Form S-1

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

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):

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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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.

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 $ and $ per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “CVRR.”

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

See “Risk Factors” on page 22 to read about factors you should consider before buying our common units. These risks include the following:

The underwriters expect to deliver the common units to purchasers on or about , 2012.

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.

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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 , 2012 (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.

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.

Index to Financial Statements

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 $ 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 Appendix 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 six months ended June 30, 2012, we purchased approximately two-thirds of our crude oil at a discount to the price of WTI.

Our refineries’ complexity allows us to optimize the yields (the percentage of refined product that is produced from crude oil and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery’s ability to process lower quality crude oil 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 90% for the year ended December 31, 2011 to approximately 95% during the six months ended

Index to Financial Statements

June 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 (with shipper status for an additional 8,000 bpd on the Spearhead pipeline) 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 ever-increasing mid-continent domestic and Canadian crude oil production, decreasing North Sea production, 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.

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 six months ended June 30, 2012.


	Average Differential ($ per barrel)
	Year Ended December 31, 2011			Six Months Ended June 30, 2012
WTI—Brent(1)	$	(16.84	)	$	(16.45	)
WTI—Mars(1)		(12.58	)		(11.66	)
WCS—WTI(1)		(16.54	)		(23.79	)
WTS—WTI(1)		(2.06	)		(4.48	)
WTI at Midland—WTI(1)(2)		(0.52	)		(3.74	)

(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 7% 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.

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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 $726.2 million, net income of $222.2 million and Adjusted EBITDA of $531.7 million for the six months ended June 30, 2012. We generated refining margin adjusted for FIFO impacts of $799.6 million and $1,091.2 million, net income of $480.3 million and $456.2 million, and Adjusted EBITDA of $577.3 million and $811.9 million, for the year ended December 31, 2011 and twelve months ended June 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 (each as defined below) we would have generated $ million and $ million of refining margin adjusted for FIFO impacts, $751.5 million and $239.6 million of net income and $ million and $ million of Adjusted EBITDA for the year ended December 31, 2011 and twelve months ended June 30, 2012, respectively. For a reconciliation of Adjusted EBITDA and refining margin adjusted for FIFO impacts to the most directly comparable GAAP measure, 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 six months ended June 30, 2012, 13.5% of the crude oil processed at our refineries was WTS, 77.0% 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. Over the five-year period ended December 31, 2011, we realized an average discount of $3.83 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.

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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. 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 second 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. We have a major turnaround scheduled for our Wynnewood refinery in the fourth quarter of 2012, the first since we acquired this refinery in 2011. We expect to spend approximately $100 million for this turnaround, which will help to ensure operational reliability. 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

Index to Financial Statements

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.

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.

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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.

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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.

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, 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

Index to Financial Statements

required in our refinery operations. For the year ended December 31, 2011 and for the six months ended June 30, 2012 we obtained approximately 65% and 62%, 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. 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 $ million of available liquidity, comprised of $ million of cash on hand, $ million available for borrowing under our $400 million asset-backed revolving credit facility (net of $ million of outstanding letters of credit) and $ million available for borrowing under our $150 million senior unsecured revolving credit facility with Coffeyville Resources.

Industry Overview

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.

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 June 2012, up 31% over June 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.

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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 % 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.

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 . 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.

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.

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The Transactions

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

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Coffeyville Resources has formed CVR Refining Holdings;

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CVR Refining Holdings has formed CVR Refining GP;

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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;

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

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CVR Refining, LLC and Coffeyville Finance Inc. expect to issue $500 million of senior notes, which we refer to as the “New Notes,” and will use the proceeds therefrom to repurchase the 9.0% Senior Secured Notes due 2015 issued by Coffeyville Resources, which we refer to as the “First Lien Notes”;

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CVR Refining Holdings will contribute its 100% membership interest in CVR Refining, LLC to us and Coffeyville Resources, on behalf of CVR Refining Holdings, will 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 less any amount paid to fund the turnaround of our Wynnewood refinery in the fourth quarter of 2012;

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Prior to the closing of this offering, we will enter into a new credit facility to replace Coffeyville Resources’ $400 million asset-based revolving credit facility (the “ABL credit facility”);

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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”);

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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;

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On the closing date of this offering, we will issue and sell common units to the public in this offering and pay related underwriting discounts and commissions, structuring fees and all related unpaid transaction costs in connection with this offering; and

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We will use the net proceeds from the sale of 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 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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THE OFFERING

Issuer

CVR Refining, LP

Common units offered

common units.

Option to purchase additional common units

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

Units outstanding after this offering

common units.

Use of proceeds

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

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$ million to repurchase the 10.875% of senior secured notes due 2017 issued by Coffeyville Resources;

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

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$ million to fund the turnaround expenses of our Wynnewood refinery in the fourth quarter of 2012; and

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$ million for general purposes.

Cash distributions

Within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2012, 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 December 31, 2012.

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 cash flow from operations for the quarter, less cash needed for maintenance and certain environmental capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for expenses associated with our major scheduled turnarounds.

Index to Financial Statements

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. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.

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 operating cash flow 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) cash flows 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 September 30, 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 September 30, 2013 will be approximately $ million, or $ 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, cash flows, 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, cash flows 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.”

Index to Financial Statements

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 June 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 June 30, 2012, would have been $ million (or $ per common unit) and $ million (or $ 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 66²/₃% 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 % of our common units (or % 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. Please read “The Partnership Agreement—Voting Rights.”

Limited call right

If at any time our general partner and its affiliates (including CVR Energy) own more than 80% 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. See “The Partnership Agreement—Call Right.”

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 , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately % of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year

Index to Financial Statements

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, Inc. (“CVR Energy”). Prior to the closing of this offering, Coffeyville Resources, LLC (“Coffeyville Resources”), an indirect wholly-owned subsidiary of CVR Energy, will form CVR Refining Holdings, LLC, which will form CVR Refining, LLC. Coffeyville Resources will contribute 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. CVR Refining Holdings will contribute its 100% membership interest in CVR Refining, LLC to us. Coffeyville Resources will retain its other assets, including an approximate 70% limited partner interest in CVR Partners, LP and a 100% membership interest in CVR GP, LLC. The following table also presents summary 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 six months ended June 30, 2011 and 2012 and the summary combined financial data presented below under the caption Balance Sheet Data as of June 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). 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 six months ended June 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 June 30, 2012 assumes the events listed above occurred as of June 30, 2012. The unaudited pro forma combined statement of operations data for the year ended December 31, 2011 and the six months ended June 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

Index to Financial Statements

“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 combined historical 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.

Index to Financial Statements


																CVR Refining, LP Combined Pro Forma
	CVR Refining, LP Historical Combined															Year Ended December 31, 2011			Six Months Ended June 30, 2012(1)
	Year Ended December 31,									Six Months Ended June 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		$	2,488.7		$	4,128.1		$	7,398.3		$	4,128.1
Costs and expenses:
Cost of product sold(2)		2,515.9			3,539.8			3,927.6			2,053.8			3,496.9			6,126.0			3,496.9
Direct operating expenses(2)		142.2			153.1			247.7			89.5			164.3			345.0			164.3
Selling, general and administrative expenses(2)		40.0			43.1			51.0			22.3			46.3			72.7			46.3
Depreciation and amortization		64.4			66.4			69.8			33.9			52.9			98.9			52.9

Operating income	$	174.0		$	103.2		$	456.7		$	289.2		$	367.7		$	755.7		$	367.7
Other income (expense), net(3)		(0.3	)		(13.8	)		(1.5	)		(1.4	)		0.8			(1.4	)		0.8
Interest expense and other financing costs		(43.8	)		(49.7	)		(53.0	)		(26.3	)		(37.8	)		(39.2	)		(20.4	)
Realized gain (loss) on derivatives, net		(27.5	)		(2.1	)		(7.2	)		(18.4	)		(27.2	)		(49.0	)		(27.2	)
Unrealized gain (loss) on derivatives, net		(37.8	)		0.6			85.3			3.2			(81.3	)		85.4			(81.3	)

Net income(3)	$	64.6		$	38.2		$	480.3		$	246.3		$	222.2		$	751.5		$	239.6

Pro forma net income per common unit, basic and diluted
Pro forma number common units outstanding, basic and diluted

Balance Sheet Data (at period end):		(unaudited)
Cash and cash equivalents(4)	$	2.7		$	2.3		$	2.7		$	1.1		$	29.4					$	340.0
Working capital		173.7			138.7			384.7			229.4			344.5						677.8
Total assets		1,104.4			1,072.8			2,262.4			1,166.4			2,133.8						2,440.0
Total debt, including current portion		479.5			469.0			729.9			466.5			727.9						552.8
Total divisional equity/partners’ capital		485.4			418.8			1,018.6			499.9			957.3						1,454.8

Cash Flow Data
Net cash flow provided by (used in):
Operating activities	$	31.9		$	167.0		$	352.7		$	192.8		$	385.5
Investing activities		(33.6	)		(21.1	)		(655.9	)		(13.2	)		(62.2	)
Financing activities(4)		3.8			(146.3	)		303.6			(180.8	)		(296.6	)

Other Financial Data
Capital expenditures for property, plant and equipment	$	34.0		$	21.2		$	68.8		$	13.3		$	62.6
Adjusted EBITDA(5)	$	147.3		$	152.6		$	577.3		$	297.1		$	531.7		$			$	531.7

Key Operating Data(1)
Crude oil throughput (bpd)(6):
Sweet		82,598			89,746			83,538			82,302			129,781
Medium		15,602			8,180			1,704			397			22,728
Heavy sour		10,026			15,439			18,460			21,416			16,006
All other feedstocks and blendstocks		12,013			10,350			5,231			6,923			8,929

Total throughput (bpd)(6)		120,239			123,715			108,933			111,038			177,444
Production (bpd)(6):
Gasoline		62,309			61,136			48,486			51,564			89,131
Distillate		46,909			50,439			45,535			45,934			72,202
Other		11,549			12,978			15,385			14,158			15,396

Total refining production (excluding internally produced fuel)		120,767			124,553			109,406			111,656			176,729
NYMEX 2-1-1 crack spread (per barrel)(7)		8.54			10.07			26.33			23.87			28.41
PADD II Group 3 2-1-1 crack spread (per barrel)(7)	$	7.93		$	10.01		$	26.77		$	24.06		$	26.05
Refining margin per crude oil throughput barrel(5)	$	10.65		$	8.84		$	21.80		$	23.08		$	20.58		$			$
Refining margin per crude oil throughput barrel adjusted for FIFO impact(5)		8.93			8.07			21.12			21.95			23.68
Direct operating expenses (excluding major scheduled turnaround expenses) per crude oil throughput barrel(2)(5)	$	3.60		$	3.67		$	4.79		$	4.52		$	4.59
Gross profit (excluding major scheduled turnaround expenses and adjusted for FIFO impact) per crude oil throughput barrel(5)	$	3.70		$	2.80		$	14.49		$	15.63		$	17.36		$			$

Index to Financial Statements

(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 $8.3 million for the six months ended June 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 June 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:


											CVR Refining, LP Combined Pro Forma
	CVR Refining, LP Historical Combined										Year Ended December 31, 2011		Six Months Ended June 30, 2012
	Year Ended December 31,						Six Months Ended June 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		1.0		0.7		1.5		0.7
Wynnewood acquisition transaction fees and integration expense		—		—		5.2		—		8.3		5.2		8.3
Major scheduled turnaround expense(c)		—		1.2		66.4		4.3		23.5		66.4		23.5
Share-based compensation(d)		2.5		11.5		8.9		7.2		10.7		8.9		10.7

(a)

For the six months ended June 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 a major scheduled turnaround at the Coffeyville refinery.

(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 $(172.4) million and $(294.2) million for the six months ended June 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 closely comparable 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)	Data published by Platts and Oil Price Information Service and represents average pricing for the periods presented.

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 it 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. 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 Combined Pro Forma
	CVR Refining, LP Historical Combined														Year Ended December 31, 2011		Six Months Ended June 30, 2012
	Year Ended December 31,									Six Months Ended June 30,
	2009			2010			2011			2011			2012
										(unaudited)					(unaudited)
	(in millions)
Net sales	$	2,936.5		$	3,905.6		$	4,752.8		$	2,488.7		$	4,128.1	$	7,398.3	$	4,128.1
Less: cost of product sold (exclusive of depreciation and amortization)		2,515.9			3,539.8			3,927.6			2,053.8			3,496.9		6,126.0		3,496.9

Refining margin		420.6			365.8			825.2			434.9			631.2		1,272.3		631.2
FIFO impacts (favorable), unfavorable		(67.9	)		(31.7	)		(25.6	)		(21.3	)		95.0				95.0

Refining margin adjusted for FIFO impact		352.7			334.1			799.6			413.6			726.2				726.2
Crude oil throughput(bpd)		108,226			113,365			103,702			104,115			168,515				168,515
Refining margin per crude oil throughput barrel	$	10.65		$	8.84		$	21.80		$	23.08		$	20.58	$		$	20.58

Refining margin per crude oil throughput barrel adjusted for FIFO impact	$	8.93		$	8.07		$	21.12		$	21.95		$	23.68	$		$	23.68

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, loss on extinguishment of debt and where applicable, 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,									Six Months Ended June 30,					Year Ended December 31,			Six Months Ended June 30,
	2009			2010			2011			2011			2012		2011			2012
										(unaudited)					(unaudited)
	(in millions)
Net income	$	64.6		$	38.2		$	480.3		$	246.3		$	222.2	$	751.5		$	239.6
Add:
Interest expense and other financing costs		43.8			49.7			53.0			26.3			37.8		39.2			20.4
Depreciation and amortization		64.4			66.4			69.8			33.9			52.9		98.9			52.9

EBITDA	$	172.8		$	154.3		$	603.1		$	306.5		$	312.9	$	889.6		$	312.9
Add:
FIFO impacts (favorable), unfavorable(a)		(67.9	)		(31.7	)		(25.6	)		(21.3	)		95.0					95.0
Share-based compensation		2.5			11.5			8.9			7.2			10.7		8.9			10.7
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			—			8.3		5.2			8.3
Major scheduled turnaround expenses		—			1.2			66.4			4.3			23.5		66.4			23.5
Unrealized (gain) loss on derivatives, net		37.8			(0.6	)		(85.3	)		(3.2	)		81.3		(85.4	)		81.3

Adjusted EBITDA	$	147.3		$	152.6		$	577.3		$	297.1		$	531.7	$			$	531.7

Index to Financial Statements

(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 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 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,								Six Months Ended June 30,						Year Ended December 31,			Six Months Ended June 30,
	2009		2010			2011			2011			2012			2011			2012
												(unaudited)			(unaudited)
	(in millions)
Direct operating expenses	$	142.2	$	153.1		$	247.7		$	89.5		$	164.3		$	345.0		$	164.3
Less: Major scheduled turnaround expense		—		(1.2	)		(66.4	)		(4.3	)		(23.5	)		(66.4	)		(23.5	)

Direct operating expenses excluding major scheduled turnaround expenses		142.2		151.9			181.3			85.2			140.8			278.6			140.8
Crude oil throughput(bpd)		108,226		113,365			103,702			104,115			168,515						168,515
Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel	$	3.60	$	3.67		$	4.79		$	4.52		$	4.59		$			$	4.59

Index to Financial Statements

Gross Profit (Excluding Major Scheduled Turnaround Expenses and adjusted for FIFO impact) 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,									Six Months Ended June 30,					Year Ended December 31,		Six Months Ended June 30,
	2009			2010			2011			2011			2012		2011		2012
													(unaudited)		(unaudited)
	(in millions)
Net sales	$	2,936.5		$	3,905.6		$	4,752.8		$	2,488.7		$	4,128.1	$	7,398.3	$	4,128.1
Cost of product sold		2,515.9			3,539.8			3,927.6			2,053.8			3,496.9		6,126.0		3,496.9
Direct operating expenses	$	142.2		$	153.1		$	247.7		$	89.5		$	164.3		345.0		164.3
Depreciation and amortization		64.4			66.4			69.8			33.9			52.9		98.9		52.9

Gross Profit		214.0			146.3			507.7			311.5			414.0	$	828.4	$	414.0
Add:
Major Scheduled turnaround expense		—			1.2			66.4			4.3			23.5		66.4		23.5
FIFO impacts (favorable)/unfavorable		(67.9	)		(31.7	)		(25.6	)		(21.3	)		95.0				95.0

Gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impacts		146.1			115.8			548.5			294.5			532.5				532.5
Crude oil throughput(bpd)		108,226			113,365			103,702			104,115			168,515				168,515
Gross profit excluding major scheduled turnaround expenses and adjusted for FIFO impact per crude oil throughput barrel	$	3.70		$	2.80		$	14.49		$	15.63		$	17.36	$		$	17.36

Index to Financial Statements

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.

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 September 30, 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 distribution for the twelve months ending September 30, 2013 will be significantly lower than our forecasted distribution, 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:

Index to Financial Statements

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 results of operations 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 results of operations and ability to pay distributions to unitholders.

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 six months of 2012, favorable crack spreads and access to a variety of price-advantaged crude oils have resulted in higher Adjusted EBITDA and cash flows. 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’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 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. Any 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.

Index to Financial Statements

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. 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. We expect our business performance will be more volatile, and our cash flows will 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 distributions over time. The amount of our quarterly cash distributions will be directly dependent on the performance of our business, which has been historically volatile and seasonal, and which we expect will continue to be volatile and seasonal. 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. 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. 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 September 30, 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

Index to Financial Statements

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 September 30, 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 unscheduled 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 refining industry may reduce insurance capacity, 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 catastrophic event, 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 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:

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 scheduled 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, a 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. 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

Index to Financial Statements

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 is covered by separate property and business interruption insurance policies with an $800.0 million limit, with a $10.0 million deductible for physical damage and a 75-day waiting period. The policies also contain exclusions and conditions that could have a materially adverse impact on our ability to receive indemnification thereunder, as well as customary sub-limits for particular types of losses.

The energy industry generally, and the refining industry specifically, is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry participants, such as us, and their insurance carriers. The energy industry insurance market offers finite insurance capacity that could be reduced in the future, coverage could be restricted, and premiums could be substantially increased to reflect greater risks, a reduction in the supply of commercial insurance or large loss ratios caused by catastrophic events. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. For example, during 2005, Hurricanes Katrina and Rita caused significant damage to several petroleum refineries along the Gulf Coast, in addition to numerous oil and gas production facilities and pipelines in that region. As a result of large energy industry insurance claims, insurance companies that have historically participated in underwriting energy related facilities could discontinue that practice or demand significantly higher premiums or deductibles to cover these facilities. Although we currently maintain significant amounts of insurance, insurance policies are subject to annual renewal. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost or we might need to significantly increase our retained exposures.

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 purchase an additional 80,000 to 90,000 bpd of crude oil to be refined into liquid fuels. 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 these regions for any reason could have a material impact on our business. In the

Index to Financial Statements

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.

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

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

The geographic concentration of our refineries and related assets creates an exposure to the risks of the local economy 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 discussed above, 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. Changes in market conditions could have a material adverse effect on our business, financial condition and results of operations and, as a result, our ability to make distributions.

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 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 is a small refinery under the RFS and has received a two year extension to comply, which expires on January 1, 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 $20.2 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

Index to Financial Statements

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.

Our business’ financial results are seasonal and generally lower in the first and fourth quarters of the year.

Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. 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 quarters. Further, reduced agricultural work during the winter months somewhat depresses demand for diesel fuel in the winter months. In addition to the overall seasonality of our business, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the areas in which we sell our petroleum products could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and reduce our operating margins thereby affecting our ability to pay distributions to our unitholders.

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

The refining industry is highly competitive with respect to both crude oil and other feedstock supply and refined product markets. We may be unable to compete effectively with our competitors within and outside of our industry, which could result in reduced profitability. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We are not engaged in the petroleum exploration and production business and therefore we do not produce any of our crude oil or other 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.

Index to Financial Statements

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

In the future, we may incur 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 high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future 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, we expect the bank borrowing base under the new credit agreement we will enter into 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 credit facility we expect to enter into will contain a number of restrictive covenants that will impose significant operating and financial restrictions on us 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:

Index to Financial Statements

A breach of the covenants under the indentures governing our notes or under the new credit facility we expect to enter into could result in an event of default under the applicable indebtedness. Such default may allow the creditors to accelerate the related debt and may result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In the event our lenders or noteholders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness. 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.

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. The purpose of these hedging arrangements is to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term. 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, while intended to reduce the adverse effects of fluctuations in crude oil and refined product prices, 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:

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.

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.

Index to Financial Statements

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. Although we strive to identify these conditions and deficiencies during the due diligence process or shortly after acquisition, the conditions or deficiencies may not be identified or disclosed in a timely manner. To the extent that there may be cost recovery provisions in acquisitions, recovery of legitimate costs may be denied or may become the subject of litigation. The cost of these unknown or undisclosed deficiencies or conditions may be material and adversely affect our finaincial condition and ability to distribute cash to our unitholders.

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 or results of operations, and 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:

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 recent turnaround of the Coffeyville refinery and the turnaround for the Wynnewood refinery is scheduled to begin in the fourth quarter of 2012 for which we have budgeted approximately $100 million. 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.

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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 with, 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.

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 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.

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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. 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 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 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, Coffeyville Resources 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 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.

Wynnewood Refining Company, LLC (“WRC”) 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 ODEQ about doing so. Instead, WRC entered into a Consent Order (the “Wynnewood Consent Order”) with ODEQ in August 2011 addressing some, but not all of the traditional marquee issues under the EPA’s National Petroleum Refining Initiative and addressing certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC agreed to pay a civil penalty, install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. The remaining costs of complying with the Wynnewood Consent Order past 2012, other than costs associated with a scheduled turnaround, are not expected to be material.

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A number of factors could affect our ability to meet the requirements imposed by either the Second Consent Decree or the Wynnewood Consent Order and could have a material adverse effect on our results of operations, financial condition and ability to pay distributions to our unitholders.

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 RCRA administrative orders 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 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 could cause a significant increase in greenhouse gas emissions and 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 the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under

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which it agreed to promulgate New Source Performance Standards (“NSPS”) to regulate greenhouse gas emissions from 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 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 the federal Occupational Safety and Health Act (“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.

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.

Index to Financial Statements

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 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.

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 one or several of these significant customers, or a significant reduction in purchase volume by any 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.

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.

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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, acquisitions and expansions involve numerous risks and uncertainties, including 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 need to obtain regulatory or other governmental approvals that may be necessary to complete acquisitions and expansions. 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:

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

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

We are a holding company, and our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of distributions 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 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.

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. We can provide no assurance that CVR Energy will 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 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.

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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 June 30, 2012, approximately 54% of the employees at the Coffeyville refinery and 64% 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.

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 December 31, 2012. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

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.”

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 in our best interests, 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.

Index to Financial Statements

Our partnership agreement limits the liability and reduces 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 reduces 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 reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:

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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.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, 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.”

Index to Financial Statements

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

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.

Our public unitholders will not have sufficient voting power to remove our general partner without CVR Energy’s consent.

Following the closing of this offering, CVR Energy will indirectly own approximately % of our common units (or approximately % 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.

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.”

Unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the

Index to Financial Statements

distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may 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 under the reasonable belief 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. Please read “The Partnership Agreement—Limited Liability.”

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 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:

Index to Financial Statements

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 $ 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:

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 common units outstanding following this offering. common units are being sold to the public in this offering (or common units if the underwriters exercise their option to purchase additional common units in full) and common units will be owned by CVR Refining Holdings following this offering (or common units if the underwriters exercise their option to purchase additional common units in full). 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.

Index to Financial Statements

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 CVR Refining Holdings pursuant to which we may be required to register the sale of the common units it holds under the Securities Act and applicable state securities laws.

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.

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:

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

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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, and under current rules will be required to comply with Section 404 in our annual report for the year ended 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 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.

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 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.

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

Index to Financial Statements

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 taxation as an entity.

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. Currently, 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.

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.

Index to Financial Statements

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.

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

Index to Financial Statements

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.

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.

Index to Financial 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 September 30, 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.

These 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:

Index to Financial Statements

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.

Index to Financial Statements

Based on an assumed initial offering price of $ per common unit, we expect to receive net proceeds of approximately $ million from the sale of 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, together with cash contributed by Coffeyville Resources, in the following manner:

Pursuant to the Contribution Agreement, Coffeyville Resources, on behalf of CVR Refining Holdings, will 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 less any amount paid to fund the turnaround of our Wynnewood refinery in the fourth quarter of 2012.

Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ 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 $ million based on an assumed initial offering price of $ 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 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.”

Index to Financial Statements

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

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.”

Index to Financial Statements

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 June 30, 2012, excluding the net proceeds of this offering, was approximately $ million, or approximately $ 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 common units in this offering at an initial public offering price of $ 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 June 30, 2012 would have been approximately $ million, or $ per unit. This represents an immediate increase in combined net tangible book value of $ per unit to our existing unitholders and an immediate combined pro forma dilution of $ per unit to purchasers of common units in this offering. The following table illustrates this dilution on a per unit basis:

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):

Index to Financial Statements

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.

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 December 31, 2012. 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 cash flow from operations for the quarter, less cash needed for maintenance and certain environmental capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for expenses associated with our major scheduled turnarounds. 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. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.

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 cash flow from operations, 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 cash flow 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:

Index to Financial Statements

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 September 30, 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 expansion 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 quarter ending December 31, 2012.

Index to Financial Statements

We believe that we would have generated pro forma combined available cash during the year ended December 31, 2011 and the twelve months ended June 30, 2012 of $ million and $ 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 $ for the year ended December 31, 2011 and $ for the twelve months ended June 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.

Index to Financial Statements

The following table illustrates, on a pro forma combined basis for the year ended December 31, 2011, and for the twelve months ended June 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:

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

Index to Financial Statements

During the twelve months ending September 30, 2013, we estimate that we will generate $ 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 September 30, 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 September 30, 2013” to present our expectations regarding our ability to generate $ million of available cash for the twelve months ending September 30, 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 to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending September 30, 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 September 30, 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.

Index to Financial Statements

The following table illustrates the amount of cash that we estimate that we will generate for the twelve months ending September 30, 2013 that would be available for distribution to our unitholders. All of the amounts for the twelve months ending September 30, 2013 in the table below are estimates. All of the amounts for the twelve months ending September 30, 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.

Index to Financial Statements

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

Index to Financial Statements

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

Within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2012, 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.

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.”

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.

Index to Financial Statements

The Partnership was formed in September 2012 and does not have historical financial statements. Therefore, in this prospectus we present the combined historical financial and operating results of the petroleum refining and related logistics business of CVR Energy. Prior to the closing of this offering, Coffeyville Resources, an indirect wholly-owned subsidiary of CVR Energy, will form CVR Refining Holdings, LLC, which will form CVR Refining, LLC. Coffeyville Resources will contribute 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. CVR Refining Holdings will contribute its 100% membership interest in CVR Refining, LLC to us. Coffeyville Resources will retain its other assets, including an approximate 70% limited partner interest in CVR Partners, LP and a 100% membership interest in CVR GP, LLC. 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 six months ended June 30, 2011 and 2012 and the selected combined financial data presented below under the caption Balance Sheet Data as of June 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), which owns 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, 2010 and 2009 are included elsewhere in this prospectus.

The unaudited pro forma combined balance sheet as of June 30, 2012 assumes the events listed above occurred as of June 30, 2012. The unaudited pro forma combined statements of operations data for the year ended December 31, 2011 and the six months ended June 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.

Index to Financial Statements

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.

Index to Financial Statements

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 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 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.

Index to Financial Statements

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:

Index to Financial Statements

Gross Profit (Excluding Major Scheduled Turnaround Expenses and adjusted for FIFO impact) 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:

Index to Financial Statements

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 of the refining and logistics operating subsidiaries of our sponsor, CVR Energy, which subsidiaries will be contributed to us in connection with this offering. 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.

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 Energy, LP’s (“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. 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 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

Index to Financial Statements

oils. The access to a variety of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for the second quarter of 2012 was $2.06 per barrel compared to $5.04 per barrel in the second quarter of 2011.

On April 18, 2012, CVR Energy entered into a Transaction Agreement (the “Transaction Agreement”) with certain affiliates of Icahn Enterprises, L.P. (“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 June 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 appraised value of the shares at the time of vesting. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.

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) an 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.”

Index to Financial Statements

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 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.

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.

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 six months ended June 30, 2012, our results included net sales of approximately $1,607.8 million and net income of $160.7 million related to WEC. Future periods’ results of operations will include full periods of WEC’s financial results.

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 (“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 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

Index to Financial Statements

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. We expect to replace the ABL credit facility with a new credit facility in connection with the closing of this offering.

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’ 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.

We expect that CVR Refining, LLC and Coffeyville Finance Inc., as issuers, will undertake an offering of senior notes prior to the closing of this offering. We expect that the offering will be for $500.0 million aggregate principal amount of senior notes, and the net proceeds from the sale of the senior notes will be used to redeem the First Lien Notes. We expect that the new senior notes will be sold in offerings exempt from registration under the Securities Act and will be offered only 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.

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 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.

Index to 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.

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.

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

Index to Financial Statements

(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 appraised value of the shares at the time of vesting. 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 six months ended June 30, 2012 and 2011, we were allocated compensation expense of $10.7 million and $1.5 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 $3.4 million, respectively, as a result of the phantom and certain override unit share-based compensation awards issued in connection with CVR Energy’s IPO. 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 six months ended June 30, 2011, we were allocated $1.4 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.

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 Sheets with changes in fair value currently recognized in our Combined Statement of Operations. At June 30, 2012, there were open commodity hedging instruments consisting of 13.5 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.

Index to Financial Statements

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 $21.0 million and $4.3 million for the six months ended June 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 is scheduled to begin turnaround maintenance in the fourth quarter of 2012. We expect to incur approximately $100.0 million of expenses during 2012 related to the Wynnewood refinery’s turnaround. The Wynnewood refinery incurred $2.5 million of turnaround costs in the six months ended June 30, 2012. It is anticipated that the downtime associated with the Wynnewood refinery turnaround will be approximately 40 to 45 days and will significantly impact our results of operations for the fourth quarter of 2012.

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.

The period to period comparisons of our results of operations have been prepared using the historical periods included in our combined financial statements. This “Results of Operations” section compares the six months ended June 30, 2012 with the sixth months ended June 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.

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, 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.

Index to Financial Statements

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 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 basis.

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

Index to Financial Statements

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 six months ended June 30, 2012, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $3.9 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. The next turnaround for the Wynnewood refinery is scheduled for the fourth quarter of 2012.

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.

CVR Refining, LP’s business includes the operations of both the Coffeyville and Wynnewood refineries, each of which will be contributed to us in connection with this offering. 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.

Index to Financial Statements

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

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

Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). 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:

Index to Financial Statements

Net Sales. Net sales were $4,128.1 million for the six months ended June 30, 2012 compared to $2,488.7 million for the six months ended June 30, 2011. The increase of $1,639.4 million was primarily the result of higher overall sales volume. The higher sales volume is due to the inclusion of a full six month’s sales for our Wynnewood refinery for the six months ended June 30, 2012. Our average sales price per gallon for the six months ended June 30, 2012 was $2.88 for gasoline and $3.03 for distillate as compared to the six months ended June 30, 2011 average sales prices of $2.86 for gasoline and $3.03 for distillates.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil and feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $3,496.9 million for the six months ended June 30, 2012 compared to $2,053.8 million for the six months ended June 30, 2011. The increase of $1,443.1 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 quarter’s consumption at our Wynnewood refinery. Our average cost per barrel of crude oil consumed for the six months ended June 30, 2012 was $95.62 compared to $93.89 for the comparable period of 2011, an increase of approximately 1.8%. Sales volume of refined fuels increased by approximately 67.4%. 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

Index to Financial Statements

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 six months ended June 30, 2012, we had an unfavorable FIFO inventory impact of $95.0 million compared to a favorable FIFO inventory impact of $21.3 million for the comparable period of 2011.

Refining margin per barrel of crude oil throughput decreased from $23.08 for the six months ended June 30, 2011 to $20.58 for the six months ended June 30, 2012. Refining margin adjusted for FIFO impact was $23.68 per crude oil throughput barrel for the six months ended June 30, 2012, as compared to $21.95 per crude oil throughput barrel for the six months ended June 30, 2011. Gross profit per barrel decreased to $13.50 for the six months ended June 30, 2012 as compared to gross profit per barrel of $16.53 in the equivalent period in 2011. The decrease of our refining margin per barrel is due to an increase in our cost of consumed crude oil. Consumed crude oil costs increased 1.8% from $93.89 per crude oil barrel throughput for the six months ended June 30, 2011 to $95.62 per crude oil barrel throughput for the six months ended June 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 $164.3 million for the six months ended June 30, 2012 compared to $89.5 million for the six months ended June 30, 2011. The increase of $74.8 million was primarily the result of six months of expenses for our Wynnewood refinery ($55.9 million), and increases at our Coffeyville refinery of expenses primarily related with turnaround maintenance ($16.7 million), labor expense ($2.3 million), outside services ($1.2 million), catalyst and chemicals ($1.1 million), insurance ($0.9 million), operating supplies ($0.9 million) and other direct operating expenses ($0.3 million), partially offset by a decrease in repairs and maintenance ($4.5 million) at our Coffeyville refinery. Our Coffeyville refinery completed the second phase of its scheduled turnaround in March of 2012. Direct operating expenses per barrel of crude oil throughput for the six months ended June 30, 2012 increased to $5.36 per barrel as compared to $4.75 per barrel for the six months ended June 30, 2011.

Operating income. Operating income was $367.7 million for the six months ended June 30, 2012, as compared to $289.2 million for the six months ended June 30, 2011. This increase of $78.5 million was primarily the result of an increase in the refining margin ($196.3 million). The increase in refining margin was partially offset by an increase in direct operating expenses ($74.8 million), depreciation and amortization ($19.0 million) and selling, general and administrative expenses ($24.0 million)

Interest Expense. Interest expense for the six months ended June 30, 2012 was $37.8 million as compared to interest expense of $26.4 million for the six months ended June 30, 2011. This $11.4 million increase resulted primarily from higher interest cost due to the additional $200.0 million of Notes issued 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 six months ended June 30, 2012, we recorded a $27.1 million realized loss on derivatives compared to an $18.4 million realized loss on derivatives for the six months ended June 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.

Index to Financial Statements

Unrealized Gain (Loss) on Derivatives, net. For the six months ended June 30, 2012, we recorded a $81.3 million unrealized loss on derivatives compared to a $3.2 million unrealized gain on derivatives for the six months ended June 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 six months ended June 30, 2012 was $222.2 million as compared to net income of $246.3 million for the six months ended June 30, 2011, a decrease of $24.1 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.

Cost of Products Sold (Exclusive of Depreciation and Amortization). Costs of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, and transportation and distribution costs. Cost of products 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 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.

Index to Financial Statements

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 products 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).

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.

Index to Financial Statements

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 for the year ended December 31, 2010, an increase of $442.1 million.

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.

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

Index to Financial Statements

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 $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

Index to Financial Statements

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, 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.

We expect that our future principal uses of cash will be for working capital, capital expenditures, funding 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

Index to Financial Statements

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 a new credit facility that we expect to enter into to replace Coffeyville Resources’ 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 December 31, 2012. 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.

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.

Net cash provided by operating activities for the six months ended June 30, 2012 was $385.5 million. The positive cash flow from operating activities generated over this period was primarily attributable to operating income of $367.7 million which was the result of higher operating margins. This positive operating income was coupled with a favorable change in trade working capital which resulted in a net cash inflow of $17.5 million. The trade working capital inflow was the result of a decrease in inventories of $121.3 million, offset by a $35.7 million increase in accounts receivable and a $68.1 million decrease in accounts payable.

Net cash provided by operating activities for the six months ended June 30, 2011 was $192.8 million. The positive cash flow from operating activities was primarily attributable to operating income of $289.2 million, offset by unfavorable changes in trade working capital and other working capital. Trade working capital for the six months ended June 30, 2011 resulted in a reduction of cash flows of $76.5 million which was attributable to an increase in inventories of $66.8 million and an increase in accounts receivable of $18.4 million, offset by an

Index to Financial Statements

increase of $8.7 million in accounts payable. Other working capital activities during the period resulted in a reduction of cash flows of $21.8 million which was primarily attributable to an increase in prepaid expenses and other assets of $15.8 million and an increase in the insurance receivable of $6.1 million, offset by an increase in other current liabilities of $2.2 million and an increase in other long-term liabilities of $1.4 million.

Net cash used in investing activities for the six months ended June 30, 2012 was approximately $62.2 million compared to $13.2 million for the six months ended June 30, 2011. The increase in investing activities was primarily the result of an increase in capital expenditures of approximately $49.3 million primarily due to projects at the Coffeyville refinery, construction of crude oil storage in Cushing, Oklahoma and capital spend incurred for the Wynnewood refinery.

Net cash used in financing activities for the six months ended June 30, 2012 was approximately $296.6 million compared to $180.8 million for the six months ended June 30, 2011. CRLLC has historically provided cash as necessary to support our operations and has retained excess cash earned by our operations. Cash received or paid by CRLLC 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 six months ended June 30, 2012, the use of cash for financing activities was primarily driven by $294.2 million in net distributions to CRLLC. Additionally, finance 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 six months ended June 30, 2011, the use of cash for financing activities was primarily driven by $172.4 million in net distributions to CRLLC. Additional uses of cash for the six months ended June 30, 2011 included finance costs of approximately $5.7 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 six months ended June 30, 2012, there were no borrowings or repayments under our ABL credit facility. As of June 30, 2012, there were no short-term borrowings outstanding under our ABL credit facility.

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.

Index to Financial Statements

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).

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.

Net cash used in 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 Notes. Additionally, we repurchased $2.7 million of the Notes in accordance with the terms of a tender offer.

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.

Expected Senior Notes. We expect that CVR Refining, LLC and Coffeyville Finance Inc., which will be our wholly owned subsidiaries following this offering, as issuers, will undertake a non-public offering of the New Notes prior to the closing of this offering. We expect that the non-public offering will be for $500.0 million

Index to Financial Statements

aggregate principal amount of New Notes. We expect that the New Notes will be sold in offerings exempt from registration under the Securities Act and will be offered only 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.

We expect that the senior notes will be issued under a trust indenture that will contain negative covenants which in general will restrict our and our subsidiaries’ ability to engage in certain activities, including without limitation:

If an event of default exists under the indenture we expect to enter into, the holders of the expected senior unsecured notes may, as is customary, declare the entire principal of all senior notes and interest accrued thereon to be due and payable immediately.

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 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 June 30, 2012, the Notes had an aggregate principal balance of $669.8 million and a net carrying value of $675.2 million.

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 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.

Index to Financial Statements

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. We expect to redeem the First Lien Notes with proceeds from the expected issuance of the New Notes (as described above).

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

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.

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.

Index to Financial Statements

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 June 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.

Asset-Backed Credit Facility. Coffeyville Resources entered into its ABL credit facility on February 22, 2011, which was expanded to a $400.0 million ABL credit facility on December 15, 2011 in connection with the Wynnewood Acquisition. We expect to replace the ABL credit facility in connection with the closing of this offering with a new credit facility. The ABL credit facility provides for borrowings, letter of credit issuances and a feature that permits an increase of borrowings up to an additional $100.0 million (in the aggregate) subject to additional lender commitments. The ABL credit facility is scheduled to mature in August 2015 and the ABL credit facility, or a replacement credit facility, will be used to finance our ongoing working capital, capital expenditures, letter of credit issuances and general needs and includes, among other things, a letter of credit sublimit equal to 90% of the total commitment. As the facility is maintained for the benefit of our operations, costs and any borrowings under the facility have been allocated to CVR Refining. As of June 30, 2012, Coffeyville Resources had availability under the ABL credit facility of $347.0 million and had letters of credit outstanding of approximately $53.0 million. There were no borrowings outstanding under the ABL credit facility as of June 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.

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 contains 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 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. Coffeyville Resources was in compliance with the covenants of the ABL credit facility as of June 30, 2012.

In connection with the change in control described above, CVR Energy, 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 the acquisition of Shares by affiliates of Icahn Enterprises from the definition

Index to Financial Statements

of change of control as provided in the ABL Credit Agreement, dated as of February 22, 2011, by and among the parties thereto (the “ABL Credit Agreement”). 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 Agreement.

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:

We expect to spend approximately $170.0 million to $175.0 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 $59.0 million of maintenance capital. Approximately $80.0 million to $85.0 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.

Index to Financial Statements

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 $21.0 million in connection with the turnaround in 2012. The Wynnewood refinery is scheduled to begin turnaround maintenance in the fourth quarter of 2012. We expect to incur approximately $100.0 million of expenses during 2012 related to the Wynnewood refinery.

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.

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 June 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 June 30, 2012 and thereafter. As of June 30, 2012, there were no amounts outstanding under the ABL credit facility. The following table assumes no borrowings are made under the ABL credit facility.

Index to Financial Statements

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 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.

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.

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.

Index to Financial Statements

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 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 Coffeyville Resources 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 combined financial statements therefore include certain expenses incurred by its parent which may include, but are not necessarily limited to, the following:

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 18 to our audited historical combined financial statements as of and for the years ended December 31, 2009, 2010 and 2011 (“Related Party Transactions”) 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.

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. Although management considers these derivatives economic hedges, our other 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.

Index to Financial Statements

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.

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. CVR Refining 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.

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.

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.

Index to Financial Statements

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 the 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:

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

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.

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.

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 we may deem appropriate) 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.

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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 June 30, 2012, we had over-the-counter commodity swaps consisting of 13.5 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 June 30, 2012 was a net unrealized gain of $0.9 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 $13.5 million.

Index to Financial Statements

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.

Index to Financial Statements

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:

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

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):

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

Index to Financial Statements

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 June 2012, up 31% over June 2010 volumes.

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.

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

Index to Financial Statements

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, 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.

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 six months ended June 30, 2012.

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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 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 WTI. In the six months ended June 30, 2012, we purchased approximately two-thirds of our crude oil at a discount to the price of WTI.

Our refineries’ complexity allows us to optimize the yields (the percentage of refined product that is produced from crude oil and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery’s ability to process lower quality crude oil 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 90% for the year ended December 31, 2011 to approximately 95% during the six months ended June 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.

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 ever-increasing mid-continent domestic and Canadian crude oil production, decreasing North Sea production, 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.

Index to Financial Statements

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 7% 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.

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

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. 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. 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.

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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 second quarter of 2012. In early 2012, we successfully and safely completed the second phase of our turnaround 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. We have a major turnaround scheduled for our Wynnewood refinery in the fourth quarter of 2012, the first since we acquired this refinery in 2011. We expect to spend approximately $100 million for this turnaround, which will help to ensure operational reliability. The next turnarounds of our Coffeyville and Wynnewood refineries are scheduled to begin in late-2015 and 2016, respectively.

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

Index to Financial Statements

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.

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, 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 six months ended June 30, 2012 we obtained approximately 65% and 62%, 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. 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 $ million of available liquidity, comprised of $ million of cash on hand, $ million available for borrowing under our $400 million asset-backed revolving credit facility (net of $ million of outstanding letters of credit) and $ million available for borrowing under our $150 million senior unsecured revolving credit facility with Coffeyville Resources.

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

Index to Financial Statements

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. 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.

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 June 30, 2012 was 71,189,718 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 will contribute its wholly-owned subsidiaries and logistics assets described above in “—Overview” to CVR Refining, LLC, and CVR Refining Holdings, a subsidiary of Coffeyville Resources, will contribute CVR Refining, LLC to us. Following the Transactions, CVR Refining Holdings will own common units as well as CVR Refining GP, our general partner.

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.

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).

Index to Financial Statements

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 the Broome Station via the Plains pipeline. From the Broome Station, 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.

Index to Financial Statements

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.

Index to Financial Statements

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 six months ended June 30, 2012, our Coffeyville refinery processed approximately 104,864 bpd of crude oil and 5,934 bpd of feedstocks and blendstocks. These reduced throughput rates for the first six 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:

Index to Financial Statements

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.

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 six months ended June 30, 2012, our Wynnewood refinery processed approximately 63,651 bpd and 2,995 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.

Index to Financial Statements

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.

Index to Financial Statements

We focus our Coffeyville petroleum product marketing efforts in the central mid-continent and Rocky Mountain areas because of their relative proximity to the refinery and their pipeline access. 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 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.

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.

Index to Financial Statements

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.

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:

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 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.

Index to Financial Statements

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.

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 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.

Index to Financial Statements

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.

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 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 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.

Index to Financial Statements

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.

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.

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 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. 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 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 $45 million for CRRM and $49 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

Index to Financial Statements

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.

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 emissions from petroleum refineries. The EPA may propose the NSPS in 2012. 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.

Index to Financial Statements

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.

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 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:

Index to Financial Statements

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.

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.

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.

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

Index to Financial Statements

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.

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.

As of June 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 June 30, 2012, the Coffeyville refinery employed approximately 540 of our employees, about 54% 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

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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 June 30, 2012, the Wynnewood refinery employed approximately 270 people, about 64% 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.

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. CVR Energy provides us with the following services under the agreement, among others:

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

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.”

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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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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 New York Stock Exchange’s corporate governance requirements, including:

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 seven 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. 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. 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 in the best interests 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 in our best interests, approved by 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.

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

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, (90%), Wyatt E. Jernigan (90%), and Christopher G. Swanberg (60%).

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. Mr. Lipinski has also 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

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of CVR Partners since June 2011 and, prior to assuming such role, served as Chief Executive Officer, President and a director of CVR Partner’s general partner beginning in October 2007 and as Chairman of the board of directors of CVR Partner’s 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 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.

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.

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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.

Vincent 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, and since October 2011,

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Mr. Intrieri has served as Senior Vice President of Icahn Enterprises G.P. Inc., the general partner of Icahn Enterprises L.P. Icahn Enterprises L.P. is a Nasdaq-listed diversified holding company engaged in a variety of businesses, including investments, automotive, energy, railcar, food packaging, metals, real estate, gaming and home fashion. Mr. Intrieri was a director of Icahn Enterprises G.P. Inc. from 2006 through September 2012. In addition, since 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 served as a director of Chesapeake Energy Corporation, an oil and gas exploration and production company, since June 2012. Mr. Intrieri has served as a director of CVR Energy, Inc., an independent petroleum refiner and marketer of high value transportation fuels, since May 2012. Mr. Intrieri has also served on the board of directors of Federal-Mogul Corporation, a supplier of automotive products, since December 2007. Mr. Intrieri served on the board of directors 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.

From December 2007 through April 2012, Mr. Intrieri was chairman of the board and a director of PSC Metals, Inc., a privately held processor of ferrous and non-ferrous scrap metals. From January 2011 until March 2012, Mr. Intrieri was a director of Motorola Solutions, Inc., a provider of communication products and services. From November 2006 to November 2008, Mr. Intrieri served on the board of directors of Lear Corporation, a global supplier of automotive seating and electrical power management systems and components. From August 2008 through September 2009, Mr. Intrieri was a director of WCI Communities, Inc., a homebuilding company.

From November 2005 to March 2011, Mr. Intrieri was a director of WestPoint International, Inc., a manufacturer and distributor of home fashion consumer products. From December 2006 to June 2011, he was 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 April 2005 through September 2008, Mr. Intrieri served as the President and Chief Executive Officer of Philip Services Corporation, an industrial services company. Mr. Intrieri served on the board of directors of XO Holdings, LLC, a telecommunications company, from February 2006 until August 2011. Mr. Intrieri served on the board of directors of American Railcar Industries, Inc., a company that is primarily engaged in the business of manufacturing covered hopper and tank railcars, from August 2005 until March 2011, and from March 2005 to December 2005, Mr. Intrieri was a Senior Vice President, the Treasurer and the Secretary of American Railcar Industries. From April 2003 to March 2011, Mr. Intrieri was the Chairman of the Board of directors and a director of Viskase Companies, Inc., a producer of cellulosic and plastic casings used in preparing and packaging processed meat products.

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

Samuel Merksamer has served as a director on the Board since our inception in September 2012. Mr. Merksamer has served as an investment analyst at Icahn Capital LP, a subsidiary of Icahn Enterprises L.P., since May 2008. Mr. Merksamer is responsible for identifying, analyzing and monitoring investment opportunities and portfolio companies for Icahn Capital. Mr. Merksamer serves as a director of Viskase Companies, Inc., American Railcar Industries Inc., PSC Metals Inc., Federal-Mogul Corporation and CVR Energy. Mr. Merksamer served on the board of directors of Dynegy Inc. from March 2011 through September 2012. Viskase Companies, PSC Metals, American Railcar Industries Inc., Federal-Mogul and CVR Energy are each, directly or indirectly, controlled by Carl C. Icahn. Mr. Icahn also has an interest in Dynegy Inc. through the

Index to Financial Statements

ownership of securities. 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 received an A.B. in Economics from Cornell University in 2002. 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, qualify him to serve as a member of the board of directors of our general partner.

We were formed in September 2012. We are a new subsidiary formed to hold the petroleum refining and logistics operating subsidiaries which previously comprised a portion of the assets of CVR Energy. As such, our general partner did not 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, or for any periods prior to our formation date. Accordingly, we are not presenting any compensation for historical periods.

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, and therefore will have responsibilities for both us, our general partner and CVR Energy 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:

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 and CVR Partners.”

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 (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

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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:

Messrs. Lipinski, Riemann, Gross and Haugen were also considered to be named executive officers of CVR Energy for the 2011 year, and detailed information about the compensation that was provided to these individuals by CVR Energy for the 2011 year can be found under the headings “Compensation Discussion and Analysis” and “Compensation of Executive Officers” in the most recent CVR Energy proxy statement.

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. 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.

The LTIP will provide 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”).

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 interchangeably 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 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. In the event that the committee is not comprised of “nonemployee directors” within the meaning of Rule 16b-3 under the Exchange Act, a subcommittee of two or more

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nonemployee directors will administer all awards granted to individuals that are subject to Section 16 of the Exchange Act or the board of directors of our general partners will grant and administer those awards.

The LTIP authorizes a pool of 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.

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.

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.

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.

Index to Financial Statements

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 dividends 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.

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.

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.

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.

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.

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.

Index to Financial Statements

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.

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.

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).

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.

In the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, stock dividend, 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.

Index to Financial Statements

Officers, employees and directors of CVR Energy who serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Following this offering, our general partner may appoint independent directors to its board. 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.

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.

Index to Financial Statements

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

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.

Index to Financial Statements

The following table sets forth, as of September 27, 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 and all directors and executive officers of our general partner as a group.

Index to Financial Statements

After this offering, (i) CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy, will own common units, representing approximately % of our outstanding units (approximately % 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.

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.

Index to Financial Statements

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.

In connection with the closing of this offering, we will enter into a contribution, conveyance and assumption agreement with Coffeyville Resources and CVR Refining Holdings pursuant to which Coffeyville Resource will contribute CVR Refining, LLC to us and we will assume all liabilities (including unknown and contingent liabilities) associated with owning CVR Refining, LLC after its contribution to us and Coffeyville Resources, on behalf of CVR Refining Holdings, will contribute to us an amount of cash such that we will have approximately $340 million in cash on hand at the closing of this offering less any amount paid to fund the turnaround of our Wynnewood refinery in the fourth quarter of 2012.

As consideration for the contribution of CVR Refining, LLC and cash, we will (i) issue common units to CVR Refining Holdings and (ii) 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.

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—Liquidity and Capital Resources—Borrowing Activities—Intercompany Credit Facility.”

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 percent of the pet coke

Index to Financial Statements

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 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 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

Index to Financial Statements

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.

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.

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 products 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.

Index to Financial Statements

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 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

Index to Financial Statements

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.

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

Index to Financial Statements

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.

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.

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.

Index to Financial Statements

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.

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, 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.

Index to Financial Statements

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

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:

Index to Financial Statements

We will enter into a services agreement with CVR Energy concurrently with the closing of our initial public 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:

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 may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice. CVR Energy also has 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

Index to Financial Statements

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, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.

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

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.

In connection with this offering, we will enter into a registration rights agreement with CVR Refining Holdings, pursuant to which we may be required to register the sale of the common units it holds. Under the registration rights agreement, CVR Refining Holdings will have the right to request that we register the sale of common units held by it on its 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 issue common units and use the proceeds (net of underwriting discounts) to redeem an equal number of common units from CVR Refining Holdings. In addition, CVR Refining Holdings and its 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 CVR Refining Holdings and any permitted transferee will be entitled to these registration rights, except that the demand registration rights may only be transferred in whole and not in part.

Index to Financial Statements

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 in our best interests. 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 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:

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. 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 deemed to 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 interests 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.

Index to Financial Statements

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 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 reduce 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.

Index to Financial Statements

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:

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:

Our partnership agreement permits us to borrow funds to make a distribution on all outstanding units, 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, subject to certain limitations contained in our partnership agreement. In

Index to Financial Statements

addition, the current owners of our general partner may sell the general 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.”

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right (which it may assign to any of its affiliates or to us), but not the obligation, to acquire all, but not less than all, of the common units held by public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, 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 manager 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. 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 fiduciary 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.

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

Index to Financial Statements

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:

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

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

Index to Financial Statements

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.

Index to Financial Statements

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 a 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 these persons acted in bad faith. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, 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.”

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 the Partnership Agreement.

Index to Financial Statements

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.”

Duties. 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:

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.

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:

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.

Index to Financial Statements

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.

We intend to apply to list our common units on the NYSE under the symbol “CVRR.”

Index to Financial Statements

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:

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

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.

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.”

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.

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.

Index to Financial Statements

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 % 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.

Index to Financial Statements

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.

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

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 in connection with any such claims, suits, actions or proceedings.

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:

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.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their

Index to Financial Statements

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.

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’ 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.

Index to Financial Statements

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.

(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;

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 % of the outstanding common units (approximately % if the underwriters exercise their option to purchase additional common units in full).

Our general partner may generally make amendments to our partnership agreement without the approval of any other partner to reflect:

Index to Financial Statements

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:

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.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding common units in relation to other classes of units will require the approval of at least a majority of the type or class of common 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.

Index to Financial Statements

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 or our subsidiary into a new limited liability entity or merge us or our subsidiary 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.

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;

(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.

Index to Financial Statements

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:

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.

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to September 30, 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 September 30, 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 in some instances 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 classes of common 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 66²/₃% of the outstanding common 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 common units. The ownership of more than 33¹/₃% 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 approximately % of the outstanding common units (approximately % if the underwriters exercise their option to purchase additional common units in full).

Index to Financial Statements

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.

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.

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.

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.”

If at any time our general partner and its affiliates own more than 80% 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 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 % of the total outstanding common units.

Index to Financial Statements

(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.”

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:

To avoid any adverse effect on the maximum applicable rates chargeable to customers by our subsidiary, or in order to reverse an adverse determination that has occurred regarding such maximum rate, 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 our current or future subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

Index to Financial Statements

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.

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.

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:

(3) 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;

Index to Financial Statements

(4) 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;

Any indemnification under these provisions will only be out of our assets. Unless they otherwise agree, 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.

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.

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.

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.

Index to Financial Statements

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:

(2) information as to the amount of cash, and a description and statement of the agreed value of any other capital contribution, contributed or to be contributed by each partner and the date on which each became a partner;

(3) copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

(4) 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

(5) 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.

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 affect 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 CVR Refining Holdings, pursuant to which we may be required to register the sale of the common units it holds. See “Units Eligible for Future Sale.”

Index to Financial Statements

Upon the completion of this offering, there will be common units outstanding, of which will be owned by CVR Refining Holdings, assuming the underwriters do not exercise their option to purchase additional common units; if they exercise such option in full, CVR Refining Holdings will own 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.

The common units sold in this offering (or 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 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:

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 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. 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 CVR Refining Holdings. Under this agreement, CVR Refining Holdings 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 it holds, subject to certain limitations. See “Certain Relationships and Related Party Transactions—Agreements with CVR Energy and CVR Partners—Registration Rights Agreement.”

Index to Financial Statements

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 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.

Index to Financial Statements

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”).

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.

Index to Financial Statements

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 % 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; and

(iii) 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.

Index to Financial Statements

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.

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 , will be allocated, on a cumulative basis, an amount of federal taxable income that will be % or

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less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of 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;

(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 alternatiev 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. Under current law, 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 35% and 15%, respectively. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rates applicable to ordinary income and long-term capital gains of individuals will increase to 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 is scheduled to apply to 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.

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. Currently, 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.

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:

(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.

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.

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.

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;

(b) a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

(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.

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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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:

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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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, the following respective amounts of common units:

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 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 representative may change the public offering price and concession.

The following table summarizes the compensation and estimated expenses we will pay (excluding 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.):

We will pay a structuring fee equal to % of the gross proceeds of this offering, including the gross proceeds from any exercise of the underwriters’ option to purchase additional units, 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 intend to apply to list our common units 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

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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 and Citigroup Global Markets Inc. 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 and Citigroup Global Markets Inc. waive, 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.

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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.

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.

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.

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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.

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:

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.

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:

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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.

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 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).

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.

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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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.

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, have been included herein (and in the registration statement) in reliance upon the report 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 accountants, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

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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The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

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The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

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The accompanying notes are an integral part of these unaudited pro forma condensed combined financial statements.

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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 June 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 and June 30, 2012.

The unaudited pro forma condensed combined financial statements reflect the following transactions:

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.

Index to Financial Statements

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 common units. All units were assumed to have been outstanding since January 1, 2012 for the June 30, 2012 pro forma financials and January 1, 2011 for the 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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Management of the Partnership evaluated subsequent events through the date of issuance of the balance sheet.

Index to Financial Statements

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”). 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.” 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 will be a transfer of assets under common control and, accordingly, balances will be 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 Partner’s outstanding units.

Index to Financial Statements

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.

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 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.

Index to Financial Statements

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 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.

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 six months ended June 30, 2012, CVR Refining incurred approximately $8.3 million of transaction fees and integration expenses that are included in selling, general and administrative expense in the condensed combined Statements of Operations.

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.

Index to Financial Statements

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.

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.

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 six months ended June 30, 2012 and 2011 related to the Phantom Unit Plans was approximately $0 and $4.2 million, respectively.

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 June 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.

Index to Financial Statements

Through the CVR Energy LTIP, shares of restricted common stock 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 June 30, 2012, there was approximately $12.4 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 June 30, 2012, compensation expense has been allocated to CVR Refining.

Compensation expense recorded for the six months ended June 30, 2012 and 2011, related to the restricted shares, was approximately $10.7 million and $1.5 million, respectively.

Index to Financial Statements

Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2012 and 2011 totaled approximately $1.2 million and $0.2 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 June 30, 2012. Amortization of assets held under capital leases is included in depreciation expense.

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks and freight and distribution expense. For the six months ended June 30, 2012, there was $1.5 million in depreciation expense incurred related to the cost of product sold. For the six months ended June 30, 2011, there was $1.2 million 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 six months ended June 30, 2012 and 2011, direct operating expenses exclude depreciation and amortization of approximately $51.0 million and $32.6 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 $0.4 million and $0.1 million for the six months ended June 30, 2012 and 2011, respectively.

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 June 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 June 30, 2012, were approximately $3.2 million. No costs have been recorded in 2012. 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 June 30, 2012, CVR Refining has recorded an insurance receivable of approximately $0.7 million.

Index to Financial Statements

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.

Index to Financial Statements

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.

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 June 30, 2012, CRLLC had availability under the ABL credit facility of $347.0 million and had letters of credit outstanding of approximately $53.0 million. There were no borrowings outstanding under the ABL credit facility as of June 30, 2012.

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 June 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 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

Index to Financial Statements

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.

The minimum required payments for the Partnership’s operating leases and unconditional purchase obligations are as follows:

CVR Refining leases trucks, tractor trailers and facilities under long-term operating leases expiring at various dates. Lease expense for the six months ended June 30, 2012 and 2011 totaled approximately $1.5 million and $0.7 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.

Index to Financial Statements

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 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 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.

Index to Financial Statements

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.

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.

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 with DOJ to resolve DOJ’s claims. Civil penalties associated with the proceeding will exceed $100,000;

Index to Financial Statements

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 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, 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.

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.

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 June 30, 2012 and December 31, 2011, environmental accruals of approximately $1.8 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 $0.4 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

Index to Financial Statements

free rates at June 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 June 30, 2012 and December 31, 2011, respectively. The estimated future payments for these required obligations are as follows:

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 $45.0 million for CRRM and $49.0 million for WRC.

Index to Financial Statements

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.

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 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 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 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 U.S. District Court for the District of Kansas on April 19, 2012.

Index to Financial Statements

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 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 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 six months ended June 30, 2012 and 2011, capital expenditures were approximately $10.8 million and $2.3 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.

Index to Financial Statements

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:

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of June 30, 2012 and December 31, 2011.

Index to Financial Statements

As of June 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 six months ended June 30, 2012.

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 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.

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 June 30, 2012, CVR Refining had open commodity hedging instruments

Index to Financial Statements

consisting of 13.5 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 June 30, 2012 was a net asset of $0.9 million which was comprised of $5.1 million included in current liabilities, $1.2 million included in long-term liabilities, $6.9 million included in current assets and $0.3 million included in long-term assets. For the six months ended June 30, 2012, CVR Refining recognized a realized loss of $25.0 million and an unrealized loss of $79.6 million which are recorded in loss on derivatives, net in the condensed combined Statements of Operations.

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 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:

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 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.

Index to Financial Statements

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 June 30, 2012. Amounts owed to CRRM and WEC from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable, prepaid expenses and other current assets, and other long-term assets, on the condensed 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.

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 six months ended June 30, 2012 and 2011, the net sales generated from the sale of hydrogen to CRNF were approximately $0.1 million and $0.7 million, respectively. For the six months ended June 30, 2012 and 2011, CVR Refining recognized $5.7 million and $6.1 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 six months ended June 30, 2012 and 2011 were approximately $45,000 and $0.2 million, respectively, related to high pressure steam. Reimbursed and paid amounts on a gross basis basis were nominal for the six 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 reasonable manner. Direct operating expenses incurred by CRRM associated with the purchase of nitrogen for the six months ended June 30, 2012 and 2011, were approximately $0.9 million and $0.7 million, respectively. No amounts were paid by CRNF to CRRM for any of the years.

For the six months ended June 30, 2012 and 2011, CRRM recognized approximately $0.1 million and $0.1 million, respectively, of direct operating expenses from the purchase of tail gas from CRNF.

Index to Financial Statements

approximately $0.6 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 $0.0 million for the use of tank capacity for the six months ended June 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 June 30, 2012 and December 31, 2011, payables of $0.1 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 June 30, 2012 and December 31, 2011, receivables of $0.3 million and $0.3 million, respectively, were included in prepaids and other current assets on the condensed combined Balance Sheets associated amounts due from CRNF under the feedstock and shared services 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.

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.

Index to Financial Statements

For the six months ended June 30, 2012 and 2011, net sales of pet coke associated with the transfer of pet coke from CRRM to CRNF was approximately $4.8 million and $4.9 million, respectively. Receivables of $0.7 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 June 30, 2012 and December 31, 2011, respectively.

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 six months ended June 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.

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.

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.

Index to Financial Statements

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.

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 (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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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.

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.

Index to Financial Statements

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 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.

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:

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 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.

Index to Financial Statements

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 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.

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.

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.

Index to Financial Statements

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.

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.

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.

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).

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.

Index to Financial Statements

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.

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.

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.

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.

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

Index to Financial Statements

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.

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:

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.

Index to Financial Statements

CVR Refining has omitted earnings per unit because CVR Refining has operated under a divisional equity structure.

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.

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.

Index to Financial Statements

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):

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.

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.

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III.

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.

Significant assumptions used in the valuation of the Override Operating Units (a) and (b) were as follows:

Significant assumptions used in the valuation of the Override Value Units (c) and (d) were as follows:

Index to Financial Statements

(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:

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:

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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

Index to Financial Statements

$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.

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”).

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.

Index to Financial Statements

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.

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).

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.

Index to Financial Statements

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

Index to Financial Statements

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.

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.

Index to Financial Statements

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 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.

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.

Index to Financial Statements

Future payments required under capital lease at December 31, 2011 are as follows:

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.

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.

Index to Financial Statements

The minimum required payments for CVR Refining’s operating lease agreements and unconditional purchase obligations are as follows:

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

Index to Financial Statements

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

Index to Financial Statements

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.

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.

Index to Financial Statements

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.

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

Index to Financial Statements

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.

Index to Financial Statements

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:

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.

Index to Financial Statements

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 $45.0 million for CRRM and $49.0 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 2011, 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.

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

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

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 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.

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.

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.

Index to Financial Statements

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.

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.

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,

Index to Financial Statements

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.

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.

Index to Financial Statements

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.

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.

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.

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.

Index to Financial Statements

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.

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.

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.

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.

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.

Index to Financial Statements

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.

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:

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

(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.

Index to Financial Statements

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.

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.

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

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.

The valuation methods used to measure financial instruments at fair value are as follows:

Index to Financial Statements

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:

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:

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.

Index to Financial Statements

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:

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.

Index to Financial Statements

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.

Index to Financial Statements

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”) 820—Fair 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.

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

Index to Financial Statements

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.

Index to Financial Statements

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:

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.

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.

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

Index to Financial Statements

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.

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.

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.

Index to Financial Statements

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:

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:

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.

Index to Financial Statements

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:

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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.

Index to Financial Statements

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

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:

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:

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.

Index to Financial Statements

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:

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

Index to Financial Statements

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.

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.

Index to Financial Statements

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—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.

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

Index to Financial Statements

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).

Index to Financial Statements

The minimum remaining principal payments under the loan agreements and minimum lease payments under capital lease obligations are as follows:

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.

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.

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.

Index to Financial Statements

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.

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.

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.

Index to Financial Statements

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.

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

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:

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:

Index to Financial Statements

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.

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.

Index to Financial Statements

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 and Missouri. 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.

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.

Index to Financial Statements

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.

Index to Financial Statements

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.

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 the second amended and restated 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, to be filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions that will indemnify and hold harmless the director and officers of our general partner.

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. There have been no other sales of unregistered securities within the past three years.

Index to Financial Statements

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.

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.

(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.

Index to Financial Statements

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 September 28, 2012.

Each person whose signature appears below appoints John J. Lipinski, Stanley A. Riemann, Susan M. Ball and Edmund S. Gross, and each of them, any of whom may act without the joinder of the other, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

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.


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


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



Title of securities to be registered	Proposed maximum aggregate offering price(1)(2)	Amount of registration fee
Common units representing limited partner interests	$300,000,000	$34,380


	Price to Public	Underwriting Discounts and Commissions	Structuring fees	Proceeds to CVR Refining, LP
Per Common Unit	$	$	$	$
Total	$	$	$	$


PROSPECTUS SUMMARY			1
RISK FACTORS			22
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			50
USE OF PROCEEDS			52
CAPITALIZATION			53
DILUTION			54
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			55
HOW WE MAKE CASH DISTRIBUTIONS			63
SELECTED HISTORICAL AND UNAUDITED PRO FORMA COMBINED FINANCIAL AND OPERATING DATA			64
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			72
INDUSTRY			107
BUSINESS			112
MANAGEMENT			133
COMPENSATION DISCUSSION AND ANALYSIS			138
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			144
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			146
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			157
DESCRIPTION OF THE COMMON UNITS			164
THE PARTNERSHIP AGREEMENT			166
UNITS ELIGIBLE FOR FUTURE SALE			179
MATERIAL TAX CONSEQUENCES			181
INVESTMENT IN CVR REFINING, LP BY EMPLOYEE BENEFIT PLANS			195
UNDERWRITING			196
LEGAL MATTERS			201
EXPERTS			201
WHERE YOU CAN FIND MORE INFORMATION			201
INDEX TO FINANCIAL STATEMENTS			202
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


	As of June 30, 2012
	Actual		Pro Forma
	(in thousands)
Cash and cash equivalents	$	29,409	$


Debt:
Asset-based revolving credit facility(1)	$	—	$
Intercompany revolving credit facility(2)		—
9.0% senior secured notes due 2015(3)		454,427
10.875% senior secured notes due 2017		220,746
Capital lease obligations		52,756
Expected senior notes(3)		—

Total debt	$	727,929	$


Equity:
Divisional equity	$	957,288	$
Partners’ equity in CVR Refining, LP:
Common units—CVR Refining Holdings		—
Common units—public		—

Total equity	$	957,288	$

Total capitalization	$	1,685,217	$


Assumed initial public offering price per common unit		$
Combined net tangible book value per common unit before the offering(1)
Increase in net combined tangible book value per common unit attributable to purchasers in the offering
Less: Pro forma combined net tangible book value per common unit after the offering(2)

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


	Units				Total Consideration
	Number	Percent			Amount		Percent
CVR Refining Holdings(1)				%	$			%
New investors				%		(2)		%

Total			100	%	$			%


	Pro Forma Combined
	Year Ended December 31, 2011			Twelve Months Ended June 30, 2012
	($ in millions except per unit data)
Statement of Operations Data:
Net sales	$	7,398.3		$
Operating costs and expenses:
Cost of product sold		6,126.0
Direct operating expenses		345.0
Selling, general and administrative expense		72.7
Depreciation and amortization		98.9

Operating income	$	755.7		$
Other income (expense):
Interest expense and other financing costs		(39.2	)
Realized gain (loss) on derivatives, net		(49.0	)
Unrealized gain (loss) on derivatives, net		85.4
Loss on extinguishment of debt		(2.1	)
Other income, net		0.7

Net income	$	751.5		$
Adjustments to reconcile net income to Adjusted EBITDA:
Interest expense and other financing costs		39.2
Depreciation and amortization		98.9

EBITDA subtotal	$	889.6		$
FIFO impacts (favorable) unfavorable
Share-based compensation
Loss of disposition of assets
Loss on extinguishment of debt
Major scheduled turnaround expenses
Unrealized (gain) loss on derivatives, net

Adjusted EBITDA	$			$
Adjustments to reconcile Adjusted EBITDA to estimated cash available for distribution:
Less:
Incremental general and administrative expenses
Maintenance capital expenditures
Environmental capital expenditures
Growth capital expenditures
Increase in reserves for future turnarounds(a)
Cash interest expense, net
Plus:
Use of cash on hand to fund environmental capital expenditures
Draw on $150 million senior unsecured revolving credit facility to fund growth capital expenditures

Estimated Cash Available for Distribution	$			$

Common units outstanding for the period presented (in millions)
Estimated cash available for distribution per unit	$			$


		Twelve Months Ending September 30, 2013
		($ in millions, except per unit data and otherwise indicated)
Operating data:
Throughput (bpd):
Sweet
Medium
Heavy Sour

Total crude oil throughput
Feedstocks/Blendstocks

Total throughput

Production (bpd):
Gasoline
Distillate
Other (excluding internally produced fuel)

Total production (excluding internally produced fuel)

Forecasted NYMEX 2:1:1 crack spread (per barrel)
Forecasted realized 2:1:1 crack spread (per barrel)
Forecasted WTI (per barrel)
Refining margin per crude oil throughput barrel(a)
Refining margin per crude oil throughput barrel adjusted for FIFO impact(a)
Direct operating expenses excluding major turnaround expense per crude oil throughput barrel(b)

Statement of Operations Data ($ in millions):
Net sales		$
Operating costs and expenses:
Cost of product sold
Direct operating expenses
Selling, general and administrative expense
Depreciation and amortization

Operating income		$
Other income (expenses):
Interest expense and other financing costs
Realized gain (loss) on derivatives, net
Unrealized gain (loss) on derivatives, net
Other income, net


Net income		$


		Twelve months Ending September 30, 2013
		($ in millions, except per barrel data)
		(unaudited)
Net sales
Less: cost of product sold (exclusive of depreciation and amortization)
Refining margin
FIFO impacts (favorable)/unfavorable
Refining margin adjusted for FIFO impact
Crude oil throughput (bpd)
Refining margin per crude oil throughput barrel

Refining margin per crude oil throughput barrel adjusted for FIFO impact		$


		Twelve Months Ended September 30, 2013
		($ in millions, except per barrel data)
		(unaudited)
Direct operating expenses		$
Less: Major scheduled turnaround expense

Direct operating expenses excluding major scheduled turnaround expenses
Crude oil throughput (bpd)
Direct operating expenses excluding major scheduled turnaround expenses per crude oil throughput barrel		$


	CVR Refining, LP Historical Combined										CVR Refining, LP Combined Pro Forma
	Year Ended December 31,						Six Months Ended June 30,				Year Ended December 31, 2011		Six Months Ended June 30, 2012
	2009		2010		2011		2011		2012		Year Ended December 31, 2011		Six Months Ended June 30, 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		1.0		0.7		1.5		0.7
Wynnewood acquisition transaction fees and integration expenses		—		—		5.2		—		8.3		5.2		8.3
Major scheduled turnaround expense(c)		—		1.2		66.4		4.3		23.5		66.4		23.5
Share-based compensation(d)		2.5		11.5		8.9		7.2		10.7		8.9		10.7


	Six Months Ended June 30, 2012
	($ in millions)
	(unaudited except as otherwise indicated)
Wynnewood Refinery Statements of Operations Data:
Net sales	$	1,607.8
Cost of product sold(1)		1,365.0
Direct operating expenses(1)(2)		53.4
Schedule turnaround expense		2.5
Depreciation and amortization		16.7

Gross Profit(3)	$	170.2
Plus:
Direct operating expenses(1)		55.9
Depreciation and amortization		16.7

Refining margin(4)	$	242.8
Operating income	$	164.7

Wynnewood Refinery Key Operating Statistics:
Per crude oil throughput barrel:
Refining margin(4)	$	20.97

Refining margin adjusted for FIFO impacts(7)		23.22
Gross profit		14.70

Gross profit (excluding major scheduled turnaround expenses and adjusted for FIFO impact)(8)		17.17
Direct operating expenses(1)(2)		4.83

Direct operating expenses (excluding major scheduled turnaround expenses)(9)		4.61
Direct operating expenses per barrel sold(6)		4.15
Barrels sold (barrels per day)		73,996


	Six Months Ended June 30, 2012
Wynnewood Refinery Throughput and Production Data(bpd):
Throughput:
Sweet		43,740
Medium		19,911
Heavy sour		—

Total crude oil throughput		63,651
Feedstocks and blendstocks		2,995

Total throughput		66,646
Production:
Gasoline		32,821
Distillate		24,198
Other (excluding internally-produced fuel)		7,273

Total refining production (excluding internally-produced fuel)		64,292
Average sales price (dollars per gallon):
Gasoline	$	2.90
Distillate	$	3.06


Credit Suisse				Citigroup


Barclays		UBS Investment Bank		Jefferies


	Year Ended December 31,									Six Months Ended June 30,
	2009			2010			2011			2011			2012
										(unaudited)
	($ in millions)
Net income	$	64.6		$	38.2		$	480.3		$	246.3		$	222.2
Add:
Interest expense and other financing costs		43.8			49.7			53.0			26.3			37.8
Income tax expense		—			—			—			—			—
Depreciation and amortization		64.4			66.4			69.8			33.9			52.9

EBITDA	$	172.8		$	154.3		$	603.1		$	306.5		$	312.9
Add:
FIFO impacts (favorable), unfavorable(a)		(67.9	)		(31.7	)		(25.6	)		(21.3	)		95.0
Share-based compensation		2.5			11.5			8.9			7.2			10.7
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			—			8.3
Major scheduled turnaround expenses		—			1.2			66.4			4.3			23.5
Unrealized gain (loss) on derivatives, net		37.8			(0.6	)		(85.3	)		(3.2	)		81.3

Adjusted EBITDA	$	147.3		$	152.6		$	577.3		$	297.1		$	531.7


	Six Months Ended June 30, 2012						Six Months Ended June 30, 2011						Total Variance				Volume Variance		Price Variance
	Volume(1)		$ per barrel		Sales $		Volume(1)		$ per barrel		Sales $		Volume(1)		Sales $		Volume Variance		Price Variance
($ in millions other than per barrel data)
Gasoline		17.9	$	120.98	$	2,159.8		10.5	$	120.17	$	1,262.8		7.4	$	897.0	$	882.6	$	14.4
Distillate		13.8	$	127.23	$	1,758.5		8.5	$	127.20	$	1,082.4		5.3	$	676.1	$	675.7	$	0.4


	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 $		Volume Variance			Price Variance
($ 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


	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 $		Volume Variance		Price Variance
($ 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


	Year Ended December 31,									Six Months Ended June 30,
	2009			2010			2011			2011			2012
	($ in millions)
										(unaudited)
Net cash provided by (used in):
Operating Activities	$	31.9		$	167.0		$	352.7		$	192.8		$	385.5
Investing Activities		(33.6	)		(21.1	)		(655.9	)		(13.2	)		(62.2	)
Financing Activities		3.8			(146.3	)		303.6			(180.8	)		(296.6	)

Net increase (decrease) in cash and cash equivalents	$	2.1		$	(0.4	)	$	0.4		$	(1.2	)	$	26.7


	Actual		Estimated
	2011		2012		2013		2014
	($ in millions)
Coffeyville refinery:
Maintenance	$	49.7	$	58.5	$	82.9	$	94.2
Growth		6.8		2.1		11.8		2.4

Total capital (excluding turnaround expenditures)		56.5		60.6		94.7		96.6
Wynnewood refinery:(1)
Maintenance		0.5		75.5		84.2		106.7
Growth		—		7.0		17.9		26.9

Total capital (excluding turnaround expenditures)		0.5		82.5		102.1		133.6
Other Petroleum:
Maintenance		0.4		9.4		5.5		4.2
Growth		11.4		18.3		6.7		6.2

Total capital (excluding turnaround expenditures)		11.8		27.7		12.2		10.4

Total business capital (excluding major scheduled turnaround expense)	$	68.8	$	170.8	$	209.0	$	240.6

Major scheduled turnaround expense		66.4		121.0		—		—

Total capital spending (including major scheduled turnaround expense)	$	135.2	$	291.8	$	209.0	$	240.6


	Total		2012		2013		2014		2015		2016		Thereafter
	($ in millions)
Contractual Obligations
Long-term debt(1)	$	675.2	$	—	$	—	$	—	$	454.4	$	—	$	220.8
Operating leases		12.7		2.0		3.5		3.0		2.1		1.7		0.4
Capital lease obligations(2)		51.7		0.2		1.0		1.1		1.2		1.4		46.8
Unconditional purchase obligations(3)		905.0		58.1		114.6		107.4		96.8		90.2		437.9
Environmental liabilities(4)		2.0		0.3		0.2		0.2		0.2		0.1		1.0
Interest payments(5)		202.4		32.2		24.2		64.5		44.9		24.2		12.4

Total	$	1,849.0	$	92.8	$	143.5	$	176.2	$	599.6	$	117.6	$	719.3
Other Commercial Commitments
Standby letters of credit(6)	$	53.0	$	—	$	—	$	—	$	—	$	—	$	—


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


	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	%		16	%		14	%


	Average Differential ($per barrel)
	Year Ended December 31, 2011			Six Months Ended June 30, 2012
WTI – Brent(1)	$	(16.84	)	$	(16.45	)
WTI – Mars(1)		(12.58	)		(11.66	)
WCS – WTI(1)		(16.54	)		(23.79	)
WTS – WTI(1)		(2.06	)		(4.48	)
WTI at Midland – WTI(1)(2)		(0.52	)		(3.74	)


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
Aklylation 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


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)		80.0


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


Name	Age (as of 06/30/2012)	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	60	Executive Vice President, Crude Oil Acquisition and Petroleum Marketing
Christopher G. Swanberg	54	Vice President, Environmental, Health and Safety
Vincent J. Intrieri	55	Director
Samuel Merksamer	31	Director


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 Refining Holdings, LLC(3)
John J. Lipinski		—		—
Stanley A. Riemann		—		—
Susan M. Ball		—		—
Edmund S. Gross		—		—
Robert W. Haugen		—		—
Vincent J. Intrieri		—		—
Samuel Merksamer		—		—
All directors and executive officers as a group (10 persons)		—		—


	Shares Beneficially Owned as of September 27, 2012
Name of Beneficial Owner	Number		Percent
John J. Lipinski		489,351		*
Stanley A. Riemann		148,163		*
Susan M. Ball		32,076		*
Edmund S. Gross		113,253		*
Robert W. Haugen		43,095		*
Vincent J. Intrieri		—		—
Samuel Merksamer		—		—
All directors and executive officers as a group (10 persons)		904,603		1	%


Underwriter		Number of Common Units
Credit Suisse Securities (USA) LLC
Citigroup Global Markets Inc.
Barclays Capital Inc.
UBS Securities LLC
Jefferies & Company, Inc.

Total


CVR REFINING, LP

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
Unaudited Pro Forma Condensed Combined Balance Sheet as of June 30, 2012			P-1
Unaudited Pro Forma Condensed Combined Statement of Operations for the Six Months Ended June 30, 2012			P-2
Unaudited Pro Forma Condensed Combined Statement of Operations for the Year Ended December 31, 2011			P-3
Notes to Unaudited Pro Forma Condensed Combined Financial Statements			P-4

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 June 30, 2012 and December 31, 2011			F-4
Condensed Combined Statements of Operations for the Six Months Ended June 30, 2012 and 2011			F-5
Condensed Combined Statement of Changes in Divisional Equity for the Six Months Ended June 30, 2012			F-6
Condensed Combined Statements of Cash Flows for the Six Months Ended June 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


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


	Historical		Pro Forma Adjustments				Pro Forma
ASSETS
Current assets:
Cash and cash equivalents	$	29,409	$	500,000		a	$	340,000
				(9,000	)	b
				(477,226	)	c
				(10,059	)	c
				279,964		e
				300,000		f
				(19,000	)	g
				(248,032	)	h
				(6,056	)	h
Accounts receivable, net of allowance for doubtful accounts of $1,275 at June 30, 2012 and on a pro forma basis, including $739 from affiliates at June 30, 2012 and on a pro forma basis		210,471		—				210,471
Inventories		491,984		—				491,984
Prepaid expenses and other current assets including $788 due from affiliates at June 30, 2012 and on a pro forma basis		56,277		900		b		52,959
				(3,339	)	c
				(879	)	h
Insurance receivables		1,926		—				1,926

Total current assets		790,067		307,273				1,097,340
Property, plant and equipment, net		1,320,094		—				1,320,094
Deferred financing costs, net		14,752		8,100		b		13,656
				(5,889	)	c
				(3,307	)	h
Insurance receivable		4,076		—				4,076
Other long-term assets, including $595 due from affiliates at June 30, 2012 and on a pro forma basis		4,819		—				4,819

Total assets	$	2,133,808	$	306,177			$	2,439,985

LIABILITIES AND DIVISIONAL EQUITY/PARTNERS’ CAPITAL
Current liabilities:
Capital lease obligations	$	1,018	$	—			$	1,018
Accounts payable, including $127 due to affiliates at June 30, 2012 and on a pro forma basis		369,384		—				369,384
Personnel accruals		8,748		—				8,748
Accrued taxes other than income taxes		29,099		—				29,099
Accrued expenses and other current liabilities, including $149 due to affiliates at June 30, 2012 and on a pro forma basis		37,367		(10,059	)	c		21,252
				(6,056	)	h

Total current liabilities		445,616		(16,115	)			429,501
Long-term liabilities:
Long-term debt and capital lease obligations, net of current portion		726,911		500,000		a		551,738
				(447,050	)	c
				(7,377	)	d
				(222,750	)	h
				2,004		i
Accrued environmental liabilities, net of current portion		1,373		—				1,373
Other long-term liabilities, including $1,405 due to affiliates at June 30, 2012 and on a pro forma basis		2,620		—				2,620

Total long-term liabilities		730,904		(175,173	)			555,731

Commitments and contingencies
Divisional equity		957,288		(39,404	)	c		—
				7,377		d
				(29,468	)	h
				279,964		e
				(2,004	)	i
				(1,173,753	)	j
PRO FORMA PARTNERS’ CAPITAL
Common unitholders—public, units issued and outstanding		—		300,000		f		281,000
				(19,000	)	g
Common unitholders—parent, units issued and outstanding		—		1,173,753		j		1,173,753
General Partner Interest		—		—		k		—

Total divisional equity/partners’ capital		957,288		497,465				1,454,753

Total liabilities and divisional equity/partners’ capital	$	2,133,808	$	306,177			$	2,439,985