CVR Energy Annual Report 2015

Plain-text annual report

Table of ContentsUNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549_____________________________________________________________Form 10-K(Mark One) þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2015 ORoTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to .Commission file number: 001-33492_____________________________________________________________CVR Energy, Inc.(Exact name of registrant as specified in its charter)Delaware(State or Other Jurisdiction ofIncorporation or Organization)61-1512186(I.R.S. EmployerIdentification No.)2277 Plaza Drive, Suite 500Sugar Land, Texas(Address of Principal Executive Offices)77479(Zip Code)Registrant's Telephone Number, including Area Code:(281) 207-3200_____________________________________________________________ Securities registered pursuant to Section 12(b) of the Act:Title of Each ClassName of Each Exchange on Which RegisteredCommon Stock, $0.01 par value per shareThe New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act:NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period thatthe registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No oIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 orRegulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, indefinitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and"smaller reporting company" in Rule 12b-2 of the Exchange Act.Large accelerated filer þAccelerated filer oNon-accelerated filer oSmaller reporting company o (Do not check if a smaller reportingcompany) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þThe aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 2015 (the last businessday of the registrant's second fiscal quarter) was $588,400,939. Shares of the registrant's common stock held by each executive officer and director and by each entity or person that, to the registrant's knowledge, owned10% or more of the registrant's outstanding common stock as of June 30, 2015 have been excluded from this number in that these persons may be deemed affiliates of the registrant. This determination of possible affiliatestatus is not necessarily a conclusive determination for other purposes.Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.ClassOutstanding at February 16, 2016Common Stock, par value $0.01 per share86,831,050 sharesDocuments Incorporated By ReferenceDocumentParts IncorporatedProxy Statement for the 2016 Annual Meeting of StockholdersItems 10, 11, 12, 13 and 14 of Part III TABLE OF CONTENTS Page PART I Item 1.Business5Item 1A.Risk Factors20Item 1B.Unresolved Staff Comments46Item 2.Properties46Item 3.Legal Proceedings46Item 4.Mine Safety Disclosures46 PART II Item 5.Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities47Item 6.Selected Financial Data52Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations54Item 7A.Quantitative and Qualitative Disclosures About Market Risk94Item 8.Financial Statements and Supplementary Data97Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure150Item 9A.Controls and Procedures150Item 9B.Other Information150 PART III Item 10.Directors, Executive Officers and Corporate Governance151Item 11.Executive Compensation151Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters151Item 13.Certain Relationships and Related Transactions, and Director Independence151Item 14.Principal Accounting Fees and Services151 PART IV Item 15.Exhibits, Financial Statement Schedules1521Table of ContentsGLOSSARY OF SELECTED TERMSThe following are definitions of certain terms used in this Annual Report on Form 10-K for the year ended December 31, 2015 (this "Report").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 barrelof distillate. The 2-1-1 crack spread is expressed in dollars per barrel.ammonia — Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applicationsand finished fertilizer products.backwardation market — Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. Theopposite 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 dieselfuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.bpd — Abbreviation for barrels per day.bpcd — Abbreviation for barrels per calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by 365 days,thus reflecting all operational and logistical limitations.bulk sales — Volume sales through third-party pipelines, in contrast to tanker truck quantity rack sales.capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput maybe expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the mosteconomical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as 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.contango market — Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The oppositeof backwardation market.corn belt — The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio andWisconsin.crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crackspread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasolineand one barrel of distillate.distillates — Primarily diesel fuel, kerosene and jet fuel.ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically fromfermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as agasoline octane enhancer and oxygenate.farm belt — Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texasand Wisconsin.feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, dieselfuel and jet fuel during the refining process.2Table of ContentsGroup 3 — A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3refineries include the Refining Partnership's Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsarefinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and CHS' 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 ofprocessing 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 thecrude oil used as feedstock 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 processingto 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 refinedpetroleum products.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 onedegree Fahrenheit.MSCF — One thousand standard cubic feet, a customary gas measurement unit.natural gas liquids — Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels and products of therefining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.Nitrogen Fertilizer Partnership IPO — The initial public offering of 22,080,000 common units representing limited partner interests of CVRPartners, LP (the "Nitrogen Fertilizer Partnership"), which closed on April 13, 2011.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.petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.product pricing at gate — Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. Product pricing atgate is also referred to as netback.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.Refining Partnership IPO — The initial public offering of 27,600,000 common units representing limited partner interests of CVR Refining, LP (the"Refining Partnership"), which closed on January 23, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional commonunits).Secondary Offering — The registered public offering of 12,000,000 common units representing limited partner interests of the Nitrogen FertilizerPartnership, which closed on May 28, 2013.Second Underwritten Offering — The second underwritten offering of 7,475,000 common units of the Refining Partnership, which closed on June 30,2014 (which includes the underwriters' subsequently-exercised option to purchase additional common units).sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically lessexpensive than sweet crude oil.spot market — A market in which commodities are bought and sold for cash and delivered immediately.sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically moreexpensive than sour crude oil.3Table of Contentsthroughput — 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 the refinery or nitrogen fertilizer plant assets. Thisprocess involves the shutdown and inspection of major processing units and occurs every four to five years for the refineries and every two to three years forthe nitrogen fertilizer plant.UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.Underwritten Offering — The underwritten offering of 13,209,236 common units of the Refining Partnership, which closed on May 20, 2013 (whichincludes the underwriters' subsequently-exercised option to purchase additional common units).WCS — Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity")of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.WEC — Gary-Williams Energy Corporation, subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood EnergyCompany, LLC.WRC — Wynnewood Refining Company, LLC, the owner of the Wynnewood, Oklahoma refinery and related assets with a rated capacity of 70,000bpcd.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 ofapproximately 0.4 weight percent that is used as a benchmark for other crude oils.WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content ofapproximately 2.0 weight percent.Wynnewood Acquisition — The acquisition by the Company of all the outstanding shares of WEC and its subsidiaries, which owned the Wynnewood,Oklahoma refinery with a rated capacity of 70,000 bpcd and 2.0 million barrels of storage tanks, on December 15, 2011. As of January 2013, WRC became awholly-owned subsidiary of CVR Refining, LLC. It was previously a wholly-owned subsidiary of WEC.yield — The percentage of refined products that is produced from crude oil and other feedstocks.4Table of ContentsPART IItem 1. BusinessOverviewCVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries ("CVR Energy," the "Company," "we," "us," or "our") is a diversified holdingcompany primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP ("CVRRefining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). The Refining Partnership is anindependent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces and markets nitrogen fertilizersin the form of UAN and ammonia. We own the general partner and a majority of the common units representing limited partner interests in each of theRefining Partnership and the Nitrogen Fertilizer Partnership. CVR Energy's common stock is listed on the New York Stock Exchange ("NYSE") under thesymbol "CVI," the Refining Partnership's common units are listed on the NYSE under the symbol "CVRR" and the Nitrogen Fertilizer Partnership's commonunits are listed on the NYSE under the symbol "UAN."We operate under two business segments: petroleum (the petroleum and related businesses operated by the Refining Partnership) and nitrogen fertilizer(the nitrogen fertilizer business operated by the Nitrogen Fertilizer Partnership). Throughout the remainder of this document, our business segments arereferred to as the "petroleum business" and the "nitrogen fertilizer business," respectively.For the fiscal years ended December 31, 2015, 2014 and 2013, we generated consolidated net sales of $5.4 billion, $9.1 billion and $9.0 billion,respectively, and operating income of $421.6 million, $264.3 million and $710.5 million, respectively. The petroleum business generated $5.2 billion, $8.8billion and $8.7 billion of net sales and the nitrogen fertilizer business generated $289.2 million, $298.7 million and $323.7 million of net sales, in eachcase, for the years ended December 31, 2015, 2014 and 2013, respectively. The petroleum business generated operating income of $361.7 million, $207.2million and $603.0 million and the nitrogen fertilizer business generated operating income of $68.7 million, $82.8 million and $124.9 million, in each case,for the years ended December 31, 2015, 2014 and 2013, respectively. Our consolidated results of operations include certain other unallocated corporateactivities and the elimination of intercompany transactions and, therefore, are not a sum of the operating results of the petroleum and nitrogen fertilizerbusinesses.Refer to Item 1, "Petroleum Business" and Item 1, "Nitrogen Fertilizer Business" for further details on our business segments.Our HistoryThe Coffeyville refinery, which began operations in 1906, and the nitrogen fertilizer plant, built in 2000, were operated as components of FarmlandIndustries, Inc. ("Farmland") until March 3, 2004, the date on which Coffeyville Resources, LLC ("CRLLC") completed the acquisition of these assetsthrough a bankruptcy court auction.On June 24, 2005, Coffeyville Acquisition LLC ("CALLC"), which was formed by certain funds affiliated with Goldman, Sachs & Co. and Kelso &Company, L.P. (the "Goldman Sachs Funds" and the "Kelso Funds," respectively), acquired these businesses. CALLC operated our business from June 24,2005 until CVR Energy's initial public offering in October 2007.CVR Energy was formed in September 2006 as a subsidiary of CALLC in order to consummate an initial public offering of its businesses. CVR Energyconsummated its initial public offering on October 26, 2007. The Goldman Sachs Funds and the Kelso Funds completely sold their ownership interests byFebruary 2011 and May 2011, respectively.On April 13, 2011, the Nitrogen Fertilizer Partnership completed the Nitrogen Fertilizer Partnership IPO. The Nitrogen Fertilizer Partnership sold22,080,000 common units at a price of $16.00 per common unit, resulting in gross proceeds of $353.3 million. The Nitrogen Fertilizer Partnership's commonunits are listed on the NYSE and are traded under the symbol "UAN." In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen FertilizerPartnership paid approximately $24.7 million in underwriting fees and incurred approximately $4.4 million of other offering costs. As a result of the NitrogenFertilizer Partnership IPO and through May 27, 2013, CVR Energy indirectly owned approximately 70% of the Nitrogen Fertilizer Partnership's outstandingcommon units and 100% of the Nitrogen Fertilizer Partnership's general partner with its non-economic general partner interest.5Table of ContentsOn December 15, 2011, CVR Energy acquired all of the issued and outstanding shares of WEC. Assets acquired include a 70,000 bpcd rated capacityrefinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of company-owned storage tanks.On April 18, 2012, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with an affiliate of Icahn Enterprises L.P. ("IEP").Pursuant to the Transaction Agreement, IEP's affiliate offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's commonstock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment("CCP") right for each share, which represented the contractual right to receive an additional cash payment per share if a definitive agreement for the sale ofCVR Energy was executed on or before August 18, 2013 and such transaction closed. As no sale of the Company was executed by the date outlined in theTransaction Agreement, the CCPs expired on August 19, 2013.In May 2012, IEP's affiliate acquired a majority of the common stock of CVR Energy through the Offer. As of December 31, 2015, IEP and its affiliatesowned approximately 82% of CVR Energy’s outstanding common stock. On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units at aprice of $25.00 per unit, resulting in gross proceeds of $600.0 million. Of the common units issued, 4,000,000 units were purchased by an affiliate of IEP.Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per unitresulting in gross proceeds of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."In connection with the Refining Partnership IPO, the Refining Partnership paid approximately $32.5 million in underwriting fees and incurred approximately$3.9 million of other offering costs.Immediately following the Refining Partnership IPO and through May 19, 2013, CVR Energy indirectly owned approximately 81% of the total RefiningPartnership common units and 100% of the Refining Partnership's general partner, which holds a non-economic general partner interest. Prior to the RefiningPartnership IPO, CVR Energy owned 100% of the Refining Partnership and net income earned during this period was fully attributable to the Company.On May 20, 2013, the Refining Partnership completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to thepublic at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. Inconnection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of$30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described inthis paragraph are collectively referred to as the "Transactions." In connection with the Transactions, the Refining Partnership paid approximately $12.2million in underwriting fees and approximately $0.4 million in offering costs. The Refining Partnership utilized net proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) toredeem 13,209,236 common units from CVR Refining Holdings, LLC ("CVR Refining Holdings"), an indirect wholly-owned subsidiary of CVR Energy. Thenet proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The Refining Partnershipdid not receive any of the proceeds from the sale of common units by CVR Energy to AEPC. Immediately following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of the total RefiningPartnership common units (including units owned by affiliates of IEP representing 4% of total Refining Partnership common units), and CVR RefiningHoldings held approximately 71% of the total Refining Partnership common units. On May 28, 2013, CRLLC completed a registered public offering (the "Secondary Offering") whereby it sold 12,000,000 Nitrogen Fertilizer Partnershipcommon units to the public at a price of $25.15 per unit. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6 million, afterdeducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceedsfrom the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5million in offering costs.Immediately subsequent to the closing of the Secondary Offering and as of December 31, 2015, public security holders held approximately 47% of thetotal Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of the6Table of Contentstotal Nitrogen Fertilizer Partnership common units. In addition, CRLLC owns 100% of the Nitrogen Fertilizer Partnership’s general partner, CVR GP, LLC,which only holds a non-economic general partner interest. On June 30, 2014, the Refining Partnership completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000common units to the public at a price of $26.07 per unit. The Refining Partnership paid approximately $5.3 million in underwriting fees and approximately$0.5 million in offering costs. The Refining Partnership utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering toredeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July23, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately67% of the total Refining Partnership common units. On July 24, 2014, the Refining Partnership sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with theunderwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 millionfrom the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR RefiningHoldings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection withthe underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2015, public securityholders held approximately 34% of the total Refining Partnership common units (including units owned by affiliates of IEP, representing 4% of the totalRefining Partnership common units), and CVR Refining Holdings held approximately 66% of the total Refining Partnership common units, in addition toowning 100% of the Refining Partnership's general partner.On August 9, 2015, CVR Partners entered into an Agreement and Plan of Merger (the "Merger Agreement") with Rentech Nitrogen Partners, L.P.("Rentech Nitrogen") and Rentech Nitrogen GP, LLC ("Rentech Nitrogen GP"), pursuant to which CVR Partners would acquire Rentech Nitrogen andRentech Nitrogen GP by merging two newly-created direct wholly-owned subsidiaries of CVR Partners with and into those entities with Rentech Nitrogenand Rentech Nitrogen GP continuing as surviving entities and wholly-owned subsidiaries of CVR Partners (together, the "mergers"). Refer to Part II, Item 8,Note 1 ("Organization and History of the Company") of this Report for further discussion of the mergers.7Table of ContentsOrganizational Structure and Related OwnershipThe following chart illustrates our organizational structure and the organizational structure of the Refining Partnership and the Nitrogen Fertilizer Partnershipas of the date of this Report.8Table of ContentsPetroleum BusinessThe petroleum business, operated by the Refining Partnership, includes a complex full coking medium-sour crude oil refinery in Coffeyville, Kansaswith a rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). The combined crude capacity represents approximately 22% of the region'srefining capacity. The Coffeyville refinery located in southeast Kansas is approximately 100 miles from Cushing, Oklahoma, a major crude oil trading andstorage hub. The Wynnewood refinery is located approximately 65 miles south of Oklahoma City, Oklahoma and approximately 130 miles from Cushing,Oklahoma.For the year ended December 31, 2015, the Coffeyville refinery's product yield included gasoline (46%), diesel fuel (primarily ultra-low sulfur diesel)(43%), and pet coke and other refined products such as natural gas liquids ("NGL") (propane and butane), slurry, sulfur and gas oil (11%). The Wynnewoodrefinery's product yield included gasoline (52%), diesel fuel (primarily ultra-low sulfur diesel) (36%), asphalt (5%), jet fuel (4%) and other products (3%).The petroleum business also includes the following auxiliary operating assets:•Crude Oil Gathering System. The petroleum business owns and operates a crude oil gathering system serving Kansas, Nebraska, Oklahoma,Missouri, Colorado and Texas. The system has field offices in Bartlesville and Pauls Valley, Oklahoma and Plainville, Winfield and Iola,Kansas. The gathering system includes approximately 336 miles of active owned and leased pipelines and approximately 150 crude oiltransports and associated storage facilities, which allows it to gather crude oils from independent crude oil producers. The crude oil gatheringsystem has a gathering capacity of over 65,000 bpd. Gathered crude oil provides an attractive and competitive base supply of crude oil for theCoffeyville and Wynnewood refineries. During 2015, the petroleum business gathered an average of approximately 69,000 bpd. The petroleumbusiness also has 35,000 bpd of contracted capacity on the Keystone and Spearhead pipelines that allow it to supply price-advantagedCanadian and Bakken crudes to its refineries. It also has contracted capacity on the Pony Express and White Cliffs pipelines, which bothbecame in-service during 2015. Both the Pony Express and White Cliffs pipelines originate in Colorado and extend to Cushing, Oklahoma.•Pipelines and Storage Tanks. The petroleum business owns a proprietary pipeline system capable of transporting approximately 170,000 bpdof crude oil from its Broome Station facility located near Caney, Kansas to its Coffeyville refinery. Crude oils sourced outside of the proprietarygathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and thendelivered to the Broome Station tank farm via a pipeline owned by Plains Pipeline L.P. ("Plains"). The petroleum business owns approximately(i) 1.5 million barrels of crude oil storage capacity that supports the gathering system and the Coffeyville refinery, (ii) 0.9 million barrels ofcrude oil storage capacity at the Wynnewood refinery and (iii) 1.5 million barrels of crude oil storage capacity in Cushing, Oklahoma. Thepetroleum business also leases additional crude oil storage capacity of approximately (iv) 2.8 million barrels in Cushing, (v) 0.2 million barrelsin Duncan, Oklahoma and (vi) 0.1 million barrels at the Wynnewood refinery. In addition to crude oil storage, the petroleum business owns over4.5 million barrels of combined refined products and feedstocks storage capacity.•Marketing and Product Supply. The petroleum business also has a rack marketing division supplying product through tanker trucks directly tocustomers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and to customers at throughput terminalson Magellan Midstream Partners, L.P. ("Magellan") and NuStar Energy, LP's ("NuStar") refined products distribution systems.The refineries' complexity allows the petroleum business to optimize the yields (the percentage of refined product that is produced from crude oil andother feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery's ability to process lower quality crude oiland feedstocks in an economic manner. The two refineries' capacity weighted average complexity is 13.0. As a result of key investments in its refining assetsand the addition of process units to comply with gasoline quality regulations, both of the refinery's complexities have increased. The Coffeyville refinery'scomplexity score is 13.3, and the Wynnewood refinery's complexity score is 12.6. The petroleum business' higher complexity provides it the flexibility toincrease its refining margin over comparable refiners with lower complexities. The petroleum business has achieved significant increases in its refinery crudethroughput rates over historical levels. As a result of the increasing complexities, the petroleum business is capable of processing a variety of crudes,including WTS, WTI, sweet and sour Canadian, and locally gathered crudes. 9Table of ContentsCrude and Feedstock SupplyThe Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, theCoffeyville refinery crude oil slate consists of a blend of mid-continent domestic grades and various Canadian medium and heavy sours, and it has recentlyintroduced North Dakota Bakken and other similarly sourced crudes into its crude slate. While crude oil has historically constituted over 90% of theCoffeyville refinery's total throughput over the last five years, other feedstock inputs include normal butane, natural gasoline, alkylation feeds, naphtha, gasoil and vacuum tower bottoms.The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, althoughisobutane, gasoline components, and normal butane are also typically used. Historically most of the Wynnewood refinery's crude oil has been acquireddomestically, mainly from Texas and Oklahoma, but it can also access and process various light and medium Canadian grades.Crude oil is supplied to the Coffeyville and Wynnewood refineries through the wholly-owned gathering system and by pipeline. The petroleum businesshas continued to increase the number of barrels of crude oil supplied through its crude oil gathering system in 2015 and it now has the capacity of supplyingover 65,000 bpd of crude oil to the refineries. For the year ended December 31, 2015, the gathering system supplied approximately 39% of both of theCoffeyville and Wynnewood refineries' crude oil demand. Locally produced crude oils are delivered to the refineries at a discount to WTI, and althoughsometimes slightly heavier and more sour, offer good economics to the refineries. These crude oils are light and sweet enough to allow the refineries to blendhigher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining their target medium sour blend with an API gravity ofbetween 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of the proprietary gathering system are delivered to Cushing,Oklahoma by various pipelines including the Keystone and Spearhead pipelines, and subsequently to the Broome Station facility via the Plains pipeline. InMay 2015 and November 2015, the petroleum business' contracted capacity included the Pony Express and White Cliffs pipelines, respectively. From theBroome Station facility, crude oil is delivered to the Coffeyville refinery via the petroleum business' 170,000 bpd proprietary pipeline system. Crude oils aredelivered to the Wynnewood refinery by three separate pipelines, and received into storage tanks at terminals located on or near the refinery.For the year ended December 31, 2015, the Coffeyville refinery's crude oil supply blend was comprised of approximately 85.4% light sweet crude oil,12.8% heavy sour crude oil and 1.8% light/medium sour crude oil. For the year ended December 31, 2015, the Wynnewood refinery's crude oil supply blendwas comprised of approximately 99.5% light sweet crude oil and 0.5% light/medium sour crude oil. The light sweet crude oil supply blend includes itslocally gathered crude oil.The Coffeyville refinery is connected to the mid-continent natural gas liquids commercial hub of Conway, Kansas by the inbound Enterprise PipelineBlue Line. Natural gas liquids feedstock supplies such as butanes and natural gasoline are sourced and delivered directly into the refinery. In addition,Coffeyville's proximity to Conway provides access to the natural gas liquid and liquid petroleum gas fractionation and storage capabilities as well as thecommercial markets available at Conway.Crude Oil Supply AgreementOn August 31, 2012, Coffeyville Resources Refining and Marketing, LLC ("CRRM") and Vitol Inc. ("Vitol") entered into an Amended and RestatedCrude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil andintermediation logistics, which helps the petroleum business to reduce its inventory position and mitigate crude oil pricing risk. The Vitol Agreement willautomatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal atleast 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2016. Marketing and DistributionThe petroleum business focuses its Coffeyville petroleum product marketing efforts in the central mid-continent area, because of its relative proximity tothe refinery and pipeline access. Coffeyville also has access to the Rocky Mountain area. Coffeyville engages in rack marketing, which is the supply ofproduct through tanker trucks directly to customers located in close geographic proximity to the refinery and to customers at throughput terminals on therefined products distribution systems of Magellan and NuStar. Coffeyville also makes bulk sales (sales into third-party pipelines) into the mid-continentmarkets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. The outbound Enterprise Pipeline RedLine provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ULSD product sales from Kansas up intoNorth Dakota.10Table of ContentsThe Wynnewood refinery ships its finished product via pipeline, railcar, and truck. It focuses its efforts in the southern portion of the Magellan systemwhich covers all of Oklahoma, parts of Arkansas as well as eastern Missouri, and all other Magellan terminals. The pipeline system is also able to flow in theopposite direction, providing access to Texas markets as well as some adjoining states with pipeline connections. Wynnewood also sells jet fuel to the U.S.Department of Defense via its segregated truck rack and can offer asphalts, solvents and other specialty products via both truck and rail.CustomersCustomers for the refined petroleum products primarily include retailers, railroads, and farm cooperatives and other refiners/marketers in Group 3 of thePADD II region because of their relative proximity to the refineries and pipeline access. The petroleum business sells bulk products to long-standingcustomers at spot market prices based on a Group 3 basis differential to prices quoted on the New York Mercantile Exchange ("NYMEX"), which are reportedby industry market-related indices such as Platts and Oil Price Information Service.The petroleum business also has a rack marketing business supplying product through tanker trucks directly to customers located in proximity to theCoffeyville and Wynnewood refineries, as well as to customers located at throughput terminals on refined products distribution systems run by Magellan andNuStar. Rack sales are at posted prices that are influenced by competitor pricing and Group 3 spot market differentials. Additionally, the Wynnewoodrefinery supplies jet fuel to the U.S. Department of Defense. For the year ended December 31, 2015, the two largest customers accounted for approximately14% and 9% of the petroleum business net sales and approximately 53% of the petroleum business net sales were made to its ten largest customers.CompetitionThe petroleum business competes primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. Theprincipal competitive factors affecting its refining operations are cost of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refineryproduct mix and product distribution and transportation costs. The location of the refineries provides the petroleum business with a reliable supply of crudeoil and a transportation cost advantage over its competitors. The petroleum business primarily competes against five refineries operated in the mid-continentregion. In addition to these refineries, the refineries compete against trading companies, as well as other refineries located outside the region that are linked tothe mid-continent market through an extensive product pipeline system. These competitors include refineries located near the Gulf Coast and the Texaspanhandle region. The petroleum business refinery competition also includes branded, integrated and independent oil refining companies, such as Phillips66, HollyFrontier, CHS, Valero and Flint Hills Resources.SeasonalityThe petroleum business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during thewinter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel is higher during the planting and harvestingseasons. As a result, the petroleum business' results of operations for the first and fourth calendar quarters are generally lower compared to its results for thesecond and third calendar quarters. In addition, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months inthe markets in which the petroleum business sells its petroleum products can impact the demand for gasoline and diesel fuel. The demand for asphalt is alsoseasonal and is generally higher during the months of March through October.Nitrogen Fertilizer BusinessThe nitrogen fertilizer business, operated by the Nitrogen Fertilizer Partnership, is the only nitrogen fertilizer plant in North America that utilizes a petcoke gasification process to produce nitrogen fertilizer products, which are used primarily by farmers to improve the yield and quality of their crops. Thenitrogen fertilizer facility includes a 1,300 ton-per-day ammonia unit, a 3,000 ton-per-day UAN unit and a gasifier complex having a capacity of 89 millionstandard cubic feet per day of hydrogen. The nitrogen fertilizer business' principal products are UAN and ammonia. These products are manufactured at itsfacility in Coffeyville, Kansas. The nitrogen fertilizer business' product sales are heavily weighted toward UAN and all of its products are sold on a wholesalebasis.11Table of ContentsRaw Material SupplyThe nitrogen fertilizer facility's primary input is pet coke. In contrast, substantially all of the nitrogen fertilizer business' competitors use natural gas astheir primary raw material feedstock. Historically, pet coke has been less expensive than natural gas on a per ton of fertilizer produced basis. The nitrogenfertilizer facility's pet coke gasification process results in a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant.During the past five years, over 70% of the nitrogen fertilizer business' pet coke requirements on average were supplied by CVR Refining's adjacentcrude oil refinery pursuant to a renewable long-term agreement. Historically the nitrogen fertilizer business has obtained the remainder of its pet cokerequirements from third parties such as other Midwestern refineries or pet coke brokers at spot-prices. The Nitrogen Fertilizer Partnership is party to a pet cokesupply agreement with HollyFrontier Corporation. The term of this agreement expires in December 2016. If necessary, the gasification process can bemodified to operate on coal as an alternative, which provides an additional raw material source. There are significant supplies of coal within a 60-mile radiusof the nitrogen fertilizer plant.Linde LLC ("Linde") owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry airto the facility for a monthly fee. The nitrogen fertilizer business provides and pays for all utilities required for operation of the air separation plant. Theagreement with Linde expires in 2020.Although the nitrogen fertilizer plant has its own boiler that is used to create start-up steam, it also has the ability to import start-up steam for thenitrogen fertilizer plant from the adjacent Coffeyville crude oil refinery and then export steam back to the crude oil refinery once all units in the nitrogenfertilizer plant are in service. Monthly charges and credits are recorded with the steam valued at the natural gas price for the month.Nitrogen Production ProcessThe nitrogen fertilizer plant was built in 2000 with two separate gasifiers to provide redundancy and reliability. The plant uses a gasification process toconvert pet coke to high purity hydrogen for subsequent conversion to ammonia. The nitrogen fertilizer plant is capable of producing approximately 1,300tons per day of ammonia. Substantially all of the ammonia produced is converted to approximately 3,000 tons per day of UAN, which has historicallycommanded a premium price over ammonia. Typically, approximately 0.41 tons of ammonia is required to produce one ton of UAN. The nitrogen fertilizerbusiness completed a significant two-year plant expansion in February 2013, which increased UAN production capacity by 400,000 tons or approximately50%, per year. The expanded facility was operating at full rates at the end of the first quarter of 2013. In 2015, the nitrogen fertilizer business produced928,600 tons of UAN and 385,400 tons of ammonia. Approximately 96% of the produced ammonia tons and the majority of the purchased ammonia wereupgraded into UAN.The nitrogen fertilizer business schedules and provides routine maintenance to its critical equipment using its own maintenance technicians. Pursuant toa Technical Services Agreement with an affiliate of the General Electric Company ("General Electric"), which licenses the gasification technology to thenitrogen fertilizer business, General Electric provides technical advice and technological updates from their ongoing research as well as other licensees'operating experiences. The pet coke gasification process is licensed from General Electric pursuant to a perpetual license agreement that is fully paid. Thelicense grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions.Distribution, Sales and MarketingThe primary geographic markets for the nitrogen fertilizer business' fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas.The nitrogen fertilizer business markets the UAN products to agricultural customers and the ammonia products to industrial and agricultural customers.UAN and ammonia are distributed by truck or by railcar. If delivered by truck, products are sold on a freight-on-board basis, and freight is normallyarranged by the customer. The nitrogen fertilizer business leases and owns a fleet of railcars for use in product delivery. The nitrogen fertilizer business incurscosts to maintain and repair its railcar fleet that include expenses related to regulatory inspections and repairs. For example, many of the nitrogen fertilizerbusiness' railcars require specific regulatory inspections and repairs due on ten-year intervals. The extent and frequency of railcar fleet maintenance and repaircosts are generally expected to change based partially on when regulatory inspections and repairs are due for its railcars under the relevant regulations. Thenitrogen fertilizer business operates eight rail loading and two truck loading racks for UAN. It also operates four rail loading and two truck loading racks forammonia.12Table of ContentsThe nitrogen fertilizer business owns all of the truck and rail loading equipment at the nitrogen fertilizer facility. The nitrogen fertilizer business alsoutilizes two separate UAN storage tanks and related truck and railcar load-out facilities. Each of these facilities, located in Phillipsburg and Dartmouth,Kansas, has a UAN storage tank that has a capacity of two million gallons, or approximately 10,000 tons. The Phillipsburg property that the terminal wasconstructed on is owned by a subsidiary of CVR Refining, which operates the terminal. The Dartmouth terminal is located on leased property owned by thePawnee County Cooperative Association, which operates the terminal. The purpose of the UAN terminals is to collectively distribute approximately 40,000tons of UAN fertilizer annually.The nitrogen fertilizer business markets agricultural products to destinations that produce strong margins. The UAN market is primarily located near theUnion Pacific Railroad lines or destinations that can be supplied by truck. The ammonia market is primarily located near the Burlington Northern Santa Fe orKansas City Southern Railroad lines or destinations that can be supplied by truck.The nitrogen fertilizer business often uses forward sales of fertilizer products to optimize its asset utilization, planning process and productionscheduling. These sales are made by offering customers the opportunity to purchase product on a forward basis at prices and delivery dates that it proposes.The nitrogen fertilizer business uses this program to varying degrees during the year and between years depending on market conditions and has theflexibility to increase or decrease forward sales depending on management's view as to whether price environments will be increasing or decreasing. Fixingthe selling prices of nitrogen fertilizer products months in advance of their ultimate delivery to customers typically causes the nitrogen fertilizer businessreported selling prices and margins to differ from spot market prices and margins available at the time of shipment. Cash received as a result of prepayments isrecognized as deferred revenue on the Consolidated Balance Sheet upon receipt, and revenue and resultant net income and EBITDA are recorded as theproduct is delivered to the customer.CustomersThe nitrogen fertilizer business sells UAN products to retailers and distributors. In addition, it sells ammonia to agricultural and industrial customers.Some of its larger customers include Crop Production Services, Inc., Gavilon Fertilizer, LLC, Interchem, J.R. Simplot, Inc., MFA and United Suppliers, Inc.Given the nature of its business, and consistent with industry practice, the nitrogen fertilizer business does not have long-term minimum purchase contractswith its UAN and ammonia customers.For the year ended December 31, 2015, the top five customers in the aggregate represented 39% of the nitrogen fertilizer business' net sales. The nitrogenfertilizer business' top two customers on a consolidated basis accounted for approximately 14% and 10%, respectively, of the nitrogen fertilizer business' netsales.CompetitionCompetition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farmingactivities intensify and delivery capacity is a significant competitive factor. The nitrogen fertilizer business maintains a large fleet of leased and ownedrailcars and seasonally adjusts inventory to enhance its manufacturing and distribution operations.The nitrogen fertilizer business' major competitors include Agrium, Inc.; Koch Nitrogen Company, LLC; Potash Corporation of Saskatchewan, Inc.; CFIndustries Holdings, Inc. and Terra Nitrogen Company, LP. Domestic competition is intense due to customers' sophisticated buying tendencies andcompetitor strategies that focus on cost and service. The nitrogen fertilizer business also encounters competition from producers of fertilizer productsmanufactured in foreign countries. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respectivegovernments.Based on third-party expert data regarding total United States demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant's UANcapacity in 2015 represented approximately 7% of total U.S. UAN demand and that the net ammonia produced and marketed at its facility represented lessthan 1% of total U.S. ammonia demand.SeasonalityBecause the nitrogen fertilizer business primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand fornitrogen fertilizer products in the agricultural industry. As a result, the nitrogen fertilizer business typically generates greater net sales in the first half of eachcalendar year, which is referred to as the planting season, and its net sales tend to be lower during the second half of each calendar year, which is referred to asthe fill season.13Table of ContentsEnvironmental MattersThe petroleum and nitrogen fertilizer businesses are subject to extensive and frequently changing federal, state and local, environmental and health andsafety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, thestorage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. These lawsand regulations, their underlying regulatory requirements and the enforcement thereof impact the petroleum business and operations and the nitrogenfertilizer business and operations by imposing:•restrictions on operations or the need to install enhanced or additional controls;•the need to obtain and comply with permits, licenses and authorizations;•requirements for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability foroff-site waste disposal locations; and•specifications for the products marketed by the petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN andammonia.Our operations require numerous permits, licenses and authorizations. Failure to comply with these permits or environmental laws and regulations couldresult 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 andmany of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. The ultimateimpact on our business of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that ouroperations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are undergovernmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.The principal environmental risks associated with our businesses are outlined below with additional details included in Part I, Item 1A, Risk Factors andPart II, Item 8, Note 13 ("Commitments and Contingencies") of this Report.The Federal Clean Air ActThe federal Clean Air Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutantsinto the air, affect the petroleum business and the nitrogen fertilizer business both directly and indirectly. Direct impacts may occur through the federal CleanAir Act's permitting requirements and/or emission control requirements relating to specific air pollutants, as well as the requirement to maintain a riskmanagement program to help prevent accidental releases of certain regulated substances. The federal Clean Air Act indirectly affects the petroleum businessand the nitrogen fertilizer business by extensively regulating the air emissions of sulfur dioxide ("SO2"), volatile organic compounds, nitrogen oxides andother substances, including those emitted by mobile sources, which are direct or indirect users of our products.Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation ofcontrols or changes to the petroleum business or the nitrogen fertilizer facilities in order to comply. If new controls or changes to operations are needed, thecosts could be material. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmentalregulations 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 capitalexpenditures for the installation of certain air pollution control devices at the petroleum and nitrogen fertilizer operations when regulations change or we addnew equipment or modify existing equipment. Various regulations specific to our operations have been implemented, such as National Emission Standard forHazardous Air Pollutants ("NESHAP"), New Source Performance Standards ("NSPS") and New Source Review/Prevention of Significant Deterioration ("PSD").We have incurred, and expect to continue to have to make, substantial capital expenditures to attain or maintain compliance with these and other airemission regulations that have been promulgated or may be promulgated or revised in the future.14Table of ContentsOn September 12, 2012, the U.S. Environmental Protection Agency (the "EPA") published in the Federal Register final revisions to its NSPS for processheaters and flares at petroleum refineries. The EPA originally issued final standards in June 2008, but the portions of the rule relating to process heaters andflares were stayed pending reconsideration of certain provisions. The final standards regulate emissions of nitrogen oxide from process heaters and emissionsof SO2 from flares, as well as require certain work practice and monitoring standards for flares. We do not believe that the costs of complying with the rule willbe material.On August 14, 2012, the EPA sent both the Wynnewood and Coffeyville refineries letters regarding the EPA's 2012 enforcement alert entitled EPAEnforcement Targets Flaring Efficiency Violations signaling the agency's intention to begin a national enforcement program to conduct complianceevaluations and take enforcement actions against petroleum refining companies that operate flares that are not in compliance with standards articulated in theEnforcement Alert. The Enforcement Alert identified new standards that refiners are required to meet for flaring combustion efficiency. The EPA entered intoconsent decrees with several refining companies. Because the EPA has not specifically told us that our operations are not in compliance, we cannot say withcertainty whether or when we may become an enforcement target under this initiative.Refer to Part II, Item 8, Note 13 ("Commitments and Contingencies") of this Report for further discussion of recent environmental matters related to theClean Air Act including the "Flood, Crude Oil Discharge and Insurance" and certain "Environmental, Health and Safety ("EHS") Matters," such as the"Coffeyville Second Consent Decree," "Wynnewood Clean Air Act Compliance" and other compliance evaluations.The Coffeyville refinery's Clean Air Act Title V operating permit has expired, and has not yet been re-issued. The Coffeyville refinery timely submittedan application for renewal, and therefore is authorized under the regulations to operate under the current permit until the permit is re-issued. The permitrenewal process has begun, and capital costs or expenses, if any, related to changes to these permits are not known yet, but are not expected to be material.The Federal Clean Water ActThe federal Clean Water Act ("CWA") and its implementing regulations, as well as the corresponding state laws and regulations that regulate thedischarge of pollutants into the water, affect the petroleum business and the nitrogen fertilizer business. Direct impacts occur through the CWA's permittingrequirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily loadof 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 Wynnewood Refining Company, LLC ("WRC"), are subject to restrictions on their ability to use water in the eventof low availability conditions. Both CRRM and WRC have contracts in place to receive additional water during low-flow conditions, but these conditionscould change over time if water becomes scarce.The Wynnewood refinery's CWA permit ("OPDES permit") has expired. The refinery timely submitted their renewal application, and therefore isauthorized to continue discharging under the expired permit until the Oklahoma Department of Environmental Quality ("ODEQ") re-issues the permit. Thepermit renewal process has begun, and capital costs or expenses related to changes to this permit, if any, are not expected to be material.Release ReportingThe release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federaland state environmental laws. Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. For example, thenitrogen fertilizer facility periodically experiences minor releases of hazardous and extremely hazardous substances from its equipment. Our facilitiesperiodically have excess emission events from flaring and other planned and unplanned start-up, shutdown and malfunction events. Such releases arereported to the EPA and relevant state and local agencies. From time to time, the EPA has conducted inspections and issued information requests to us withrespect to our compliance with release reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act("CERCLA") and the Emergency Planning and Community Right-to-Know Act. If we fail to timely or properly report a release, or if the release violates thelaw 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.15Table of ContentsFuel RegulationsTier 2, Low Sulfur Fuels. In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles,establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-roaddiesel regulations, which required a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance byJanuary 1, 2010. The refineries are in compliance with the EPA's low sulfur gasoline and diesel fuel standards.Tier 3. In April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which will require that gasoline contain no morethan ten parts per million of sulfur on an annual average basis. Refineries must be in compliance with the more stringent emission standards by January 1,2017; however, compliance with the rule is extended until January 1, 2020 for approved small volume refineries and small refiners. In March 2015, the EPAapproved the Wynnewood refinery's application requesting "small volume refinery" status; therefore, it's compliance deadline is January 1, 2020. It is notanticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard. Mobile Source Air Toxic II EmissionsIn 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires the reduction of benzene in gasoline by 2011. The MSAT IIprojects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. The projects were completed at a total cost ofapproximately $48.3 million and $89.0 million, excluding capitalized interest, by CRRM and WRC, respectively.Renewable Fuel StandardsRefer to Part I, Item 1A, Risk Factors, If sufficient RINs are unavailable for purchase, if the petroleum business has to pay a significantly higher price forRINs or if the petroleum business is otherwise unable to meet the EPA's Renewable Fuels Standard (RFS) mandates, the petroleum business' financialcondition and results of operations could be materially adversely affected, and Part II, Item 8, Note 13 ("Commitments and Contingencies"), "Environmental,Health and Safety ("EHS") Matters" of this Report for further discussion of the "Renewable Fuel Standards." Greenhouse Gas EmissionsRefer to Part I, Item 1A, Risk Factors, Climate change laws and regulations could have a material adverse effect on our results of operations, financialcondition and cash flows, of this Report for further discussion of the Greenhouse Gas ("GHG") Emissions regulations.RCRAOur operations are subject to the Resource Conservation and Recovery Act ("RCRA") requirements for the generation, transportation, treatment, storageand disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRAestablishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses theenvironmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulatedsubstances. Refer to Part II, Item 8, Note 13 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" for further discussionof "RCRA Compliance Matters." Waste Management. There are two closed hazardous waste units at the Coffeyville refinery and eight other hazardous waste units in the process ofbeing closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewoodrefinery. In addition, one closed interim status hazardous waste land farm located at the now-closed Phillipsburg terminal is under long-term post closure care.Impacts of Past Manufacturing. The 2004 Consent Decree that CRRM signed with the EPA and the Kansas Department of Health and Environment(the "KDHE") required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the Coffeyville refinery. We are subject to a1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. Inaccordance 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 atthe 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 facility16Table of Contentsinvestigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, ODEQ andWRC have entered into a Consent Order requiring further investigations of groundwater conditions and enhancements of existing remediation systems.Additional remediation, if necessary, will be based upon the results of the further investigation.The anticipated investigation and remediation costs through 2019 were estimated, as of December 31, 2015, to be as follows:FacilitySiteInvestigationCosts CapitalCosts Total Operation &Maintenance CostsThrough 2019 Total Estimated CostsThrough 2019 (in millions)Coffeyville Refinery$0.3 $— $0.9 $1.2Phillipsburg Terminal0.4 — 1.1 1.5Wynnewood Refinery0.3 — 1.8 2.1Total Estimated Costs$1.0 $— $3.8 $4.8These estimates are based on current information and could increase or decrease as additional information becomes available through our ongoingremediation and investigation activities. At this point, we have estimated that, over ten years starting in 2016, we will spend approximately $7.3 million toremedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closedPhillipsburg terminal and at the Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately$2.1 million in 2015 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 bythe Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decreeas modified by a 2010 agreement between CRRM, Coffeyville Resources Terminal, LLC, the EPA and the KDHE, this financial assurance is currentlyprovided by a bond in the amount of $4.3 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of $0.2 million forestimated costs to close regulated hazardous waste management units at the Coffeyville refinery. Additional self-funded financial assurance of approximately$4.9 million and $2.4 million is required by our post-closure care obligations and the 2004 Consent Decree for clean-up costs at the Coffeyville refinery andPhillipsburg terminal, respectively. The $4.3 million bond amount is reduced each year based on actual expenditures for corrective actions and the letter ofcredit and the self-funded mechanisms are re-evaluated and adjusted on an annual basis. Current RCRA financial assurance requirements for the Wynnewoodrefinery total $0.2 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.Environmental RemediationUnder the CERCLA, RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. Thesepersons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the propertywhen the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminatedproperty. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entirecost of investigating and remediating the release of hazardous substances. Similarly, the Oil Pollution Act of 1990 generally subjects owners and operators offacilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costsarising from oil spills into the waters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmentalmatters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that wemanufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure you that we will not become involved in futureproceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existingor future proceedings, such costs would be covered by insurance or would not be material. Refer to Part II, Item 8, Note 13 ("Commitments andContingencies"), "Flood, Crude Oil Discharge and Insurance" of this Report for discussion of the environmental remediation associated with the discharge ofcrude oil on July 1, 2007 at the Coffeyville refinery.17Table of ContentsEnvironmental InsuranceWe are covered by a site pollution legal liability insurance policy with an aggregate limit of $50.0 million per pollution condition, subject to a self-insured retention of $1.0 million. The policy includes business interruption coverage, subject to a 5-day waiting period deductible. This insurance expires onMarch 1, 2016 and is expected to be renewed without any material changes in terms. The policy insures any location owned, leased or rented or operated bythe Company, including the Coffeyville refinery, the Wynnewood refinery and the nitrogen fertilizer facility. The policy insures certain pollution conditionsat or migrating from a covered location, certain waste transportation and disposal activities and business interruption.In addition to the site pollution legal liability insurance policy, we maintain umbrella and excess casualty insurance policies having an aggregate andoccurrence limit of $200.0 million, subject to a self-insured retention of $2.0 million. This insurance provides coverage due to named perils for claimsinvolving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. The casualtyinsurance policies, including umbrella and excess policies, expire on March 1, 2016 and are expected to be renewed or replaced by insurance policiescontaining materially equivalent sudden and accidental pollution coverage with no reduction in limits.The site pollution legal liability policy and the pollution coverage provided in the casualty insurance policies contain discovery requirements, reportingrequirements, exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claimwill be adequately insured for all potential damages.Safety, Health and Security MattersWe are subject to a number of federal and state laws and regulations related to safety, including the Occupational Safety and Health Act ("OSHA") andcomparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Managementregulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We operate a comprehensive safety, health and security program, with participation by employees at all levels of the organization. We have developedcomprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and healthperformance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely audit our programs and considerimprovements in our management systems.The Wynnewood refinery has been the subject of a number of OSHA inspections since 2006. As a result of these inspections, the Wynnewood refineryhas entered into four OSHA settlement agreements in 2008, pursuant to which it has agreed to undertake certain studies, conduct abatement activities, andrevise and enhance certain OSHA compliance programs. The remaining costs associated with implementing these studies, abatement activities and programrevisions are not expected to exceed $1.0 million.Refer to Part II, Item 8, Note 13 ("Commitments and Contingencies"), "Wynnewood Refinery Incident" of this Report for further discussion of OSHAmatters related to the Wynnewood refinery boiler explosion.Process Safety Management. We maintain a process safety management ("PSM") program. This program is designed to address all aspects of the OSHAguidelines for developing and maintaining a comprehensive PSM program. We will continue to audit our programs and consider improvements in ourmanagement 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 toemergencies in our facilities. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personalradios. We will continue to audit our programs and consider improvements in our management systems and equipment.18Table of ContentsEmployeesAs of December 31, 2015, 968 employees were employed by the petroleum business, 149 employees were employed by the nitrogen fertilizer businessand 215 employees were employed by the Company at our offices in Sugar Land, Texas and Kansas City, Kansas. As of December 31, 2015, these employeesare covered by health insurance, disability and retirement plans established by the Company. We believe that our relationship with our employees is good.As of December 31, 2015, the Coffeyville refinery employed 610 of the petroleum business' employees, about 54% of whom were covered by a collectivebargaining agreement. These employees are affiliated with five unions of the Metal Trades Department of the AFL-CIO ("Metal Trade Unions") and theUnited Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC ("UnitedSteelworkers"). The petroleum business is a party to a collective bargaining agreement with the Metal Trade Unions covering union members who workdirectly at the Coffeyville refinery. The agreement expires in March 2019. In addition, a collective bargaining agreement with the United Steelworkers, whichcovers the balance of the petroleum business' unionized employees who work in crude transportation, expires in March 2017 and automatically renews on anannual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. As of December 31, 2015, the Wynnewood refinery employed 317 of the petroleum business' employees, about 59% of whom were represented by theInternational Union of Operating Engineers. The collective bargaining agreement with the International Union of Operating Engineers with respect to theWynnewood refinery expires in June 2017.Available InformationOur website address is www.cvrenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and allamendments to those reports, are available free of charge through our website under "Investor Relations," as soon as reasonably practicable after theelectronic filing of these reports is made with the Securities and Exchange Commission (the "SEC"). In addition, our Corporate Governance Guidelines,Codes of Ethics and Charters of the Audit Committee, the Nominating and Corporate Governance Committee and the Compensation Committee of the Boardof Directors are available on our website. These guidelines, policies and charters are also available in print without charge to any stockholder requestingthem. We do not intend for information contained in our website to be part of this Report.Trademarks, Trade Names and Service MarksThis Report may include our and our affiliates' trademarks, including the CVR Energy logo, Coffeyville Resources, the Coffeyville Resources logo, theCVR Refining, LP logo and the CVR Partners, LP logo, each of which is registered or for which we are applying for federal registration with the United StatesPatent and Trademark Office. This Report may also contain trademarks, service marks, copyrights and trade names of other companies.19Table of ContentsItem 1A. Risk FactorsYou should carefully consider each of the following risks together with the other information contained in this Report and all of the information setforth in our filings with the SEC. If any of the following risks and uncertainties develops into actual events, our business, financial condition or results ofoperations could be materially adversely affected.Risks Related to the Petroleum BusinessThe price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on the petroleum business'earnings, profitability and cash flows.The petroleum business' financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oiland other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices tightens, the petroleum business' 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 avariety of factors including fluctuations in prices of crude oil, other feedstocks and refined products. Continued future volatility in refining industry marginsmay cause a decline in the petroleum business' results of operations, since the margin between refined product prices and crude oil and other feedstock pricesmay decrease below the amount needed for the petroleum business to generate net cash flow sufficient for its needs. The effect of changes in crude oil priceson the petroleum business' 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 inrefined product prices without a corresponding decrease in crude oil prices, could have a significant negative impact on the petroleum business' earnings,results of operations and cash flows.Profitability is also impacted by the ability to purchase crude oil at a discount to benchmark crude oils, such as WTI, as the petroleum business does notproduce any crude oil and must purchase all of the crude oil it refines. Crude oil differentials can fluctuate significantly based upon overall economic andcrude oil market conditions. Adverse changes in crude oil differentials can adversely impact refining margins, earnings and cash flows. In addition, thepetroleum business' purchases of crude oil, although based on WTI prices, have historically been at a discount to WTI because of the proximity of therefineries to the sources, existing logistics infrastructure and quality differences. Any change in the sources of crude oil, infrastructure or logisticalimprovements or quality differences could result in a reduction of the petroleum business' historical discount to WTI and may result in a reduction of thepetroleum business' cost advantage.Refining margins are also impacted by domestic and global refining capacity. Downturns in the economy reduce the demand for refined fuels and, inturn, generate excess capacity. In addition, the expansion and construction of refineries domestically and globally can increase refined fuel productioncapacity. Excess capacity can adversely impact refining margins, earnings and cash flows. The Arabian Gulf and Far East regions have added refiningcapacity in 2015 and 2016.The petroleum business is significantly affected by developments in the markets in which it operates. For example, numerous pipeline projects in 2014expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage.Volatile prices for natural gas and electricity also affect the petroleum business' manufacturing and operating costs. Natural gas and electricity priceshave been, and will continue to be, affected by supply and demand for fuel and utility services in both local and regional markets.If the petroleum business is required to obtain its crude oil supply without the benefit of a crude oil supply agreement, its exposure to the risks associatedwith volatile crude oil prices may increase and its liquidity may be reduced.Since December 31, 2009, the petroleum business has obtained substantially all of its crude oil supply for the Coffeyville refinery, other than the crudeoil it gathers, through the Vitol Agreement. The Vitol Agreement was amended and restated on August 31, 2012 to include the provision of crude oilintermediation services to the Wynnewood refinery. The agreement, which currently extends through December 31, 2016, minimizes the amount of in-transitinventory and mitigates crude oil pricing risk by ensuring pricing takes place close to the time the crude oil is refined and the yielded products are sold. If thepetroleum business were required to obtain its crude oil supply without the benefit of a supply intermediation agreement, its exposure to crude oil pricingrisk may increase, despite any hedging activity in which it may engage, and its liquidity could be negatively impacted due to increased inventory, potentialneed to post letters of credit and negative impacts of market volatility. There is no assurance that the petroleum business will be able to renew or extend theVitol Agreement beyond December 31, 2016.20Table of Contents Disruption of the petroleum business' ability to obtain an adequate supply of crude oil could reduce its liquidity and increase its costs.In addition to the crude oil the petroleum business gathers locally in Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, it also purchasedadditional crude oil to be refined into liquid fuels in 2015. In 2015, the Coffeyville refinery purchased an additional 65,000 to 70,000 bpd of crude oil whilethe Wynnewood refinery purchased approximately 45,000 to 50,000 bpd of crude oil. The Wynnewood refinery has historically acquired most of its crude oilfrom Texas and Oklahoma with smaller amounts purchased from other regions. The Coffeyville refinery and Wynnewood refinery obtained a portion of itsnon-gathered crude oil, approximately 23% and 1%, respectively, in 2015, from Canada. The actual amount of Canadian crude oil the petroleum businesspurchases is dependent on market conditions and will vary from year to year. The petroleum business is subject to the political, geographic, and economicrisks attendant to doing business with Canada. Disruption of production for any reason could have a material impact on the petroleum business. In the eventthat one or more of its traditional suppliers becomes unavailable, the petroleum business may be unable to obtain an adequate supply of crude oil, or it mayonly be able to obtain crude oil at unfavorable prices. As a result, the petroleum business may experience a reduction in its liquidity and its results ofoperations could be materially adversely affected.If our access to the pipelines on which the petroleum business relies for the supply of its crude oil and the distribution of its products is interrupted, itsinventory and costs may increase and it may be unable to efficiently distribute its products.If one of the pipelines on which either of the Coffeyville or Wynnewood refineries relies for supply of crude oil becomes inoperative, the petroleumbusiness would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase its costs and result inlower production levels and profitability. Similarly, if a major refined fuels pipeline becomes inoperative, the petroleum business would be required to keeprefined fuels in inventory or supply refined fuels to its customers through an alternative pipeline or by additional tanker trucks, which could increase thepetroleum business' costs and result in a decline in profitability.The geographic concentration of the petroleum business' refineries and related assets creates an exposure to the risks of the local economy in which weoperate and other local adverse conditions. The location of its refineries also creates the risk of increased transportation costs should the supply/demandbalance change in its region such that regional supply exceeds regional demand for refined products.As the petroleum business' refineries are both located in the southern portion of Group 3 of the PADD II region, the petroleum business primarily marketsits refined products in a relatively limited geographic area. As a result, it is more susceptible to regional economic conditions than the operations of moregeographically diversified competitors, and any unforeseen events or circumstances that affect its operating area could also materially adversely affect itsrevenues and cash flows. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increasedsupply of refined products from competitors and reductions in the supply of crude oil.Should the supply/demand balance shift in its region as a result of changes in the local economy, an increase in refining capacity or other reasons,resulting in supply in the region exceeding demand, the petroleum business may have to deliver refined products to customers outside of the region and thusincur considerably higher transportation costs, resulting in lower refining margins, if any.If sufficient RINs are unavailable for purchase, if the petroleum business has to pay a significantly higher price for RINs or if the petroleum business isotherwise unable to meet the EPA's Renewable Fuels Standard (RFS) mandates, the petroleum business' financial condition and results of operationscould be materially adversely affected.Pursuant to the Energy Independence and Security Act of 2007, the EPA has promulgated the Renewable Fuel Standards ("RFS"), which requires refinersto either blend "renewable fuels," such as ethanol and biodiesel, into their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu ofblending. Under the RFS, the volume of renewable fuels refineries like Coffeyville and Wynnewood are obligated to blend into their finished petroleumproducts is adjusted annually. The petroleum business is not able to blend the substantial majority of its transportation fuels and has to purchase RINs on theopen market as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. The price of RINs has been extremely volatile asthe EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which the amount of ethanol blendedinto the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to bereached when more than 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.21Table of ContentsOn December 14, 2015, the EPA published in the Federal Register a final rule establishing the renewable fuel volume mandates for 2014, 2015 and 2016,and the biomass-based diesel mandate for 2017. The volumes included in the EPA's final rule increase each year, but are lower, with the exception of thevolumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authority to lower the volumes, but its decisionto do so has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In addition, in the final rule establishing the renewable volumeobligations for 2014-2016 and bio-mass based diesel for 2017, the EPA articulated a policy to incentivize additional investments in renewable fuel blendingand distribution infrastructure by increasing the price of RINs. The petroleum business cannot predict the future prices of RINs or waiver credits. The price of RINs has been extremely volatile and has increased overthe last year. Additionally, the cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at whichRINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed atthe refineries and downstream terminals, all of which can vary significantly from period to period. However, the costs to obtain the necessary number of RINsand waiver credits could be material, if the price for RINs continues to increase. Additionally, because the petroleum business does not produce renewablefuels, increasing the volume of renewable fuels that must be blended into its products displaces an increasing volume of the refineries' product pool,potentially resulting in lower earnings and materially adversely affecting the petroleum business' cash flows. If the demand for the petroleum business'transportation fuel decreases as a result of the use of increasing volumes of renewable fuels, increased fuel economy as a result of new EPA fuel economystandards, or other factors, the impact on its business could be material. If sufficient RINs are unavailable for purchase, if the petroleum business has to pay asignificantly higher price for RINs or if the petroleum business is otherwise unable to meet the EPA's RFS mandates, its business, financial condition andresults of operations could be materially adversely affected. The petroleum business faces significant competition, both within and outside of its industry. Competitors who produce their own supply of crude oil orother feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than it does may have a competitive advantage.The refining industry is highly competitive with respect to both crude oil and other feedstock supply and refined product markets. The petroleumbusiness may be unable to compete effectively with competitors within and outside of the industry, which could result in reduced profitability. Thepetroleum business competes with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for its refined products.The petroleum business is not engaged in the petroleum exploration and production business and therefore it does not produce any of its crude oilfeedstocks. It does not have a retail business and therefore is dependent upon others for outlets for its refined products. It does not have long-termarrangements (those exceeding more than a twelve-month period) for much of its output. Many of its competitors obtain significant portions of their crude oiland other feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retailoutlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may bebetter positioned to withstand periods of depressed refining margins or feedstock shortages.A number of the petroleum business' competitors also have materially greater financial and other resources than it does. These competitors may have agreater ability to bear the economic risks inherent in all aspects of the refining industry. An expansion or upgrade of its 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 mayadd additional competitive pressure.In addition, the petroleum business competes with other industries that provide alternative means to satisfy the energy and fuel requirements of itsindustrial, commercial and individual customers. There are presently significant governmental incentives and consumer pressures to increase the use ofalternative fuels in the United States. The more successful these alternatives become as a result of governmental incentives or regulations, technologicaladvances, consumer demand, improved pricing or otherwise, the greater the negative impact on pricing and demand for the petroleum business' products andprofitability.Changes in the petroleum business' credit profile may affect its relationship with its suppliers, which could have a material adverse effect on its liquidityand its ability to operate the refineries at full capacity.Changes in the petroleum business' credit profile may affect the way crude oil suppliers view its ability to make payments and may induce them toshorten the payment terms for purchases or require it to post security prior to payment. Given the large dollar amounts and volume of the petroleum business'crude oil and other feedstock purchases, a burdensome change in payment terms may have a material adverse effect on the petroleum business' liquidity andits ability to make payments to its22Table of Contentssuppliers. This, in turn, could cause it to be unable to operate the refineries at full capacity. A failure to operate the refineries at full capacity could adverselyaffect the petroleum business' profitability and cash flows.The petroleum business' commodity derivative contracts may limit its potential gains, exacerbate potential losses and involve other risks.The petroleum business enters into commodity derivatives contracts to mitigate crack spread risk with respect to a portion of its expected refinedproducts production. However, its hedging arrangements may fail to fully achieve this objective for a variety of reasons, including its failure to haveadequate hedging contracts, if any, in effect at any particular time and the failure of its hedging arrangements to produce the anticipated results. Thepetroleum business may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit its ability tobenefit from favorable changes in margins. In addition, the petroleum business' hedging activities may expose it to the risk of financial loss in certaincircumstances, including instances in which:•the volumes of its actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedgingarrangement;•accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect itsrefinery or suppliers or customers;•the counterparties to its futures contracts fail to perform under the contracts; or•a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.As a result, the effectiveness of the petroleum business' risk mitigation strategy could have a material adverse impact on the petroleum business' financialresults and cash flows.The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on the petroleum business' ability to hedge risks associatedwith its business.The U.S. Congress has adopted the Dodd-Frank Act, comprehensive financial reform legislation that establishes federal oversight and regulation of theover-the-counter derivatives market and entities, such as the petroleum business, that participate in that market, and requires the Commodities FuturesTrading Commission ("CFTC") to institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires theCFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The Dodd-Frank Act and implementing rules andregulations also require certain swap participants to comply with, among other things, certain margin requirements and clearing and trade-executionrequirements in connection with certain derivative activities. The rulemaking process is still ongoing, and the petroleum business cannot predict the ultimateoutcome of the rulemakings. New regulations in this area may result in increased costs and cash collateral requirements for derivative instruments thepetroleum business may use to hedge and otherwise manage its financial risks related to volatility in oil and gas commodity prices.If the petroleum business reduces its use of derivatives as a result of the Dodd-Frank Act and any new rules and regulations, its results of operations maybecome more volatile and its cash flows may be less predictable, which could adversely affect its ability to satisfy its debt obligations or plan for and fundcapital expenditures. Increased volatility may make the petroleum business less attractive to certain types of investors. Finally, the Dodd-Frank Act wasintended, in part, to reduce the volatility of oil and natural gas prices. If the Dodd-Frank Act and any new regulations result in lower commodity prices, thepetroleum business' revenues could be adversely affected. Any of these consequences could adversely affect the petroleum business' financial condition andresults of operations and therefore could have an adverse effect on its ability to satisfy its debt obligations.The petroleum business' commodity derivative activities could result in period-to-period volatility. The petroleum business does not apply hedge accounting to its commodity derivative contracts and, as a result, unrealized gains and losses are chargedto its earnings based on the increase or decrease in the market value of the unsettled position. Such gains and losses are reflected in its income statement inperiods that differ from when the underlying hedged items (i.e., gross margins) are reflected in its income statement. Such derivative gains or losses inearnings may produce significant period-to-period earnings volatility that is not necessarily reflective of the petroleum business' operational performance.23Table of ContentsExisting design, operational, and maintenance issues associated with acquisitions may not be identified immediately and may require unanticipatedcapital expenditures that could adversely impact our financial condition, results of operations or cash flows.Our due diligence associated with acquisitions may result in our assuming liabilities associated with unknown conditions or deficiencies, as well asknown but undisclosed conditions and deficiencies, where we may have limited, if any, recourse for cost recovery. Such conditions and deficiencies may notbecome evident until sometime after cost recovery provisions, if any, have expired.The petroleum business must make substantial capital expenditures on its refineries and other facilities to maintain their reliability and efficiency. If thepetroleum business is unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed inproject economics deteriorate, the petroleum business' financial condition, results of operations or cash flows could be adversely affected.Delays or cost increases related to the engineering, procurement and construction of new facilities, or improvements and repairs to the petroleumbusiness' existing facilities and equipment, could have a material adverse effect on the petroleum business' financial condition, results of operations or cashflows. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond its control, including:•denial or delay in obtaining regulatory approvals and/or permits;•unplanned increases in the cost of equipment, materials or labor;•disruptions in transportation of equipment and materials;•severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting thepetroleum business' facilities, or those of its vendors and suppliers;•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;•market-related increases in a project's debt or equity financing costs; and/or•nonperformance or force majeure by, or disputes with, the petroleum business' vendors, suppliers, contractors or sub-contractors.The Coffeyville and Wynnewood refineries have been in operation for many years. Equipment, even if properly maintained, may require significantcapital expenditures and expenses to keep it operating at optimum efficiency. For example, the petroleum business incurred approximately $101.5 millionwith the first phase of the Coffeyville refinery turnaround completed in mid-November 2015 and incurred approximately $102.5 million associated with theturnaround for the Wynnewood refinery completed in December 2012. During the outage at the Coffeyville refinery as a result of the isomerization unit firein the third quarter of 2014, the petroleum business accelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million inturnaround expenses. During the fluid catalytic cracking unit ("FCCU") outage at the Wynnewood refinery in the fourth quarter of 2014, the petroleumbusiness accelerated certain planned turnaround activities and incurred approximately $1.3 million in turnaround expenses. These costs do not result inincreases in unit capacities, but rather are focused on trying to maintain safe, reliable operations. The second phase of the Coffeyville refinery turnaround isscheduled to begin in late February 2016 at a total estimated cost of approximately $35.0 million to $38.0 million (of which approximately $0.7 million wasincurred in the fourth quarter of 2015). The next turnaround for the Wynnewood refinery is scheduled to occur in the spring of 2017.Any one or more of these occurrences noted above could have a significant impact on the petroleum business. If the petroleum business was unable tomake up for the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect the petroleum business'financial position, results of operations or cash flows.The petroleum business' plans to expand its gathering and logistics assets, which assist it in reducing costs and increasing processing margins, mayexpose it to significant additional risks, compliance costs and liabilities.The petroleum business plans to continue to make investments to enhance the operating flexibility of its refineries and to improve its crude oil sourcingadvantage through additional investments in gathering and logistics assets. If it is able to successfully increase the effectiveness of the supporting gatheringand logistics assets, including the crude oil gathering24Table of Contentsoperations, the petroleum business believes it will be able to enhance crude oil sourcing flexibility and reduce related crude oil purchasing and deliverycosts. However, the acquisition of infrastructure assets to expand crude oil gathering may expose the petroleum business to risks in the future that aredifferent than or incremental to the risks it faces with respect to its refineries and existing gathering and logistics assets. The storage and transportation ofliquid hydrocarbons, including crude oil and refined products, are subject to stringent federal, state, and local laws and regulations governing the dischargeof materials into the environment, operational safety and related matters. Compliance with these laws and regulations could adversely affect the petroleumbusiness' operating results, financial condition and cash flows. Moreover, failure to comply with these laws and regulations may result in the assessment ofadministrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibitthe petroleum business' operations, or claims of damages to property or persons resulting from its operations.Any businesses or assets that the petroleum business may acquire in connection with an expansion of its crude oil gathering could expose it to the risk ofreleasing hazardous materials into the environment. These releases would expose the petroleum business to potentially substantial expenses, including clean-up and remediation costs, fines and penalties, and third-party claims for personal injury or property damage related to past or future releases. Accordingly, ifthe petroleum business does acquire any such businesses or assets, it could also incur additional expenses not covered by insurance which could be material.More stringent trucking regulations may increase the petroleum business' costs and negatively impact its results of operations.In connection with the trucking operations conducted by its crude gathering division, the petroleum business operates as a motor carrier and therefore issubject to regulation by the U.S. Department of Transportation and various state agencies. These regulatory authorities exercise broad powers, governingactivities 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 handlingrequirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiringchanges in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of thesepossible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time adriver 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 anddimension of equipment are also subject to federal and state regulations. Furthermore, from time to time, various legislative proposals are introduced, such asproposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase the petroleum business' costs or adversely impact therecruitment of drivers. The petroleum business cannot predict whether, or in what form, any increase in such taxes will be enacted or the extent to which theywill apply to the petroleum business and its operations.Risks Related to the Nitrogen Fertilizer BusinessThe nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile, and the nitrogen fertilizer business has experiencedsubstantial downturns in the past. Cycles in demand and pricing could potentially expose the nitrogen fertilizer business to significant fluctuations in itsoperating and financial results and have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cashflows.The nitrogen fertilizer business is exposed to fluctuations in nitrogen fertilizer demand in the agricultural industry. These fluctuations historically havehad and could in the future have significant effects on prices across all nitrogen fertilizer products and, in turn, our results of operations, financial conditionand cash flows.Nitrogen fertilizer products are commodities, the price of which can be highly volatile. The prices of nitrogen fertilizer products depend on a number offactors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, governmental policies and weatherconditions, which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which thenitrogen fertilizer business bases production, customers may acquire nitrogen fertilizer products from competitors, and the profitability of the nitrogenfertilizer business will be negatively impacted. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory thatwill have to be stored or liquidated.25Table of ContentsDemand for nitrogen fertilizer products is dependent on demand for crop nutrients by the global agricultural industry. The international market fornitrogen fertilizers is influenced by such factors as the relative value of the U.S. dollar and its impact upon the cost of importing nitrogen fertilizers, foreignagricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign markets, changes in the hard currencydemands of certain countries and other regulatory policies of foreign governments, as well as the laws and policies of the United States affecting foreign tradeand investment. Nitrogen-based fertilizers remain solidly in demand, driven by a growing world population, changes in dietary habits and an expanded use ofcorn for the production of ethanol. Supply is affected by available capacity and operating rates, raw material costs, government policies and global trade. Adecrease in nitrogen fertilizer prices would have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cashflows.The costs associated with operating the nitrogen fertilizer plant are largely fixed. If nitrogen fertilizer prices fall below a certain level, the nitrogenfertilizer business may not generate sufficient revenue to operate profitably or cover its costs.Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose costs are therefore largely variable, the nitrogenfertilizer business has largely fixed costs. As a result of the fixed cost nature of its operations, downtime, interruptions or low productivity due to reduceddemand, adverse weather conditions, equipment failure, a decrease in nitrogen fertilizer prices or other causes can result in significant operating losses whichcould have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.Continued low natural gas prices could impact the nitrogen fertilizer business' relative competitive position when compared to other nitrogen fertilizerproducers.Most nitrogen fertilizer manufacturers rely on natural gas as their primary feedstock, and the cost of natural gas is a large component of the totalproduction cost for natural gas-based nitrogen fertilizer manufacturers. Low natural gas prices benefit the nitrogen fertilizer business' competitors anddisproportionately impact our operations by making the nitrogen fertilizer business less competitive with natural gas-based nitrogen fertilizer manufacturers.Continued low natural gas prices could impair the nitrogen fertilizer business' ability to compete with other nitrogen fertilizer producers who utilize naturalgas as their primary feedstock if nitrogen fertilizer pricing drops as a result of low natural gas prices, and therefore have a material adverse impact on the cashflows of the nitrogen fertilizer business.Any decline in U.S. agricultural production or limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effecton the sales of nitrogen fertilizer, and on the nitrogen fertilizer business' results of operations, financial condition and cash flows.Conditions in the U.S. agricultural industry significantly impact the operating results of the nitrogen fertilizer business. The U.S. agricultural industrycan be affected by a number of factors, including weather patterns and field conditions, current and projected grain inventories and prices, domestic andinternational population changes, demand for U.S. agricultural products and U.S. and foreign policies regarding trade in agricultural products.The Agricultural Act of 2014 (the "2014 Farm Bill") ends direct subsidies to agricultural producers for owning farmland, and funds a new crop insuranceprogram in its place. As part of the conservation title of the 2014 Farm Bill, agricultural producers must meet a minimum standard of environmentalprotection in order to receive federal crop insurance on sensitive lands. The 2014 Farm Bill also discourages producers from converting native grasslands tofarmland by limiting crop insurance subsidies for the first few years for newly converted lands. These changes may have a negative impact on fertilizer salesand on the nitrogen fertilizer business’ results of operations, financial condition and cash flows.State and federal governmental policies, including farm and biofuel subsidies and commodity support programs, as well as the prices of fertilizerproducts, may also directly or indirectly influence the number of acres planted, the mix of crops planted and the use of fertilizers for particular agriculturalapplications. Developments in crop technology, such as nitrogen fixation (the conversion of atmospheric nitrogen into compounds that plants canassimilate), could also reduce the use of chemical fertilizers and adversely affect the demand for nitrogen fertilizer. In addition, from time to time various statelegislatures have considered limitations on the use and application of chemical fertilizers due to concerns about the impact of these products on theenvironment. Unfavorable state and federal governmental policies could negatively affect nitrogen fertilizer prices and therefore have a material adverseeffect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.26Table of ContentsA major factor underlying the current high level of demand for nitrogen-based fertilizer products is the production of ethanol. A decrease in ethanolproduction, an increase in ethanol imports or a shift away from corn as a principal raw material used to produce ethanol could have a material adverseeffect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.A major factor underlying the solid level of demand for nitrogen-based fertilizer products produced by the nitrogen fertilizer business is the productionof ethanol in the United States and the use of corn in ethanol production. Ethanol production in the United States is highly dependent upon a myriad offederal statutes and regulations, and is made significantly more competitive by various federal and state incentives and mandated usage of renewable fuelspursuant to the RFS. To date, the RFS has been satisfied primarily with fuel ethanol blended into gasoline. However, a number of factors, including thecontinuing "food versus fuel" debate and studies showing that expanded ethanol usage may increase the level of greenhouse gases in the environment as wellas be unsuitable for small engine use, have resulted in calls to reduce subsidies for ethanol, allow increased ethanol imports and to repeal or waive (in wholeor in part) the current RFS, any of which could have an adverse effect on corn-based ethanol production, planted corn acreage and fertilizer demand.Therefore, ethanol incentive programs may not be renewed, or if renewed, they may be renewed on terms significantly less favorable to ethanol producersthan current incentive programs. Recently, the volume of ethanol required by the RFS standards to be blended into transportation fuel has approached the "blend wall." The blend wall isthe maximum amount of ethanol that can be blended into the transportation fuel supply because of limitations like the ability of cars to use higher ethanolblended fuels and limitations on the blending and distribution infrastructure. The blend wall is generally considered to be reached when more than 10%ethanol by volume ("E10 gasoline") is blended into transportation fuel. On December 14, 2015, the EPA published in the Federal Register a final ruleestablishing the renewable fuel volume mandates for 2014, 2015 and 2016, and the biomass-based diesel mandate for 2017. The volumes included in EPA'sfinal rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. TheEPA used its waiver authority to lower the volumes, but its decision to do so has been challenged in the U.S. Court of Appeals for the District of ColumbiaCircuit by corn growers and renewable fuels producers. The renewable fuel volume mandate for 2016 is expected to breach the blend wall, forcing higherethanol fuel blends, including fuels with 15% or 85% ethanol, or non-ethanol renewable fuel that is not constrained by the blend wall. In addition, in thefinal rule establishing the renewable volume obligations for 2014-2016 and bio-mass based diesel for 2017, the EPA articulated a policy to incentivizeadditional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs. Any substantial decrease in future volumeobligations under RFS could have a material adverse effect on ethanol production in the United States, which could have a material adverse effect on thenitrogen fertilizer business' results of operations, financial condition and ability to make cash distributions.Further, while most ethanol is currently produced from corn and other raw grains, such as milo or sorghum, the current RFS mandate requires a portion ofthe overall RFS mandate to come from advanced biofuels, including cellulose-based biomass, such as agricultural waste, forest residue, municipal solid wasteand energy crops (plants grown for use to make biofuels or directly exploited for their energy content) and biomass-based diesel. In addition, there is acontinuing trend to encourage the use of products other than corn and raw grains for ethanol production. If this trend is successful, the demand for corn maydecrease significantly, which could reduce demand for nitrogen fertilizer products and have an adverse effect on the nitrogen fertilizer business' results ofoperations, financial condition and cash flows. This potential impact on the demand for nitrogen fertilizer products, however, could be slightly offset by thepotential market for nitrogen fertilizer product usage in connection with the production of cellulosic biofuels.Nitrogen fertilizer products are global commodities, and the nitrogen fertilizer business faces intense competition from other nitrogen fertilizerproducers.The nitrogen fertilizer business is subject to intense price competition from both U.S. and foreign sources, including competitors operating in the MiddleEast, the Asia-Pacific region, the Caribbean, Russia and the Ukraine. Fertilizers are global commodities, with little or no product differentiation, andcustomers make their purchasing decisions principally on the basis of delivered price and availability of the product. Increased global supply may putdownward pressure on fertilizer prices. Furthermore, in recent years the price of nitrogen fertilizer in the United States has been substantially driven bypricing in the global fertilizer market. The nitrogen fertilizer business competes with a number of U.S. producers and producers in other countries, includingstate-owned and government-subsidized entities. Some competitors have greater total resources and are less dependent on earnings from fertilizer sales, whichmakes them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. Increased domestic supplymay put downward pressure on fertilizer prices. Additionally, the nitrogen fertilizer business' competitors utilizing different corporate structures may be betterable to withstand lower cash flows than the nitrogen fertilizer business can as a limited partnership. The nitrogen fertilizer business'27Table of Contentscompetitive position could suffer to the extent it is not able to expand its resources either through investments in new or existing operations or throughacquisitions, joint ventures or partnerships. An inability to compete successfully could result in a loss of customers, which could adversely affect the sales,profitability and the cash flows of the nitrogen fertilizer business and therefore have a material adverse effect on the nitrogen fertilizer business' results ofoperations, financial condition and cash flows.The nitrogen fertilizer business is seasonal, which may result in it carrying significant amounts of inventory and seasonal variations in working capital.Our inability to predict future seasonal nitrogen fertilizer demand accurately may result in excess inventory or product shortages.The nitrogen fertilizer business is seasonal. Farmers tend to apply nitrogen fertilizer during two short application periods, one in the spring and the otherin the fall. The strongest demand for nitrogen fertilizer products typically occurs during the spring planting season. In contrast, the nitrogen fertilizer businessand other nitrogen fertilizer producers generally produce products throughout the year. As a result, the nitrogen fertilizer business and its customers generallybuild inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. The seasonality ofnitrogen fertilizer demand results in sales volumes and net sales being highest during the North American spring season and working capital requirementstypically being highest just prior to the start of the spring season.If seasonal demand exceeds projections, the nitrogen fertilizer business will not have enough product and its customers may acquire products from itscompetitors, which would negatively impact profitability. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excessinventory and higher working capital and liquidity requirements.The degree of seasonality of the nitrogen fertilizer business can change significantly from year to year due to conditions in the agricultural industry andother factors. As a consequence of such seasonality, it is expected that the distributions we receive from the nitrogen fertilizer business will be volatile andwill vary quarterly and annually.Adverse weather conditions during peak fertilizer application periods may have a material adverse effect on the nitrogen fertilizer business' results ofoperations, financial condition and cash flows, because the agricultural customers of the nitrogen fertilizer business are geographically concentrated.The nitrogen fertilizer business' sales to agricultural customers are concentrated in the Great Plains and Midwest states and are seasonal in nature. Thenitrogen fertilizer business' quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules andpurchase patterns. For example, the nitrogen fertilizer business generates greater net sales and operating income in the first half of the year, which is referredto herein as the planting season, compared to the second half of the year. Accordingly, an adverse weather pattern affecting agriculture in these regions orduring the planting season could have a negative effect on fertilizer demand, which could, in turn, result in a material decline in the nitrogen fertilizerbusiness' net sales and margins and otherwise have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition andcash flows. The nitrogen fertilizer business' quarterly results may vary significantly from one year to the next due largely to weather-related shifts in plantingschedules and purchase patterns. As a result, it is expected that the nitrogen fertilizer business' distributions to holders of its common units (including us) willbe volatile and will vary quarterly and annually.The nitrogen fertilizer business' operations are dependent on third-party suppliers, including Linde, which owns an air separation plant that providesoxygen, nitrogen and compressed dry air to its facility, and the City of Coffeyville, which supplies the nitrogen fertilizer business with electricity. Adeterioration in the financial condition of a third- party supplier, a mechanical problem with the air separation plant, or the inability of a third-partysupplier to perform in accordance with its contractual obligations could have a material adverse effect on the nitrogen fertilizer business' results ofoperations, financial condition and cash flows.The operations of the nitrogen fertilizer business depend in large part on the performance of third-party suppliers, including Linde for the supply ofoxygen, nitrogen and compressed dry air, and the City of Coffeyville for the supply of electricity. With respect to Linde, operations could be adverselyaffected if there were a deterioration in Linde's financial condition such that the operation of the air separation plant located adjacent to the nitrogen fertilizerplant was disrupted. Additionally, this air separation plant in the past has experienced numerous short-term interruptions, causing interruptions in gasifieroperations. With respect to electricity, in 2010, the nitrogen fertilizer business entered into an amended and restated electric services agreement with the Cityof Coffeyville, Kansas, which gives the nitrogen fertilizer business an option to extend the term of such agreement through June 30, 2024. Should Linde, theCity of Coffeyville or any of its other third-party suppliers fail to perform in accordance with existing contractual arrangements, operations could be forced tohalt. Alternative28Table of Contentssources of supply could be difficult to obtain. Any shutdown of operations at the nitrogen fertilizer plant, even for a limited period, could have a materialadverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.The nitrogen fertilizer business' results of operations, financial condition and cash flows may be adversely affected by the supply and price levels of petcoke.The profitability of the nitrogen fertilizer business is directly affected by the price and availability of pet coke obtained from the Coffeyville refinerypursuant to a long-term agreement and pet coke purchased from third parties, both of which vary based on market prices. Pet coke is a key raw material usedby the nitrogen fertilizer business in the manufacture of nitrogen fertilizer products. If pet coke costs increase, the nitrogen fertilizer business may not be ableto increase its prices to recover these increased costs, because market prices for nitrogen fertilizer products are not correlated with pet coke prices.The nitrogen fertilizer business may not be able to maintain an adequate supply of pet coke. In addition, it could experience production delays or costincreases if alternative sources of supply prove to be more expensive or difficult to obtain. The nitrogen fertilizer business currently purchases 100% of thepet coke the Coffeyville refinery produces. Accordingly, if the nitrogen fertilizer business increases production, it will be more dependent on pet cokepurchases from third-party suppliers at open market prices. The nitrogen fertilizer business is party to a pet coke supply agreement with HollyFrontierCorporation. The term of this agreement ends in December 2016. There is no assurance that the nitrogen fertilizer business would be able to purchase petcoke on comparable terms from third parties or at all.The nitrogen fertilizer business relies on third-party providers of transportation services and equipment, which subjects it to risks and uncertaintiesbeyond its control that may have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.The nitrogen fertilizer business relies on railroad and trucking companies to ship finished products to its customers. The nitrogen fertilizer business alsoleases railcars from railcar owners in order to ship its finished products. These transportation operations, equipment and services are subject to varioushazards, including extreme weather conditions, work stoppages, delays, spills, derailments and other accidents and other operating hazards.These transportation operations, equipment and services are also subject to environmental, safety and other regulatory oversight. Due to concerns relatedto terrorism or accidents, local, state and federal governments could implement new regulations affecting the transportation of the nitrogen fertilizer business'finished products. In addition, new regulations could be implemented affecting the equipment used to ship its finished products.Any delay in the nitrogen fertilizer business' ability to ship its finished products as a result of these transportation companies' failure to operate properly,the implementation of new and more stringent regulatory requirements affecting transportation operations or equipment, or significant increases in the cost ofthese services or equipment could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving ammonia or other products the nitrogen fertilizer businessproduces or transports that cause severe damage to property or injury to the environment and human health could have a material adverse effect on thenitrogen fertilizer business' results of operations, financial condition and cash flows. In addition, the costs of transporting ammonia could increasesignificantly in the future.The nitrogen fertilizer business manufactures, processes, stores, handles, distributes and transports ammonia, which can be very volatile and extremelyhazardous. Major accidents or releases involving ammonia could cause severe damage or injury to property, the environment and human health, as well as apossible disruption of supplies and markets. Such an event could result in civil lawsuits, fines, penalties and regulatory enforcement proceedings, all of whichcould lead to significant liabilities. Any damage to persons, equipment or property or other disruption of the ability of the nitrogen fertilizer business toproduce or distribute its products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure itsassets, which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. The nitrogenfertilizer facility periodically experiences minor releases of ammonia related to leaks from its equipment. Similar events may occur in the future and couldhave a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.In addition, the nitrogen fertilizer business may incur significant losses or costs relating to the operation of railcars used for the purpose of carryingvarious products, including ammonia. Due to the dangerous and potentially toxic nature of the cargo, in particular ammonia, on board railcars, a railcaraccident may result in fires, explosions and pollution. These circumstances may29Table of Contentsresult in sudden, severe damage or injury to property, the environment and human health. In the event of pollution, the nitrogen fertilizer business may beheld responsible even if it is not at fault and it complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidentsinvolving ammonia and other products the nitrogen fertilizer business produces or transports may result in the nitrogen fertilizer business or us being namedas a defendant in lawsuits asserting claims for large amounts of damages, which could have a material adverse effect on the nitrogen fertilizer business' resultsof operations, financial condition and cash flows.Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. Ammonia is mosttypically transported by pipeline and railcar. A number of initiatives are underway in the railroad and chemical industries that may result in changes to railcardesign in order to minimize railway accidents involving hazardous materials. In addition, in the future, laws may more severely restrict or eliminate theability of the nitrogen fertilizer business to transport ammonia via railcar. If any railcar design changes are implemented, or if accidents involving hazardousfreight increase the insurance and other costs of railcars, freight costs of the nitrogen fertilizer business could significantly increase.Environmental laws and regulations on fertilizer end-use and application and numeric nutrient water quality criteria could have a material adverseimpact on fertilizer demand in the future. Future environmental laws and regulations on the end-use and application of fertilizers could cause changes in demand for the nitrogen fertilizerbusiness' products. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit the ability of thenitrogen fertilizer business to market and sell its products to end users. From time to time, various state legislatures have proposed bans or other limitationson fertilizer products. The EPA is encouraging states to adopt state-wide numeric water quality criteria for total nitrogen and total phosphorus, which arepresent in the nitrogen fertilizer business' fertilizer products. A number of states have adopted or proposed numeric nutrient water quality criteria for nitrogenand phosphorus. The adoption of stringent state criteria for nitrogen and phosphorus could reduce the demand for nitrogen fertilizer products in those states.If such laws, rules, regulations or interpretations to significantly curb the end-use or application of fertilizers were promulgated in the nitrogen fertilizerbusiness' marketing areas, it could result in decreased demand for its products and have a material adverse effect on the nitrogen fertilizer business' results ofoperations, financial condition and cash flows. If licensed technology were no longer available, the nitrogen fertilizer business may be adversely affected.The nitrogen fertilizer business has licensed, and may in the future license, a combination of patent, trade secret and other intellectual property rights ofthird parties for use in its business. In particular, the gasification process it uses to convert pet coke to high purity hydrogen for subsequent conversion toammonia is licensed from General Electric. The license, which is fully paid, grants the nitrogen fertilizer business perpetual rights to use the pet cokegasification process on specified terms and conditions and is integral to the operations of the nitrogen fertilizer facility. If this license or any other licenseagreements on which the nitrogen fertilizer business' operations rely, were to be terminated, licenses to alternative technology may not be available, or mayonly be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently-licensedtechnology may require substantial changes to manufacturing processes or equipment and may have a material adverse effect on the nitrogen fertilizerbusiness' results of operations, financial condition and cash flows.The nitrogen fertilizer business may face third-party claims of intellectual property infringement, which if successful could result in significant costs.Although there are currently no pending claims relating to the infringement of any third-party intellectual property rights, in the future the nitrogenfertilizer business may face claims of infringement that could interfere with its ability to use technology that is material to its business operations. Anylitigation of this type, whether successful or unsuccessful, could result in substantial costs and diversions of resources, either of which could have a materialadverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. In the event a claim of infringement against thenitrogen fertilizer business is successful, it may be required to pay royalties or license fees for past or continued use of the infringing technology, or it may beprohibited from using the infringing technology altogether. If it is prohibited from using any technology as a result of such a claim, it may not be able toobtain licenses to alternative technology adequate to substitute for the technology it can no longer use, or licenses for such alternative technology may onlybe available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently licensed technologymay require the nitrogen fertilizer business to make substantial changes to its manufacturing processes or equipment or to its products, and could have amaterial adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.30Table of ContentsThere can be no assurance that the transportation costs of the nitrogen fertilizer business' competitors will not decline.The nitrogen fertilizer plant is located within the U.S. farm belt, where the majority of the end users of its nitrogen fertilizer products grow their crops.Many of its competitors produce fertilizer outside of this region and incur greater costs in transporting their products over longer distances via rail, ships andpipelines. There can be no assurance that competitors' transportation costs will not decline or that additional pipelines will not be built, lowering the price atwhich competitors can sell their products, which would have a material adverse effect on the nitrogen fertilizer business' results of operations, financialcondition and cash flows.Risks Related to Our Entire BusinessInstability and volatility in the capital, credit and commodity markets in the global economy could negatively impact our business, financial condition,results of operations and cash flows.Our business, financial condition and results of operations could be negatively impacted by difficult conditions and volatility in the capital, credit andcommodities markets and in the global economy. For example:•Although we believe the petroleum business has sufficient liquidity under its ABL credit facility and the intercompany credit facility to operateboth the Coffeyville and Wynnewood refineries, and that the nitrogen fertilizer business has sufficient liquidity under its revolving creditfacility to run the nitrogen fertilizer business, under extreme market conditions there can be no assurance that such funds would be available orsufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all. Furthermore, thenitrogen fertilizer business' credit facility matures in April 2016 and there can be no assurance that it will be able to refinance its $125.0 millionof outstanding term loan debt or obtain a new revolving credit facility on similar terms or at all.•Market volatility could exert downward pressure on the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units,which may make it more difficult for either or both of them to raise additional capital and thereby limit their ability to grow, which could in turncause our stock price to drop.•The petroleum business' and nitrogen fertilizer business' credit facilities contain various covenants that must be complied with, and if eitherbusiness is not in compliance, there can be no assurance that either business would be able to successfully amend the agreement in the future.Further, any such amendment may be expensive. In addition, any new credit facility the petroleum business or nitrogen fertilizer business mayenter into may require them to agree to additional covenants.•Market conditions could result in significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers,and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons couldresult in decreased sales and earnings for us.The refineries and nitrogen fertilizer facility face significant risks due to physical damage hazards, environmental liability risk exposure, and unplannedor emergency partial or total plant shutdowns resulting in business interruptions. We could incur potentially significant costs to the extent there areunforeseen events which cause property damage and a material decline in production which are not fully insured. The commercial insurance industryengaged in underwriting energy industry risk is specialized and there is finite capacity; therefore, the industry may limit or curtail coverage, may modifythe coverage provided or may substantially increase premiums in the future. If any of our production plants, logistics assets, key pipeline operations serving our plants, or key suppliers sustains a catastrophic loss and operationsare shutdown or significantly impaired, it would have a material adverse impact on our operations, financial condition and cash flows. In addition, the riskexposures we have at the Coffeyville, Kansas plant complex are greater due to production facilities for refinery and fertilizer production, distribution andstorage being in relatively close proximity and potentially exposed to damage from one incident, such as resulting damages from the perils of explosion,windstorm, fire, or flood. Operations at either or both of the refineries and the nitrogen fertilizer plant could be curtailed, limited or completely shut down foran extended period of time as the result of one or more unforeseen events and circumstances, which may not be within our control, including:•major unplanned maintenance requirements31Table of Contents•catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire, or natural disasters,including, floods, windstorms and other similar events;•labor supply shortages, or labor difficulties that result in a work stoppage or slowdown;•cessation or suspension of a plant or specific operations dictated by environmental authorities; and•an event or incident involving a large clean-up, decontamination, or the imposition of laws and ordinances regulating the cost and schedule ofdemolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition.We have sustained losses over the past ten-year period at our plants, which are illustrative of the types of risks and hazards that exist. These losses orevents resulted in costs assumed by us that were not fully insured due to policy retentions or applicable exclusions. These events were as follows:•June 2007: Coffeyville refinery and nitrogen fertilizer plant; flood•September 2010: Nitrogen fertilizer plant; secondary urea reactor rupture•December 2010: Coffeyville refinery; FCCU fire•December 2010: Wynnewood refinery; hydrocracker unit fire•September 2012: Wynnewood refinery; boiler explosion•July/August 2013: Coffeyville refinery; FCCU outage•July 2014: Coffeyville refinery; isomerization unit fire Currently, we are insured under casualty, environmental, property and business interruption insurance policies. The property and business interruptioncoverage has a combined policy limit of $1.25 billion. The property and business interruption insurance policies contain limits and sub-limits which insureall CVR Energy assets. There is potential for a common occurrence to impact both the nitrogen fertilizer plant and Coffeyville refinery in which case theinsurance limitations would apply to all damages combined. Under this insurance program, there is a $10.0 million property damage retention for allproperties ($2.5 million in respect of the nitrogen fertilizer plant). For business interruption losses, the insurance program has a 45-day waiting periodretention for any one occurrence. In addition, the insurance policies contain a schedule of sub-limits which apply to certain specific perils or areas ofcoverage. Sub-limits which may be of importance depending on the nature and extent of a particular insured occurrence are: flood, earthquake, contingentbusiness interruption insuring key suppliers, pipelines and customers, debris removal, decontamination, demolition and increased cost of construction due tolaw and ordinance, and others. Such conditions, limits and sub-limits could materially impact insurance recoveries and potentially cause us to assume losseswhich could impair earnings. There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and there are risks associated with thecommercial insurance industry reducing capacity, changing the scope of insurance coverage offered, and substantially increasing premiums due to adverseloss experience or other financial circumstances. Factors that impact insurance cost and availability include, but are not limited to: industry wide losses,natural disasters, specific losses incurred by us and the investment returns earned by the insurance industry. If the supply of commercial insurance is curtaileddue to highly adverse financial results, we may not be able to continue our present limits of insurance coverage or obtain sufficient insurance capacity toadequately insure our risks for property damage or business interruption. Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or futurecontamination 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 substantialpenalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns.32Table of ContentsIn addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of lawsand regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becomingincreasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as thetechnology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmentalcompliance could have a material adverse effect on our business' 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 ofprescriptive limits and performance standards in order to operate. All of these permits, licenses, approvals, limits and standards require a significant amount ofmonitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval, limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due tothe 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 mayhave a material adverse effect on our ability to operate our facilities and accordingly our financial performance. For a discussion of environmental laws andregulations and their impact on our business and operations, please see "Business — Environmental Matters."We could incur significant cost in cleaning up contamination at our refineries, terminals, fertilizer plant and off-site locations.Our businesses are subject to the occurrence of accidental spills, discharges or other releases of petroleum or hazardous substances into the environment.Past or future spills related to any of our current or former operations, including the refineries, pipelines, product terminals, fertilizer plant or transportation ofproducts or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential clean-upresponsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, wecould be held strictly liable under CERCLA, and similar state statutes for past or future spills without regard to fault or whether our actions were incompliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated withfacilities 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 clean-up costs for past or future releases or spills, liability to third parties for damage to their property or exposure tohazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and couldhave a material adverse effect on our results of operations, financial condition and cash flows. In addition, we may incur liability for alleged personal injuryor property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability forpersonal injury, property damage, natural resource damage or for clean-up costs for the alleged migration of contamination or other hazardous substancesfrom our facilities to adjacent and other nearby properties.Four of our facilities, including the Coffeyville refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), the Wynnewoodrefinery and the nitrogen fertilizer plant, have environmental contamination. We have assumed Farmland's responsibilities under certain administrative ordersunder the RCRA related to contamination at or that originated from the Coffeyville refinery and the Phillipsburg terminal. The Coffeyville refinery hasagreed to assume liability for contamination that migrated from the refinery onto the nitrogen fertilizer plant property while Farmland owned and operatedthe properties. At the Wynnewood refinery, known areas of contamination have been partially addressed but corrective action has not been completed (referto "RCRA Compliance Matters" in Part II, Item 8, Note 13 ("Commitments and Contingencies") of this Report), and some portions of the Wynnewood refineryhave not yet been investigated to determine whether corrective action is necessary. If significant unknown liabilities are identified at or migrating from anyof 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 byinsurance.We may incur future liability relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the treatment, transportationor disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation ofcontamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposaland the damages or costs in any such proceedings could be material.33Table of ContentsWe may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.Our businesses hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Future expansion ofour operations is predicated upon securing the necessary environmental or other permits or approvals. A decision by a government agency to deny or delayissuing a new or renewed material permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effecton our ability to continue operations and on our financial condition, results of operations and cash flows. For example, WRC's OPDES permit has expired andis in the renewal process. The refinery timely submitted their renewal application; and therefore, the refinery is authorized to operate under expired permitterms and conditions until the state regulatory agency renews the permit. The renewal permit may contain different terms and conditions that would requireunplanned or unanticipated costs.Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows. The EPA regulates GHG emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs toinventory and report their GHG emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our GHG emissions to the EPA. InMay 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new GHG emissions thresholds that determine when stationary sources,such as the refineries and the nitrogen fertilizer plant, must obtain permits under PSD and Title V programs of the federal Clean Air Act. Under the rule,facilities already subject to the PSD and Title V programs that increase their emissions of GHGs by a significant amount are required to undergo PSD reviewand to evaluate and implement air pollution control technology, known as "best available control technology," to reduce GHG emissions. In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate NSPS toregulate GHG emissions from petroleum refineries and electric utilities by November 2012. In September 2014, the EPA indicated that the petroleum refiningsector risk rule, proposed in June 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for the EPA to regulateGHG emissions from petroleum refineries at this time. The final rule, which was published in the Federal Register on December 1, 2015, places additionalemission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries.Therefore, we expect that the EPA will not be issuing NSPS standards to regulate GHG from the refineries at this time but that it may do so in the future.During the State of the Union address in each of the last three years, President Obama indicated that the United States should take action to addressclimate change. At the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory GHGemission reduction, such as a nationwide cap-and-trade program. It is also possible that Congress may pass alternative climate change bills that do notmandate 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 carbon dioxide and other GHGemissions. In 2007, a group of Midwest states, including Kansas (where the Coffeyville refinery and the nitrogen fertilizer facility are located), formed theMidwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory ofsuch emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before itbecomes effective. To date, Kansas has taken no meaningful action to implement the accord, and it's unclear whether Kansas intends to do so in the future. Alternatively, the EPA may take further steps to regulate GHG emissions. The implementation of EPA regulations and/or the passage of federal or stateclimate change legislation may result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and(iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any current or future legislation or regulation ofGHG 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 and fertilizerproducts, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results ofoperations, financial condition and cash flows. 34Table of ContentsWe are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have amaterial adverse effect on our results of operations, financial condition and profitability.We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the properdesign, operation and maintenance of our equipment. In addition, OSHA and certain environmental regulations require that we maintain information abouthazardous 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 occupationalexposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations,financial condition and cash flows.We are subject to cybersecurity risks and other cyber incidents resulting in disruption. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. We depend oninformation technology systems. In addition, we collect, process and retain sensitive and confidential customer information in the normal course of business.Despite the security measures we have in place and any additional measures we may implement in the future, our facilities and systems, and those of ourthird-party service providers, could be vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, human errors, acts ofvandalism or other events. Any disruption of our systems or security breach or event resulting in the misappropriation, loss or other unauthorized disclosureof confidential information, whether by us directly or our third-party service providers, could damage our reputation, expose us to the risks of litigation andliability, disrupt our business or otherwise affect our results of operations.Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or thepublic 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, reducingour operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffersubstantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operationsmore difficult or costly. The consequences of any such actions could adversely affect our operating results, financial condition and cash flows.Both the petroleum and nitrogen fertilizer businesses depend on significant customers and the loss of several significant customers may have a materialadverse impact on our results of operations, financial condition and cash flows.The petroleum and nitrogen fertilizer businesses both have a significant concentration of customers. The five largest customers of the petroleum businessrepresented 39% of its petroleum net sales for the year ended December 31, 2015. The five largest customers of the nitrogen fertilizer business alsorepresented approximately 39% of its net sales for the year ended December 31, 2015. One significant petroleum customer and two significant nitrogenfertilizer customers each account for more than 10% of petroleum and nitrogen fertilizer net sales. Given the nature of our businesses, and consistent withindustry practice, we do not have long-term minimum purchase contracts with our customers. The loss of several of these significant customers, or asignificant reduction in purchase volume by several of them, could have a material adverse effect on our results of operations, financial condition and cashflows.The acquisition and expansion strategy of the petroleum business and the nitrogen fertilizer business involves significant risks.Both the petroleum business and the nitrogen fertilizer business will consider pursuing acquisitions and expansion projects in order to continue to growand increase profitability. However, we may not be able to consummate such acquisitions or expansions, due to intense competition for suitable acquisitiontargets, the potential unavailability of financial resources necessary to consummate acquisitions and expansions, difficulties in identifying suitableacquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms and the failure to obtain requisiteregulatory or other governmental approvals. In addition, any future acquisitions and expansions may entail significant transaction costs and risks associatedwith 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 ofacquired entities can involve significant difficulties, such as:•unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business;35Table of Contents•failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition;•strain on the operational and managerial controls and procedures of the petroleum business and the nitrogen fertilizer business, and the need tomodify systems or to add management resources;•difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations ortechnologies;•assumption of unknown material liabilities or regulatory non-compliance issues;•amortization of acquired assets, which would reduce future reported earnings;•possible adverse short-term effects on our cash flows or operating results; and•diversion of management's attention from the ongoing operations of our business.In addition, in connection with any potential acquisition or expansion project, each of the Refining Partnership and the Nitrogen Fertilizer Partnership(as applicable) will need to consider whether a business it intends to acquire or expansion project it intends to pursue could affect its tax treatment as apartnership for federal income tax purposes. If the petroleum business or the nitrogen fertilizer business is otherwise unable to conclude that the activities ofthe business being acquired or the expansion project would not affect its treatment as a partnership for federal income tax purposes, it may elect to seek aruling from the Internal Revenue Service ("IRS"). Seeking such a ruling could be costly or, in the case of competitive acquisitions, place the business in acompetitive disadvantage compared to other potential acquirers who do not seek such a ruling. If the petroleum business or the nitrogen fertilizer business isunable to conclude that an activity would not affect its treatment as a partnership for federal income tax purposes, and is unable or unwilling to obtain an IRSruling, the petroleum business or the nitrogen fertilizer business may choose to acquire such business or develop such expansion project in a corporatesubsidiary, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of cash available for distributionto its unitholders and would likely cause a substantial reduction in the value of its common units.Failure to manage these acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition andcash flows. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generatepositive cash flow at any acquired company or expansion project.We are a holding company and depend upon our subsidiaries for our cash flow.Our two principal subsidiaries are publicly traded partnerships, and a portion of their common units trade on the NYSE. We are a holding company, andthese subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations orto pay dividends or make other distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries tous in the form of distributions on their common units. The ability of the Refining Partnership and the Nitrogen Fertilizer Partnership to make any payments tous will depend on, among other things, their earnings, the terms of their indebtedness, tax considerations and legal restrictions.In particular, the indenture governing the Refining Partnership's 6.5% senior notes prohibits it from making distributions to unitholders (including us) ifany default or event of default (as defined in the indenture) exists. In addition, the indenture governing the Refining Partnership's 6.5% senior notes containscovenants limiting the Refining Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on the RefiningPartnership's fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, the Refining Partnershipwill generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed chargecoverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to itsunitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. In addition, theRefining Partnership's Amended and Restated ABL Credit Facility requires it to maintain a minimum excess availability under the facility as a condition tothe payment of distributions to its unitholders. The Nitrogen Fertilizer Partnership's credit facility requires that, before the Nitrogen Fertilizer36Table of ContentsPartnership can make distributions to us, it must be in compliance with leverage ratio and interest coverage ratio tests. Any new indebtedness could havesimilar or greater restrictions.Internally generated cash flows and other sources of liquidity may not be adequate for the capital needs of our businesses.Our businesses are capital intensive, and working capital needs may vary significantly over relatively short periods of time. For instance, crude oil pricevolatility can significantly impact working capital on a week-to-week and month-to-month basis. If we cannot generate adequate cash flow or otherwisesecure 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 debtobligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business andresults of operations.A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disruptour business and increase our costs.As of December 31, 2015, approximately 54% of the employees at the Coffeyville refinery and 59% of the employees at the Wynnewood refinery wererepresented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with five Metal Trades Unions(which covers union represented employees who work directly at the Coffeyville refinery) expires in March 2019. The collective bargaining agreement withthe United Steelworkers (which covers the balance of the petroleum business' unionized employees, who work in crude transportation) expires in March2017, and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. Thecollective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2017. We maynot 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. Inaddition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage couldnegatively affect our results of operations, financial condition and cash flows.Our business may suffer if any of our key senior executives or other key employees unexpectedly discontinues employment with us. Furthermore, ashortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.Our future success depends to a large extent on the services of our key senior executives and key senior employees. Our business depends on ourcontinuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, financeand other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multipletasks. In particular, the nitrogen fertilizer facility relies on gasification technology that requires special expertise to operate efficiently and effectively. Thecompetition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other keypersonnel resign unexpectedly or become unable to continue in their present roles and are not adequately replaced, our business operations could bematerially adversely affected. We do not maintain any "key man" life insurance for any executives.New regulations concerning the transportation, storage and handling of hazardous chemicals, risks of terrorism and the security of chemicalmanufacturing facilities could result in higher operating costs.The costs of complying with future regulations relating to the transportation, storage and handling of hazardous chemicals and security associated withthe refining and nitrogen fertilizer facilities may have a material adverse effect on our results of operations, financial condition and cash flows. Targets suchas refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, thepetroleum and chemical industries have responded to the issues that arose due to the terrorist attacks on September 11, 2001 by starting new initiativesrelating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terroristattacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition andcash flows. The 2013 fertilizer plant explosion in West, Texas has generated consideration of more restrictive measures in storage, handling andtransportation of crop production materials, including fertilizers. Compliance with and changes in the tax laws could adversely affect our performance.We are subject to extensive tax liabilities, including United States and state income taxes and transactional taxes such as excise, sales/use, payroll,franchise and withholding taxes. New tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for taxliabilities in the future.37Table of ContentsThe Refining Partnership's and the Nitrogen Fertilizer Partnership's level of indebtedness may increase, which would reduce their financial flexibilityand the distributions they make on their common units.As of the date of this Report, the Refining Partnership had (i) $500.0 million aggregate principal amount of 6.5% senior notes due 2022 (the "2022Notes") outstanding, (ii) availability under the Amended and Restated ABL Credit Facility of $262.1 million, with letters of credit outstanding ofapproximately $27.8 million and (iii) $31.5 million borrowed under an intercompany credit facility with availability under the intercompany credit facilityof $218.5 million. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions. As of the date of this Report,the Nitrogen Fertilizer Partnership had $125.0 million of outstanding term loan borrowings, with availability of up to $25.0 million under its revolving creditfacility. In the future, the Refining Partnership and the Nitrogen Fertilizer Partnership may incur additional significant indebtedness in order to make futureacquisitions, expand their businesses or develop their properties. Their level of indebtedness could affect their operations in several ways, including thefollowing:•a significant portion of their cash flows could be used to service their indebtedness, reducing available cash and their ability to makedistributions on their common units (including distributions to us);•a high level of debt would increase their vulnerability to general adverse economic and industry conditions;•the covenants contained in their debt agreements will limit their ability to borrow additional funds, dispose of assets, pay distributions andmake certain investments;•a high level of debt may place them at a competitive disadvantage compared to competitors that are less leveraged and who therefore may beable to take advantage of opportunities that their indebtedness would prevent them from pursuing;•their debt covenants may also affect flexibility in planning for, and reacting to, changes in the economy and in their industries;•a high level of debt may make it more likely that a reduction in the petroleum business' borrowing base following a periodic redeterminationcould require the Refining Partnership to repay a portion of its then-outstanding bank borrowings under its ABL credit facility; and•a high level of debt may impair their ability to obtain additional financing in the future for working capital, capital expenditures, debt servicerequirements, acquisitions, general corporate or other purposes.In addition, borrowings under their respective credit facilities and other credit facilities they may enter into in the future will bear interest at variablerates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect their ability to makedistributions to common unitholders (including us).In addition to debt service obligations, their operations require substantial investments on a continuing basis. Their ability to make scheduled debtpayments, to refinance debt obligations and to fund capital and non-capital expenditures necessary to maintain the condition of operating assets, propertiesand systems software, as well as to provide capacity for the growth of their businesses, depends on their respective financial and operating performance.General economic conditions and financial, business and other factors affect their operations and their future performance. Many of these factors are beyondtheir control. They may not be able to generate sufficient cash flows to pay the interest on their debt, and future working capital, borrowings or equityfinancing may not be available to pay or refinance such debt.In addition, the bank borrowing base under the Refining Partnership's Amended and Restated ABL Credit Facility will be subject to periodicredeterminations. It could be forced to repay a portion of its bank borrowings due to redeterminations of its borrowing base. If it is forced to do so, it may nothave sufficient funds to make such repayments. If the Refining Partnership does not have sufficient funds and is otherwise unable to negotiate renewals of itsborrowings or arrange new financing, it may have to sell significant assets. Any such sale could have a material adverse effect on the Refining Partnership'sbusiness and financial condition and, as a result, its ability to make distributions to common unitholders (including us).38Table of ContentsThe Refining Partnership and the Nitrogen Fertilizer Partnership may not be able to generate sufficient cash to service all of their indebtedness and maybe forced to take other actions to satisfy their debt obligations that may not be successful.The Refining Partnership's and the Nitrogen Fertilizer Partnership's ability to satisfy their debt obligations will depend upon, among other things:•their future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatoryand other factors, many of which are beyond our control; and•the Refining Partnership's ability to borrow under its Amended and Restated ABL Credit Facility and the intercompany credit facility betweenthe Refining Partnership and us, and the Nitrogen Fertilizer Partnership's ability to borrow under its revolving credit facility, the availability ofwhich depends on, among other things, compliance with their respective covenants.We cannot offer any assurance that our businesses will generate sufficient cash flow from operations, or that the Refining Partnership will be able to drawunder its Amended and Restated ABL Credit Facility or the intercompany credit facility, or that the Nitrogen Fertilizer Partnership will be able to draw underits revolving credit facility, or from other sources of financing, in an amount sufficient to fund their respective liquidity needs.If cash flows and capital resources are insufficient to service their indebtedness, the Refining Partnership or the Nitrogen Fertilizer Partnership may beforced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance their indebtedness. These alternative measuresmay not be successful and may not permit them to meet their scheduled debt service obligations. Their ability to restructure or refinance debt will depend onthe condition of the capital markets and their financial condition at such time. Any refinancing of their debt could be at higher interest rates and may requirethem to comply with more onerous covenants, which could further restrict their business operations, and the terms of existing or future debt agreements mayrestrict us from adopting some of these alternatives. In addition, in the absence of adequate cash flows or capital resources, they could face substantialliquidity problems and might be required to dispose of material assets or operations, or sell equity, in order to meet their debt service and other obligations.They may not be able to consummate those dispositions for fair market value or at all. The Refining Partnership's Amended and Restated ABL Credit Facilityand the indenture governing its 6.5% senior notes and the Nitrogen Fertilizer Partnership's credit facility may restrict, or market or business conditions maylimit, their ability to avail themselves of some or all of these options. Furthermore, any proceeds that we realize from any such dispositions may not beadequate to meet their debt service obligations when due. None of the Company's stockholders or any of their respective affiliates has any continuingobligation to provide us with debt or equity financing.The borrowings under the Refining Partnership's Amended and Restated ABL Credit Facility and intercompany credit facility and the Nitrogen FertilizerPartnership's revolving credit facility bear interest at variable rates and other debt we or they incur could likewise be variable-rate debt. If market interest ratesincrease, variable-rate debt will create higher debt service requirements, which could adversely affect their respective distributions to us. The RefiningPartnership or the Nitrogen Fertilizer Partnership may enter into agreements limiting their exposure to higher interest rates, but any such agreements may notoffer complete protection from this risk.Covenants in our subsidiaries' debt instruments could limit their ability to incur additional indebtedness and engage in certain transactions, whichcould adversely affect our liquidity and our ability to pursue our business strategies.The indenture governing the Refining Partnership's 2022 Notes and the Amended and Restated ABL Credit Facility and the Nitrogen FertilizerPartnership's credit facility contain a number of restrictive covenants that will impose significant operating and financial restrictions on them and theirsubsidiaries and may limit their ability to engage in acts that may be in their long-term best interest, including restrictions on their ability, among otherthings, to:•incur, assume or guarantee additional debt or issue redeemable or preferred units•make distributions or prepay, redeem, or repurchase certain debt;•enter into agreements that restrict distributions from restricted subsidiaries;•incur liens;39Table of Contents•sell or otherwise dispose of assets, including capital stock of subsidiaries;•enter into transactions with affiliates; and•merge, consolidate or sell substantially all of their assets.In particular, the indenture governing the Refining Partnership's 2022 Notes prohibits it from making distributions to unitholders (including us) if anydefault or event of default (as defined in the indenture) exists. In addition, the indenture governing the Refining Partnership's 2022 Notes contains covenantslimiting the Refining Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on the Refining Partnership'sfixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, the Refining Partnership will generallybe permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is lessthan 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, up to anaggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. In addition, the Refining Partnership'sAmended and Restated ABL Credit Facility requires it to maintain a minimum excess availability under the facility as a condition to the payment ofdistributions to its unitholders. The Nitrogen Fertilizer Partnership's credit facility requires that, before the Nitrogen Fertilizer Partnership can makedistributions to us, it must be in compliance with leverage ratio and interest coverage ratio tests. Any new indebtedness could have similar or greaterrestrictions.A breach of the covenants under the foregoing debt instruments could result in an event of default. Upon a default, unless waived, the holders of theRefining Partnership's 2022 Notes and lenders under the Refining Partnership's Amended and Restated ABL Credit Facility and the Nitrogen FertilizerPartnership's credit facility would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans,institute foreclosure proceedings against the Refining Partnership or the Nitrogen Fertilizer Partnership (as applicable) or its respective subsidiaries' assets,and force it and its subsidiaries into bankruptcy or liquidation, subject to intercreditor agreements. In addition, any defaults could trigger cross defaults underother or future credit agreements or indentures. The Refining Partnership's or Nitrogen Fertilizer Partnership's operating results may not be sufficient toservice their indebtedness or to fund our other expenditures and they may not be able to obtain financing to meet these requirements. As a result of theserestrictions, they may be limited in how they conduct their respective businesses, unable to raise additional debt or equity financing to operate duringgeneral economic or business downturns or unable to compete effectively or to take advantage of new business opportunities.Despite their indebtedness, the Refining Partnership and the Nitrogen Fertilizer Partnership may still be able to incur significantly more debt, includingsecured indebtedness. This could intensify the risks described above.The Refining Partnership and the Nitrogen Fertilizer Partnership may be able to incur substantially more debt in the future, including securedindebtedness. Although the Refining Partnership's Amended and Restated ABL Credit Facility and its 2022 Notes and the Nitrogen Fertilizer Partnership'scredit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptionsand, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions may not preventthem from incurring obligations that do not constitute indebtedness. To the extent such new debt or new obligations are added to their existing indebtedness,the risks described above could substantially increase.Mr. Carl C. Icahn exerts significant influence over the Company and his interests may conflict with the interest of the Company's other stockholders.Mr. Carl C. Icahn indirectly controls approximately 82% of the voting power of the Company's capital stock and, by virtue of such stock ownership, isable to control or exert substantial influence over the Company, including:•the election and appointment of directors;•business strategy and policies;•mergers or other business combinations;•acquisition or disposition of assets;•future issuances of common stock, common units or other securities;40Table of Contents•incurrence of debt or obtaining other sources of financing; and•the payment of dividends on the Company's common stock and distributions on the common units of the Refining Partnership and the NitrogenFertilizer Partnership.The existence of a controlling stockholder may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquirea majority of the Company's outstanding common stock, which may adversely affect the market price of the Company's common stock.Mr. Icahn's interests may not always be consistent with the Company's interests or with the interests of the Company's other stockholders. Mr. Icahn andentities controlled by him may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that anyadditional business opportunities be presented to us. We also have and may in the future enter into transactions to purchase goods or services with affiliatesof Mr. Icahn. To the extent that conflicts of interest may arise between the Company and Mr. Icahn and his affiliates, those conflicts may be resolved in amanner adverse to the Company or its other stockholders.In addition, if Mr. Icahn were to sell, or otherwise transfer, some or all of his interests in us to an unrelated party or group, a change of control could bedeemed to have occurred under the terms of the indentures governing the Refining Partnership's 6.5% senior notes, which would require it to offer torepurchase all outstanding notes at 101% of their principal amount plus accrued interest to the date of repurchase, and an event of default could be deemed tohave occurred under the Refining Partnership's Amended and Restated ABL Credit Facility, which would allow lenders to accelerate indebtedness owed tothem. However, it is possible that the Refining Partnership will not have sufficient funds at the time of the change of control to make the required repurchaseof notes or repay amounts outstanding under the Refining Partnership's Amended and Restated ABL Credit Facility, if any.The Company's common stock price may decline due to sales of shares by Mr. Carl C. Icahn.Sales of substantial amounts of the Company's common stock, or the perception that these sales may occur, may adversely affect the price of theCompany's common stock and impede its ability to raise capital through the issuance of equity securities in the future. Mr. Icahn could elect in the future torequest that the Company file a registration statement to enable him to sell shares of the Company's common stock. If Mr. Icahn were to sell a large number ofshares into the public markets, Mr. Icahn could cause the price of the Company's common stock to decline.We are a "controlled company" within the meaning of the NYSE rules and, as a result, qualify for, and are relying on, exemptions from certaincorporate governance requirements.A company of which more than 50% of the voting power is held by an individual, a group or another company is a "controlled company" within themeaning of the NYSE rules and may elect not to comply with certain corporate governance requirements of the NYSE, including:•the requirement that a majority of our board of directors consist of independent directors;•the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors; and•the requirement that we have a compensation committee that is composed entirely of independent directors.We are relying on all of these exemptions as a controlled company. Accordingly, you may not have the same protections afforded to stockholders ofcompanies that are subject to all of the corporate governance requirements of the NYSE. In addition, both the Refining Partnership and the Nitrogen FertilizerPartnership are relying on exemptions from the same NYSE corporate governance requirements described above.We may be subject to the pension liabilities of our affiliates. Mr. Icahn, through certain affiliates, owns approximately 82% of the Company's capital stock. Applicable pension and tax laws make each member of a“controlled group” of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable forcertain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well asliability for any unfunded liabilities that may exist at the time the plan is terminated. In addition, the failure to pay these pension obligations when due mayresult in41Table of Contentsthe creation of liens in favor of the pension plan or the Pension Benefit Guaranty Corporation ("PBGC") against the assets of each member of the controlledgroup.As a result of the more than 80% ownership interest in us by Mr. Icahn's affiliates, we are subject to the pension liabilities of all entities in which Mr.Icahn has a direct or indirect ownership interest of at least 80%. Two such entities, ACF Industries LLC ("ACF") and Federal-Mogul, are the sponsors ofseveral pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by thePension Protection Act of 2006, for these plans have been met as of December 31, 2015. If the ACF and Federal-Mogul plans were voluntarily terminated,they would be collectively underfunded by approximately $589.2 million and $473.8 million as of December 31, 2015 and 2014, respectively. These resultsare based on the most recent information provided to us by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities couldincrease or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate theliability. As members of the controlled group, we would be liable for any failure of ACF and Federal-Mogul to make ongoing pension contributions or to paythe unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group thatincludes us may have pension plan obligations that are, or may become, underfunded, and we would be liable for any failure of such entities to make ongoingpension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogulpension plans requires such entities to notify the PBGC of certain "reportable events," such as if we cease to be a member of the controlled group, or if wemake certain extraordinary dividends or stock redemptions. The obligation to report could cause us to seek to delay or reconsider the occurrence of suchreportable events.Risks Related to Our Common StockWe have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders' ability to sell their shares for apremium in a change of control transaction.Various provisions of our certificate of incorporation and bylaws and of Delaware corporate law may discourage, delay or prevent a change in control ortakeover attempt of our Company by a third party that our management and board of directors determines is not in the best interest of our Company and itsstockholders. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisionscould substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. Theseprovisions include:•preferred stock that could be issued by our board of directors to make it more difficult for a third party to acquire, or to discourage a third partyfrom acquiring, a majority of our outstanding voting stock;•limitations on the ability of stockholders to call special meetings of stockholders;•limitations on the ability of stockholders to act by written consent in lieu of a stockholders' meeting; and•advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted uponby our stockholders at stockholder meetings.We are authorized to issue up to a total of 350 million shares of common stock and 50 million shares of preferred stock, potentially diluting equityownership of current holders and the share price of our common stock.We believe that it is necessary to maintain a sufficient number of available authorized shares of our common stock and preferred stock in order to provideus with the flexibility to issue common stock or preferred stock for business purposes that may arise as deemed advisable by our board of directors. Thesepurposes could include, among other things, (i) future stock dividends or stock splits, which may increase the liquidity of our shares; (ii) the sale of stock toobtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt if needed; (iii) foruse in additional stock incentive programs and (iv) for other bona fide purposes. Our board of directors may authorize the Company to issue the availableauthorized shares of common stock or preferred stock without notice to, or further action by, our stockholders, unless stockholder approval is required by lawor the rules of the NYSE. The issuance of additional shares of common stock or preferred stock may significantly dilute the equity ownership of the currentholders of our common stock.42Table of ContentsOur ability to pay dividends on our common stock is subject to market conditions and numerous other factors.In January 2013, our board of directors adopted a quarterly dividend policy. We began paying regular quarterly dividends in the second quarter of 2013.Dividends are subject to change at the discretion of the board of directors and may change from quarter to quarter. Our ability to continue paying dividends issubject to our ability to continue to generate sufficient cash flow, and the amount of dividends we are able to pay each year may vary, possibly substantially,based on market conditions, crack spreads, our capital expenditure and other business needs, covenants contained in any debt agreements we may enter intoin the future, covenants contained in the debt agreements of CVR Partners and CVR Refining, and the amount of distributions we receive from CVR Partnersand CVR Refining. We may not be able to continue paying dividends at the rate we currently pay dividends, or at all. If the amount of our dividendsdecreases, the trading price of our common stock could be materially adversely affected as a result.Risks Inherent In the Limited Partnership Structures Through WhichWe Currently Hold Our Interests in the Refinery Business and the Nitrogen Fertilizer BusinessBoth the Refining Partnership and the Nitrogen Fertilizer Partnership have in place policies to distribute an amount equal to the "available cash" eachgenerates each quarter, which could limit their ability to grow and make acquisitions.The current policies of both the board of directors of the Refining Partnership's general partner and the Nitrogen Fertilizer Partnership's general partner isto distribute an amount equal to the available cash generated by each partnership each quarter to their respective unitholders. As a result of their respectivecash distribution policies, the Refining Partnership and the Nitrogen Fertilizer Partnership will rely primarily upon external financing sources, includingcommercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As such, to the extentthey are unable to finance growth externally, their respective cash distribution policies will significantly impair their ability to grow. The board of directorsof the general partner of either the Refining Partnership or the Nitrogen Fertilizer Partnership may modify or revoke its cash distribution policy at any time atits discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash they generate.Each board of directors will determine the cash distribution policy it deems advisable for them on an independent basis.In addition, because of their respective distribution policies, their growth, if any, may not be as robust as that of businesses that reinvest their availablecash to expand ongoing operations. To the extent either issues additional units in connection with any acquisitions or expansion capital expenditures or asin-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount eachdistributes in respect of each of its outstanding units. There are no limitations in their respective partnership agreements on either the Refining Partnership'sor the Nitrogen Fertilizer Partnership's ability to issue additional units, including units ranking senior to the outstanding common units. The incurrence ofadditional commercial borrowings or other debt to finance their growth strategy would result in increased interest expense, which, in turn, would reduce theavailable cash they have to distribute to unitholders (including us).Each of the Refining Partnership and the Nitrogen Fertilizer Partnership may not have sufficient available cash to pay any quarterly distribution ontheir respective common units. Furthermore, neither is required to make distributions to holders of its common units on a quarterly basis or otherwise,and both may elect to distribute less than all of their respective available cash.Either or both of the Refining Partnership or the Nitrogen Fertilizer Partnership may not have sufficient available cash each quarter to enable thepayment of distributions to common unitholders. The Refining Partnership and the Nitrogen Fertilizer Partnership are separate public companies, andavailable cash generated by one of them will not be used to make distributions to common unitholders of the other. Furthermore, their respective partnershipagreements do not require either to pay distributions on a quarterly basis or otherwise. The board of directors of the general partner of either the RefiningPartnership or the Nitrogen Fertilizer Partnership may at any time, for any reason, change its cash distribution policy or decide not to make any distribution.The amount of cash they will be able to distribute in respect of their common units principally depends on the amount of cash they generate from operations,which is directly dependent upon the margins each business generates. Please see "— Risks Related to the Petroleum Business — The price volatility ofcrude oil and other feedstocks, refined products and utility services may have a material adverse effect on our profitability and our ability to pay distributionsto unitholders" and "— Risks Related to the Nitrogen Fertilizer Business — The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical andhighly volatile, and the nitrogen fertilizer business has experienced substantial downturns in the past. Cycles in demand and pricing could potentiallyexpose the nitrogen fertilizer business to significant fluctuations in its operating and financial results and have a material adverse effect on our results ofoperations, financial condition and cash flows."43Table of ContentsIf either the Refining Partnership or the Nitrogen Fertilizer Partnership were to be treated as a corporation, rather than as a partnership, for U.S. federalincome tax purposes or if either partnership were otherwise subject to entity-level taxation, such entity's cash available for distribution to its commonunitholders, including to us, would be reduced, likely causing a substantial reduction in the value of such entity's common units, including the commonunits held by us.Current law requires the Refining Partnership and the Nitrogen Fertilizer Partnership to derive at least 90% of their respective annual gross income fromcertain specified activities in order to continue to be treated as a partnership, rather than as a corporation, for U.S. federal income tax purposes. One or both ofthem may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement. If either theRefining Partnership or the Nitrogen Fertilizer Partnership were to be treated as a corporation for U.S. federal income tax purposes, they would pay U.S.federal income tax on all of their taxable income at the corporate tax rate, which is currently a maximum of 35%, they would likely pay additional state andlocal income taxes at varying rates, and distributions to their common unitholders, including to us, would generally be taxed as corporate distributions.If the Refining Partnership and the Nitrogen Fertilizer Partnership were to be treated as corporations, rather than as partnerships, for U.S. federal incometax purposes or if they were otherwise subject to entity-level taxation, their cash available for distribution to their common unitholders, including to us, andthe value of their common units, including the common units held by us, could be substantially reduced.Increases in interest rates could adversely impact the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units and theRefining Partnership's or the Nitrogen Fertilizer Partnership's ability to issue additional equity to make acquisitions, incur debt or for other purposes.We expect that the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units will be impacted by the level of the RefiningPartnership's or the Nitrogen Fertilizer Partnership's quarterly cash distributions and implied distribution yield. The distribution yield is often used byinvestors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect theyield requirements of investors who invest in the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units, and a rising interest rateenvironment could have a material adverse impact on the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units (andtherefore the value of our investment in the Refining Partnership and/or the Nitrogen Fertilizer Partnership) as well as the Refining Partnership's or theNitrogen Fertilizer Partnership's ability to issue additional equity to make acquisitions or to incur debt.We may have liability to repay distributions that are wrongfully distributed to us.Under certain circumstances, we may, as a holder of common units in the Refining Partnership and the Nitrogen Fertilizer Partnership, have to repayamounts wrongfully returned or distributed to us. Under the Delaware Revised Uniform Limited Partnership Act, a partnership may not make distributions toits unitholders if the distribution would cause its liabilities to exceed the fair value of its assets. Delaware law provides that for a period of three years from thedate of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delawarelaw will be liable to the company for the distribution amount.Public investors own approximately 47% of the nitrogen fertilizer business through the Nitrogen Fertilizer Partnership and approximately 34% of thepetroleum business through the Refining Partnership. Although we own the majority of the common units and the general partner of both the RefiningPartnership and the Nitrogen Fertilizer Partnership, the general partners owe a duty of good faith to public unitholders, which could cause them tomanage their respective businesses differently than if there were no public unitholders.Public investors own approximately 47% of the Nitrogen Fertilizer Partnership's common units and approximately 34% of the Refining Partnership'scommon units. We are not entitled to receive all of the cash generated by the nitrogen fertilizer business or the petroleum business or freely transfer moneyfrom the nitrogen fertilizer business to finance operations at the petroleum business or vice versa. Furthermore, although we continue to own the majority ofthe common units and the general partner of both the Refining Partnership and the Nitrogen Fertilizer Partnership, the general partners are subject to certainfiduciary duties, which may require the general partners to manage their respective businesses in a way that may differ from our best interests.44Table of ContentsThe general partners of the Refining Partnership and the Nitrogen Fertilizer Partnership have limited their liability, replaced default fiduciary dutiesand restricted the remedies available to common unitholders, including us, for actions that, without these limitations and reductions might otherwiseconstitute breaches of fiduciary duty.The respective partnership agreements of the Refining Partnership and the Nitrogen Fertilizer Partnership limit the liability and replace the fiduciaryduties of their respective general partner, while also restricting the remedies available to each partnership's common unitholders, including us, for actionsthat, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions offiduciary duty. The partnership agreements contain provisions that replace the standards to which each general partner would otherwise be held by statefiduciary duty law. For example:•The partnership agreements permit each partnership's general partner to make a number of decisions in its individual capacity, as opposed to itscapacity as general partner. This entitles its general partner to consider only the interests and factors that it desires, and means that it has no dutyor obligation to give any consideration to any interest of, or factors affecting, any limited partner.•The partnership agreements provide that each partnership's general partner will not have any liability to unitholders for decisions made in itscapacity as general partner so long as (i) in the case of the Nitrogen Fertilizer Partnership, it acted in good faith, meaning it believed that thedecision was in the best interest of the Nitrogen Fertilizer Partnership and (ii) in the case of the Refining Partnership, it did not make suchdecisions in bad faith, meaning it believed that the decisions were adverse to the Refining Partnership's interests.•The partnership agreements provide that each partnership's general partner and the officers and directors of its general partner will not be liablefor monetary damages to common unitholders, including us, for any acts or omissions unless there has been a final and non-appealablejudgment entered by a court of competent jurisdiction determining that (i) in the case of the Nitrogen Fertilizer Partnership, the general partneror its officers or directors acted in bad faith or engaged in fraud or willful misconduct, or in, the case of a criminal matter, acted with knowledgethat the conduct was criminal and (ii) in the case of the Refining Partnership, such losses or liabilities were the result of the conduct of ourgeneral partner or such officer or director engaged in by it in bad faith or with respect to any criminal conduct, with the knowledge that itsconduct was unlawful.In addition, the Refining Partnership's partnership agreement provides that its general partner will not be in breach of its obligations thereunder or itsduties to the Refining Partnership or its limited partners if a transaction with an affiliate or the resolution of a conflict of interest is either (i) approved by theconflicts committee of its board of directors of the general partner, although the general partner is not obligated to seek such approval; or (ii) approved by thevote of a majority of the outstanding units, excluding any units owned by the general partner and its affiliates. In addition, the Nitrogen FertilizerPartnership's partnership agreement (i) generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflictscommittee of the board of directors of its general partner and not involving a vote of unitholders must be on terms no less favorable to the Nitrogen FertilizerPartnership than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to the Nitrogen Fertilizer Partnership,as determined by its general partner in good faith, and that, in determining whether a transaction or resolution is "fair and reasonable," the general partnermay consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficialto affiliated parties, including us and (ii) provides that in resolving conflicts of interest, it will be presumed that in making its decision, the general partner orits conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any holder of common units, the person bringing or prosecutingsuch proceeding will have the burden of overcoming such presumption.With respect to the common units that we own, we have agreed to be bound by the provisions set forth in each partnership agreement, including theprovisions described above.The Refining Partnership and the Nitrogen Fertilizer Partnership are managed by the executive officers of their general partners, some of whom areemployed by and serve as part of the senior management team of the Company. Conflicts of interest could arise as a result of this arrangement.The Refining Partnership and the Nitrogen Fertilizer Partnership is each managed by the executive officers of their general partners, some of whom areemployed by and serve as part of the senior management team of the Company. Furthermore, although both the Refining Partnership and the NitrogenFertilizer Partnership have entered into services agreements with the Company under which they compensate the Company for the services of itsmanagement, the Company's management is not required to devote any specific amount of time to the petroleum business or the nitrogen fertilizer businessand may devote a45Table of Contentssubstantial majority of their time to the business of the Company. Moreover the Company may terminate the services agreement with the RefiningPartnership and/or the Nitrogen Fertilizer Partnership at any time, in each case subject to a 180-day notice period. In addition, key executive officers of theCompany, including its president and chief executive officer, chief financial officer and general counsel, will face conflicts of interest if decisions arise inwhich the Refining Partnership or the Nitrogen Fertilizer Partnership and the Company have conflicting points of view or interests.Item 1B. Unresolved Staff CommentsNone.Item 2. PropertiesThe following table contains certain information regarding our principal properties:Location Acres Own/Lease UseCoffeyville, KS 440 Own Refining Partnership: oil refinery and office buildings Nitrogen Fertilizer Partnership: fertilizer plantWynnewood, OK 400 Own Oil refinery, office buildings, refined oil storageMontgomery County, KS (Coffeyville Station) 20 Own Crude oil storageMontgomery County, KS (Broome Station) 20 Own Crude oil storageCowley County, KS (Hooser Station) 80 Own Crude oil storageCushing, OK 138 Own Crude oil storageWe also lease property for our executive office which is located at 2277 Plaza Drive in Sugar Land, Texas. Additionally, other corporate office space isleased in Kansas City, Kansas.As of December 31, 2015, the petroleum business owns crude oil storage capacity of approximately (i) 1.5 million barrels that supports the gatheringsystem and the Coffeyville refinery, (ii) 0.9 million barrels at the Wynnewood refinery and (iii) 1.5 million barrels in Cushing, Oklahoma. The petroleumbusiness leases additional crude oil storage capacity of approximately (iv) 2.8 million barrels in Cushing, (v) 0.2 million barrels in Duncan, Oklahoma and(vi) 0.1 million barrels at the Wynnewood refinery. In addition to crude oil storage, the petroleum business owns over 4.5 million barrels of combined refinedproducts and feedstocks storage capacity.Item 3. Legal ProceedingsWe 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 describedunder "Business — Environmental Matters." We also incorporate by reference into this Part I, Item 3 of this Report, the information regarding the lawsuits andproceedings described and referenced in Note 13 ("Commitments and Contingencies") to our Consolidated Financial Statements as set forth in Part II, Item 8of this Report. In accordance with Generally Accepted Accounting Principles ("GAAP"), we record a liability when it is both probable that a liability has beenincurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts ofnegotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Although we cannot predict withcertainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding orproceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.Item 4. Mine Safety DisclosuresNot applicable.46Table of ContentsPART IIItem 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity SecuritiesMarket InformationOur common stock, which is listed on the NYSE under the symbol "CVI" commenced trading on October 23, 2007. The table below sets forth, for thequarter indicated, the high and low sales prices per share of our common stock for our most recent fiscal years:2015High LowFirst Quarter$43.21 $33.02Second Quarter43.46 36.43Third Quarter43.63 36.02Fourth Quarter48.37 38.452014High LowFirst Quarter$43.96 $34.89Second Quarter51.44 41.06Third Quarter50.99 44.25Fourth Quarter49.64 36.70Holders of RecordAs of February 16, 2016, there were 127 holders of record of our common stock. Because many of our shares of common stock are held by brokers andother institutions on behalf of stockholders, we are unable to estimate the total number of beneficial owners represented by these record holders.CVR Energy, Inc. Dividend PolicyOn January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Dividends are subject to change at the discretionof the board of directors. The Company began paying regular quarterly dividends in the second quarter of 2013. Additionally, the Company declared andpaid one special cash dividend during the year ended December 31, 2014. The following is a summary of the quarterly and special dividends paid to stockholders during the years ended December 31, 2015 and 2014: December 31, 2014 March 31, 2015 June 30, 2015 September 30, 2015 Total Dividends Paid in 2015 (in millions, except per share data)Dividend typeQuarterly Quarterly Quarterly Quarterly Amount paid to IEP$35.6 $35.6 $35.6 $35.6 $142.4Amounts paid to public stockholders7.8 7.8 7.8 7.8 31.3Total amount paid$43.4 $43.4 $43.4 $43.4 $173.7Per common share$0.50 $0.50 $0.50 $0.50 $2.00Shares outstanding86.8 86.8 86.8 86.8 47Table of Contents December 31, 2013 March 31, 2014 June 30, 2014 July 17, 2014 September 30, 2014 Total DividendsPaid in 2014 (in millions, except per share data)Dividend typeQuarterly Quarterly Quarterly Special Quarterly Amount paid to IEP$53.4 $53.4 $53.4 $142.4 $53.4 $356.0Amounts paid to publicstockholders11.7 11.7 11.7 31.3 11.7 78.2Total amount paid$65.1 $65.1 $65.1 $173.7 $65.1 $434.2Per common share$0.75 $0.75 $0.75 $2.00 $0.75 $5.00Shares outstanding86.8 86.8 86.8 86.8 86.8 On February 17, 2016, the board of directors of the Company declared a cash dividend for the fourth quarter of 2015 to the Company's stockholders of$0.50 per share, or $43.4 million in aggregate. The dividend will be paid on March 7, 2016 to stockholders of record at the close of business on February 29,2016.Our ability to pay cash dividends is dependent on the ability of our subsidiaries to make distributions to us. The cash distribution policies of theNitrogen Fertilizer Partnership and the Refining Partnership are described below. Furthermore, the ability of the Nitrogen Fertilizer Partnership and theRefining Partnership to make distributions to us is limited by the Refining Partnership's Amended and Restated ABL Credit Facility and the indenturegoverning the 2022 Notes. See Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity andCapital Resources" for a discussion of those limitations. CVR Partners, LP Cash Distribution PolicyThe current policy of the board of directors of the Nitrogen Fertilizer Partnership's general partner is to distribute all available cash the Nitrogen FertilizerPartnership generates each quarter. Available cash for each quarter is determined by the board of directors of the Nitrogen Fertilizer Partnership's generalpartner following the end of such quarter, subject to the limitations discussed below. The board of directors of the Nitrogen Fertilizer Partnership's generalpartner calculates available cash for distribution starting with Adjusted Nitrogen Fertilizer EBITDA reduced for cash needed for (i) net cash interest expense(excluding capitalized interest) and debt service and other contractual obligations, (ii) maintenance capital expenditures, (iii) to the extent applicable, majorscheduled turnaround expenses and reserves for future operating or capital needs that the board of directors of the Nitrogen Fertilizer Partnership's generalpartner deems necessary or appropriate, and (iv) expenses associated with the Rentech Nitrogen mergers, if any. Available cash for distribution may beincreased by the release of previously established cash reserves, if any, at the discretion of the board of directors of the Nitrogen Fertilizer Partnership'sgeneral partner. The Nitrogen Fertilizer Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability orgrowth in its quarterly distribution or otherwise to reserve cash for distributions, nor does the Nitrogen Fertilizer Partnership intend to incur debt to payquarterly distributions. As of the date of this Report, we own approximately 53% of the Nitrogen Fertilizer Partnership's common units, and are entitled to apro rata percentage of the Nitrogen Fertilizer Partnership's distributions in respect of its common units. The board of directors of the Nitrogen FertilizerPartnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Nitrogen Fertilizer Partnership to makedistributions at all.The Merger Agreement with Rentech Nitrogen and Rentech Nitrogen GP includes customary restrictions on the conduct of the Nitrogen FertilizerPartnership's business prior to the completion of the mergers, generally requiring the Nitrogen Fertilizer Partnership to conduct its business in the ordinarycourse and subjecting the Nitrogen Fertilizer Partnership to a variety of specified limitations. In accordance with the terms of the Merger Agreement,beginning with the distribution for the third quarter of 2015 and until the closing of the mergers, the Nitrogen Fertilizer Partnership may not make or declaredistributions in excess of available cash for distribution in respect of any quarter. Refer to Part II, Item 8, Note 1 ("Organization and History of the Company")of this Report for further discussion of the pending mergers.48Table of ContentsThe following is a summary of cash distributions paid by the Nitrogen Fertilizer Partnership to unitholders during the years ended December 31, 2015and 2014 for the respective quarters to which the distributions relate: December 31, 2014 March 31, 2015 June 30, 2015 September 30, 2015 Total CashDistributionsPaid in 2015 (in millions, except per common unit data)Amount paid to CRLLC$16.0 $17.5 $15.2 $— $48.6Amounts paid to public unitholders14.0 15.4 13.3 — 42.8Total amount paid$30.0 $32.9 $28.5 $— $91.4Per common unit$0.41 $0.45 $0.39 $— $1.25Common units outstanding73.1 73.1 73.1 73.1 December 31, 2013 March 31, 2014 June 30, 2014 September 30, 2014 Total CashDistributionsPaid in 2014 (in millions, except per common unit data)Amount paid to CRLLC$16.7 $14.8 $12.8 $10.5 $54.9Amounts paid to public unitholders14.7 13.0 11.3 9.2 48.2Total amount paid$31.4 $27.8 $24.1 $19.7 $103.1Per common unit$0.43 $0.38 $0.33 $0.27 $1.41Common units outstanding73.1 73.1 73.1 73.1 On February 17, 2016, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the fourth quarter of2015 to the Nitrogen Fertilizer Partnership's unitholders of $0.27 per unit, or $19.7 million in aggregate. The cash distribution will be paid on March 7, 2016to unitholders of record at the close of business on February 29, 2016. Total cash distributions paid and to be paid based upon available cash for 2015 were$1.11 per common unit.CVR Refining, LP Cash Distribution PolicyThe current policy of the board of directors of the Refining Partnership's general partner is to distribute all of the available cash the Refining Partnershipgenerates each quarter. Available cash for each quarter will be determined by the board of directors of the Refining Partnership's general partner following theend of such quarter and will generally equal Adjusted Petroleum EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental andmaintenance capital expenditures, (iii) reserves for future major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operatingor capital needs that the board of directors of the Refining Partnership's general partner deems necessary or appropriate, if any. Available cash fordistributions may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directorsof the Refining Partnership's general partner. The Refining Partnership does not intend to maintain excess distribution coverage for the purpose ofmaintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor do they intend to incur debt to pay quarterlydistributions. Further, it is the Refining Partnership's intent, subject to market conditions, to finance growth capital externally, and not to reserve cash forunspecified potential future needs. As of the date of this Report, we own approximately 66% of the Refining Partnership's common units, and are entitled to apro rata percentage of the Refining Partnership's distributions in respect of its common units. The board of directors of the Refining Partnership's generalpartner may modify the cash distribution policy at any time, and the partnership agreement does not require the Refining Partnership to make distributions atall.49Table of ContentsThe following is a summary of cash distributions paid by the Refining Partnership to unitholders during the years ended December 31, 2015 and 2014for the respective quarters to which the distributions relate: December 31, 2014 March 31, 2015 June 30, 2015 September 30, 2015 Total CashDistributionsPaid in 2015 (in millions, except per common unit data)Amount paid to CVR Refining Holdings, LLC$36.0 $74.0 $95.4 $98.3 $303.6Amounts paid to public unitholders18.6 38.2 49.2 50.8 156.9Total amount paid$54.6 $112.2 $144.6 $149.1 $460.5Per common unit$0.37 $0.76 $0.98 $1.01 $3.12Common units outstanding147.6 147.6 147.6 147.6 December 31, 2013 March 31, 2014 June 30, 2014 September 30, 2014 Total CashDistributionsPaid in 2014 (in millions, except per common unit data)Amount paid to CVR Refining Holdings, LLC$47.1 $102.8 $93.4 $52.5 $295.8Amounts paid to public unitholders19.3 41.9 48.3 27.2 136.7Total amount paid$66.4 $144.7 $141.7 $79.7 $432.5Per common unit$0.45 $0.98 $0.96 $0.54 $2.93Common units outstanding147.6 147.6 147.6 147.6 Total cash distributions paid based upon available cash for 2015 were $2.75 per common unit.Stock Performance GraphThe following graph sets forth the cumulative return on our common stock between January 1, 2011 and December 31, 2015, as compared to thecumulative return of the Russell 2000 Index and an industry peer group consisting of Alon USA Energy, Inc., Delek US Holdings, Inc., HollyFrontierCorporation, Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. The graph assumes an investment of $100 on January 1, 2011 in ourcommon stock, the Russell 2000 Index and the industry peer group, and assumes the reinvestment of dividends where applicable. The closing market pricefor our common stock on December 31, 2015 was $39.35. The stock price performance shown on the graph is not intended to forecast and does notnecessarily indicate future price performance.50Table of ContentsCOMPARISON OF CUMULATIVE TOTAL RETURNBETWEEN JANUARY 1, 2011 AND DECEMBER 31, 2015among CVR Energy, Inc., Russell 2000 Index and a peer groupThis performance graph shall not be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under thatSection, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or theExchange Act. Jan '11 Mar '11 Jun '11 Sep '11 Dec '11 Mar '12 Jun '12 Sep '12 Dec '12 Mar '13 Jun '13CVR Energy, Inc. 100.00 149.32 158.74 136.30 120.76 172.47 171.37 236.94 314.57 367.19 376.65Russell 2000 Index100.00 105.63 103.62 80.67 92.78 103.97 99.99 104.87 106.36 119.16 122.41Peer Group100.00 163.79 160.94 113.17 126.61 160.27 170.08 236.91 264.52 340.64 272.72 Sep '13 Dec '13 Mar '14 Jun '14 Sep '14 Dec '14 Mar '15 Jun '15 Sep '15 Dec '15CVREnergy, Inc. 311.10 358.04 354.65 410.78 403.40 354.60 394.66 353.48 390.39 378.31Russell 2000Index134.47 145.72 146.89 149.39 137.96 150.86 156.88 157.03 137.83 142.24Peer Group238.60 346.24 317.43 309.92 336.54 324.45 421.99 408.97 402.89 378.74Purchases of Equity Securities by the IssuerWe did not repurchase any of our common stock during the fiscal quarter ended December 31, 2015.51Table of ContentsItem 6. Selected Financial DataYou should read the selected historical consolidated financial data presented below in conjunction with "Management's Discussion and Analysis ofFinancial Condition and Results of Operations" and our consolidated financial statements and the related notes included elsewhere in this Report.The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for theyears ended December 31, 2015, 2014 and 2013 and the selected consolidated financial information presented below under the caption "Balance Sheet Data"as of December 31, 2015 and 2014 has been derived from our audited consolidated financial statements included elsewhere in this Report, which financialstatements have been audited by Grant Thornton LLP, our independent registered public accounting firm. The selected consolidated financial informationpresented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the years ended December 31, 2012 and 2011 and the selectedconsolidated financial information presented below under the caption "Balance Sheet Data" at December 31, 2013, 2012 and 2011 is derived from ouraudited consolidated financial statements that are not included in this Report. Year Ended December 31, 2015 2014 2013 2012 2011(1) (in millions, except per share data)Statements of Operations Data Net sales$5,432.5 $9,109.5 $8,985.8 $8,567.3 $5,029.1Cost of product sold(2)4,190.4 8,066.0 7,563.2 6,696.9 3,943.5Direct operating expenses(2)584.7 515.1 455.8 522.1 334.1Flood insurance recovery(27.3) — — — —Insurance recovery-business interruption— — — — (3.4)Selling, general and administrative expenses(2)99.0 109.7 113.5 183.4 98.0Depreciation and amortization164.1 154.4 142.8 130.0 90.3Operating income$421.6 $264.3 $710.5 $1,034.9 $566.6Interest expense and other financing costs(48.4) (40.0) (50.5) (75.4) (55.8)Interest income1.0 0.9 1.2 0.9 0.5Gain (loss) on derivatives, net(28.6) 185.6 57.1 (285.6) 78.1Loss on extinguishment of debt— — (26.1) (37.5) (2.1)Other income (expense), net36.7 (3.7) 13.5 0.9 0.8Income before income tax expense$382.3 $407.1 $705.7 $638.2 $588.1Income tax expense84.5 97.7 183.7 225.6 209.5Net income297.8 309.4 522.0 412.6 378.6Less: Net income attributable tononcontrolling interest 128.2 135.5 151.3 34.0 32.8Net income attributable to CVR Energystockholders$169.6 $173.9 $370.7 $378.6 $345.8 Basic earnings per share$1.95 $2.00 $4.27 $4.36 $4.00Diluted earnings per share$1.95 $2.00 $4.27 $4.33 $3.94Dividends declared per share$2.00 $5.00 $14.25 $— $— Weighted-average common shares outstanding: Basic86.8 86.8 86.8 86.8 86.5Diluted86.8 86.8 86.8 87.4 87.852Table of Contents Year Ended December 31, 2015 2014 2013 2012 2011(1) (in millions)Balance Sheet Data Cash and cash equivalents$765.1 $753.7 $842.1 $896.0 $388.3Working capital789.9 1,033.0 1,230.2 1,135.4 769.2Total assets3,305.8 3,462.5 3,665.8 3,610.9 3,119.3Total debt, including current portion673.5 674.9 676.2 898.2 863.8Total CVR stockholders' equity984.1 988.1 1,188.6 1,525.1 1,151.6Cash Flow Data Net cash flow provided by (used in): Operating activities$536.8 $640.3 $440.1 $762.6 $278.6Investing activities(150.6) (296.6) (250.3) (210.7) (674.4)Financing activities(374.8) (432.1) (243.7) (44.2) 584.1Net cash flow$11.4 $(88.4) $(53.9) $507.7 $188.3 Capital expenditures for property, plant andequipment$218.7 $218.4 $256.5 $212.2 $91.2_______________________________________(1)We acquired WEC on December 15, 2011 and its results of operations are included from the date of acquisition.(2)Amounts are shown exclusive of depreciation and amortization.53Table of ContentsItem 7. Management's Discussion and Analysis of Financial Condition and Results of OperationsYou should read the following discussion and analysis of our financial condition and results of operations in conjunction with our consolidatedfinancial statements and related notes included elsewhere in this Report.Forward-Looking StatementsThis Report, including, without limitation, the sections captioned "Business" and "Management's Discussion and Analysis of Financial Condition andResults of Operations," contains "forward-looking statements" as defined by the SEC, including statements concerning contemplated transactions andstrategic plans, expectations and objectives for future operations. Forward-looking statements include, without limitation:•statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will ormay occur in the future;•statements relating to future financial or operational performance, future dividends, future capital sources and capital expenditures; and•any other statements preceded by, followed by or that include the words "anticipates," "believes," "expects," "plans," "intends," "estimates,""projects," "could," "should," "may," or similar expressions.Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report,including this Management's Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that suchplans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception ofhistorical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements aresubject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of futureperformance and that actual results or developments may differ materially from those projected in the forward-looking statements as a result of variousfactors, including but not limited to those set forth under the section captioned "Risk Factors" and contained elsewhere in this Report. Such factors include,among others:•volatile margins in the refining industry and exposure to the risks associated with volatile crude oil prices;•the availability of adequate cash and other sources of liquidity for the capital needs of our businesses;•the ability to forecast future financial condition or results of operations and future revenues and expenses of our businesses;•the effects of transactions involving forward and derivative instruments;•disruption of the petroleum business' ability to obtain an adequate supply of crude oil;•changes in laws, regulations and policies with respect to the export of crude oil or other hydrocarbons;•interruption of the pipelines supplying feedstock and in the distribution of the petroleum business' products;•competition in the petroleum and nitrogen fertilizer businesses;•capital expenditures and potential liabilities arising from environmental laws and regulations;•changes in ours or the Refining Partnership's or Nitrogen Fertilizer Partnership's credit profile;•the cyclical nature of the nitrogen fertilizer business;•the seasonal nature of the petroleum business;•the supply and price levels of essential raw materials of our businesses; •the risk of a material decline in production at our refineries and nitrogen fertilizer plant;54Table of Contents•potential operating hazards from accidents, fire, severe weather, floods or other natural disasters;•the risk associated with governmental policies affecting the agricultural industry;•the volatile nature of ammonia, potential liability for accidents involving ammonia that cause interruption to the nitrogen fertilizer business, severedamage to property and/or injury to the environment and human health and potential increased costs relating to the transport of ammonia;•the dependence of the nitrogen fertilizer business on a few third-party suppliers, including providers of transportation services and equipment;•new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities;•the risk of security breaches;•the petroleum business' and the nitrogen fertilizer business' dependence on significant customers;•the potential loss of the nitrogen fertilizer business' transportation cost advantage over its competitors;•the potential inability to successfully implement our business strategies, including the completion of significant capital programs;•our ability to continue to license the technology used in the petroleum business and nitrogen fertilizer business operations;•our petroleum business' ability to purchase gasoline and diesel RINs on a timely and cost effective basis;•our petroleum business' continued ability to secure environmental and other governmental permits necessary for the operation of its business;•existing and proposed environmental laws and regulations, including those relating to climate change, alternative energy or fuel sources, and existingand future regulations related to the end-use and application of fertilizers;•refinery and nitrogen fertilizer facility operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability ofadequate insurance coverage;•instability and volatility in the capital and credit markets; and•potential exposure to underfunded pension obligations of affiliates as a member of the controlled group of Mr. Icahn.All forward-looking statements contained in this Report only speak as of the date of this Report. We undertake no obligation to publicly update or reviseany forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events,except to the extent required by law.Overview and Executive SummaryWe are a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through our holdingsin the Refining Partnership and the Nitrogen Fertilizer Partnership. The Refining Partnership is an independent petroleum refiner and marketer of high valuetransportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the form of UAN and ammonia. We own the general partner andapproximately 66% and 53%, respectively, of the outstanding common units representing limited partner interests in each of the Refining Partnership and theNitrogen Fertilizer Partnership.We operate under two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2015, 2014 and 2013, we generatedconsolidated net sales of $5.4 billion, $9.1 billion and $9.0 billion, respectively, and operating income of $421.6 million, $264.3 million and $710.5million, respectively. The petroleum business generated net sales of $5.255Table of Contentsbillion, $8.8 billion and $8.7 billion, and the nitrogen fertilizer business generated net sales of $289.2 million, $298.7 million and $323.7 million, in eachcase, for the years ended December 31, 2015, 2014 and 2013, respectively. The petroleum business generated operating income of $361.7 million, $207.2million and $603.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. The nitrogen fertilizer business generated operating incomeof $68.7 million, $82.8 million and $124.9 million for the years ended December 31, 2015, 2014 and 2013, respectively.Refer to Part I, Item 1, Business, of this Report for a detailed discussion of our business and the petroleum and nitrogen fertilizer segments.Pending MergersOn August 9, 2015, CVR Partners entered into an Agreement and Plan of Merger (the "Merger Agreement") with Rentech Nitrogen Partners, L.P.("Rentech Nitrogen") and Rentech Nitrogen GP, LLC ("Rentech Nitrogen GP"), pursuant to which CVR Partners would acquire Rentech Nitrogen andRentech Nitrogen GP by merging two newly-created direct wholly-owned subsidiaries of CVR Partners with and into those entities with Rentech Nitrogenand Rentech Nitrogen GP continuing as surviving entities and wholly-owned subsidiaries of CVR Partners (together, the "mergers"). In accordance withaccounting principles generally accepted in the United States and in accordance with the Financial Accounting Standards Board's Accounting StandardsCodification Topic 805 - Business Combinations, the Nitrogen Fertilizer Partnership anticipates accounting for the mergers as an acquisition of a businesswith CVR Partners as the acquirer. Refer to Part II, Item 8, Note 1 ("Organization and History of the Company") of this Report for further discussion of themergers.Refining Partnership Initial Public OfferingOn January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units at aprice of $25.00 per unit, resulting in gross proceeds of $600.0 million. Of the common units issued, 4,000,000 units were purchased by an affiliate of IcahnEnterprises L.P. ("IEP"). Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a priceof $25.00 per unit resulting in gross proceeds of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 underthe symbol "CVRR." In connection with the Refining Partnership IPO, the Refining Partnership paid approximately $32.5 million in underwriting fees andincurred approximately $3.9 million of other offering costs. Prior to the Refining Partnership IPO, CVR owned 100% of the Refining Partnership and net income earned during this period was fully attributable tothe Company. Immediately following the Refining Partnership IPO and through May 19, 2013, CVR Energy indirectly owned approximately 81% of theRefining Partnership's outstanding common units and 100% of the Refining Partnership's general partner, which holds a non-economic general partnerinterest. Refining Partnership Underwritten OfferingOn May 20, 2013, the Refining Partnership completed the Underwritten Offering by selling 12,000,000 common units to the public at a price of $30.75per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the publicoffering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with theUnderwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75 per unit inconnection with the exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph arecollectively referred to as the "Transactions."The Refining Partnership utilized net proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) toredeem 13,209,236 common units from CVR Refining Holdings, LLC ("CVR Refining Holdings"), an indirect wholly-owned subsidiary of CVR Energy. Thenet proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The Refining Partnershipdid not receive any of the proceeds from the sale of common units by CVR Energy to AEPC.Immediately following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of total RefiningPartnership common units (including units owned by affiliates of IEP, representing approximately 4% of total Refining Partnership common units), and CVRRefining Holdings held approximately 71% of total Refining Partnership common units.56Table of ContentsRefining Partnership Second Underwritten OfferingOn June 30, 2014, the Refining Partnership completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000common units to the public at a price of $26.07 per unit. The Refining Partnership paid approximately $5.3 million in underwriting fees and approximately$0.5 million in offering costs. The Refining Partnership utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering toredeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July23, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately67% of the total Refining Partnership common units.On July 24, 2014, the Refining Partnership sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with theunderwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 millionfrom the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR RefiningHoldings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection withthe underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2015, public securityholders held approximately 34% of total Refining Partnership common units (including units held by affiliates of IEP, representing approximately 4% oftotal Refining Partnership common units), and CVR Refining Holdings held approximately 66% of total Refining Partnership common units in addition toowning 100% of the Refining Partnership's general partner.Nitrogen Fertilizer Partnership Secondary OfferingOn May 28, 2013, Coffeyville Resources, LLC ("CRLLC"), a wholly-owned subsidiary of CVR Energy, completed the Secondary Offering in which itsold 12,000,000 Nitrogen Fertilizer Partnership common units to the public at a price of $25.15 per unit. The net proceeds to CRLLC from the SecondaryOffering were approximately $292.6 million, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen FertilizerPartnership did not receive any of the proceeds from the sale of common units by CRLLC.Immediately following the closing of the Secondary Offering and as of December 31, 2015, public security holders held approximately 47% of totalNitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of total Nitrogen Fertilizer Partnership common units in addition toowning 100% of the Nitrogen Fertilizer Partnership's general partner.Major Influences on Results of OperationsPetroleum BusinessThe earnings and cash flows of the petroleum business are primarily affected by the relationship between refined product prices and the prices for crudeoil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for whichrefined products are ultimately sold depend on factors beyond the petroleum business' control, including the supply of and demand for crude oil, as well asgasoline 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 governmentregulation. Because the petroleum business applies first-in, first-out ("FIFO") accounting to value its inventory, crude oil price movements may impact netincome in the short term because of changes in the value of its unhedged on-hand inventory. The effect of changes in crude oil prices on our results ofoperations is influenced by the rate at which the prices of refined products adjust to reflect these changes.The prices of crude oil and other feedstocks and refined product prices are also affected by other factors, such as product pipeline capacity, local marketconditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to widefluctuations. Widespread expansion or upgrades of competitors' facilities, price volatility, international political and economic developments and otherfactors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventoriesin the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations indemand for refined products, such as increases in the demand for gasoline during the summer driving57Table of Contentsseason and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that mayimpact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, andincreased mileage standards for vehicles. The petroleum business is also subject to the Renewable Fuel Standard ("RFS") of the United States EnvironmentalProtection Agency (the "EPA"), which requires it to either blend "renewable fuels" in with its transportation fuels or purchase renewable fuel credits, known asrenewable identification numbers ("RINs"), in lieu of blending.Refer to Part I, Item 1A, Risk Factors, If sufficient RINs are unavailable for purchase, if the petroleum business has to pay a significantly higher price forRINs or if the petroleum business is otherwise unable to meet the EPA's Renewable Fuels Standard (RFS) mandates, the petroleum business' financialcondition and results of operations could be materially adversely affected, and Part II, Item 8, Note 13 ("Commitments and Contingencies"), "Environmental,Health and Safety ("EHS") Matters" of this Report for further discussion of RFS.The cost of RINs for the years ended December 31, 2015, 2014 and 2013 was approximately $123.9 million, $127.2 million and $180.5 million,respectively. The price of RINs has been extremely volatile and has increased over the last year. The future cost of RINs for the petroleum business is difficultto estimate. Additionally, the cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINscan be purchased, transportation fuel production levels, the mix of the petroleum business’ petroleum products, as well as the fuel blending performed at itsrefineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimatesrelated to the other variable factors, the petroleum business estimates that the total cost of RINs will be approximately $140.0 million to $190.0 million forthe year ending December 31, 2016.In order to assess the operating performance of the petroleum business, we compare net sales, less cost of product sold (exclusive of depreciation andamortization), or the refining margin, against an industry refining margin benchmark. The industry refining margin benchmark is calculated by assuming thattwo barrels of benchmark light sweet crude oil are converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referredto 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 marketvalue 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 indollars 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 productionof gasoline and distillate.Although the 2-1-1 crack spread is a benchmark for the refinery margin, because the refineries have certain feedstock costs and logistical advantages ascompared to a benchmark refinery and their product yield is less than total refinery throughput, the crack spread does not account for all the factors that affectrefinery margin. The Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that hashistorically cost less than WTI. The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to lightsweet crude oil, although isobutene, gasoline components, and normal butane are also typically used. We measure the cost advantage of the crude oil slate bycalculating the spread between the price of the delivered crude oil and the price of WTI. The spread is referred to as the consumed crude oil differential. Therefinery margin can be impacted significantly by the consumed crude oil differential. The consumed crude oil differential will move directionally withchanges in the WTS differential to WTI and the WCS differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate toWTI. The correlation between the consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crudeoil and heavy sour crude oil the petroleum business purchases as a percent of its total crude oil volume and will correlate more closely with such publisheddifferentials the heavier and more sour the crude oil slate. The consumed crude oil cost discount to WTI for 2015 was $1.12 per barrel compared to consumedcrude oil cost discounts of $0.54 per barrel in 2014 and $2.57 per barrel in 2013.The petroleum business produces a high volume of high value products, such as gasoline and distillates. The fact that the actual product specificationsused to determine the NYMEX 2-1-1 crack spread are different from the actual production in its refineries is because the prices the petroleum business realizesare different than those used in determining the 2-1-1 crack spread. The difference between its price and the price used to calculate the 2-1-1 crack spread isreferred 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-LowSulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in its marketing area exceed those used inthe 2-1-1 crack spread.The petroleum business is significantly affected by developments in the markets in which it operates. For example, numerous pipeline projects in 2014expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage. The refiningindustry is directly impacted by these events and could see a downward movement in refining margins as a result.58Table of ContentsThe direct operating expense structure is also important to the petroleum business' profitability. Major direct operating expenses include energy,employee labor, maintenance, contract labor, and environmental compliance. The predominant variable cost is energy, which is comprised primarily ofelectrical cost and natural gas. The petroleum business is therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumptionof natural gas for the year ended December 31, 2015, a $1.00 change in natural gas prices would have increased or decreased the petroleum business' naturalgas costs by approximately $11.1 million.Because crude oil and other feedstocks and refined products are commodities, the petroleum business has no control over the changing market.Therefore, the lower target inventory it is able to maintain significantly reduces the impact of commodity price volatility on its petroleum product inventoryposition relative to other refiners. This target inventory position is generally not hedged. To the extent its inventory position deviates from the target level,the petroleum business considers risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Its hedging activitiescarry customary time, location and product grade basis risks generally associated with hedging activities. Because most of its titled inventory is valued underthe FIFO costing method, price fluctuations on its target level of titled inventory have a major effect on the petroleum business' financial results.Safe and reliable operations at the refineries are key to the petroleum business' financial performance and results of operations. Unplanned downtime atthe refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and relatedinventory position. The petroleum business seeks to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through adiligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstocklogistics and other factors. The refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon thescope of work to be completed. During the outage at the Coffeyville refinery in the third quarter of 2014 as discussed further below, the petroleum businessaccelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million of turnaround expenses for the year ended December 31,2014. The first phase of its current turnaround was completed in mid-November 2015 at a total cost of approximately $101.5 million. The second phase isscheduled to begin in late February 2016 at a total estimated cost of approximately $35.0 million to $38.0 million (of which approximately $0.7 million wasincurred in the fourth quarter of 2015). The Wynnewood Refinery completed a turnaround in December 2012. During the outage at the Wynnewood refineryin the fourth quarter of 2014 as discussed further below, the petroleum business accelerated certain planned turnaround activities and incurred approximately$1.3 million of turnaround expenses for the year ended December 31, 2014. The next turnaround for the Wynnewood refinery is scheduled to occur in thespring of 2017.During the third quarter of 2013, the fluid catalytic cracking unit ("FCCU") at the Coffeyville refinery was offline for approximately 55 days fornecessary repairs. As a result of the FCCU outage, crude throughput and production at the Coffeyville refinery was significantly reduced during the thirdquarter of 2013. Additionally, the Refining Partnership incurred approximately $21.1 million in costs to repair the FCCU for the year ended December 31,2013. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.On July 29, 2014, the Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employeewho was fatally injured. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System,which was directly caused by the fire. The Coffeyville refinery returned to operations in mid-August, with all units except the isomerization unit in operationby August 23, 2014. The isomerization unit started operating on October 12, 2014. This interruption adversely impacted production of refined products forthe petroleum business in the third quarter of 2014. Total gross repair and other costs recorded related to the incident for the year ended December 31, 2014were approximately $6.3 million.The Refining Partnership is covered by property damage insurance policies at the time of the incident, which had an associated deductible of $5.0million for the Coffeyville refinery. The Refining Partnership anticipates amounts in excess of the $5.0 million deductible related to the isomerization unitfire incident will be recoverable under the property insurance policies. As of December 31, 2015 and 2014, the Refining Partnership had an insurancereceivable related to the incident of approximately $1.2 million and $1.3 million, respectively, which is included in prepaid expenses and other current assetsin the Consolidated Balance Sheets. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation andamortization).During the fourth quarter of 2014, the FCCU at the Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a result of theFCCU outage, crude throughput and production at the Wynnewood refinery was significantly reduced during the fourth quarter of 2014. Additionally, theRefining Partnership incurred approximately $8.559Table of Contentsmillion in costs to repair the FCCU for the year ended December 31, 2014. These costs are included in direct operating expenses (exclusive of depreciationand amortization) in the Consolidated Statements of Operations. Nitrogen Fertilizer BusinessIn the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer productprices, on-stream factors and direct operating expenses. Natural gas is the most significant raw material required in its competitors' production of nitrogenfertilizer. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energysource in its operations. Instead, the adjacent Coffeyville refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needspursuant to a 20-year pet coke supply agreement entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends onnumerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world graindemand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, theavailability of imports, and the extent of government intervention in agriculture markets. Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. Anexpansion or upgrade of competitors' facilities, political and economic developments and other factors are likely to continue to play an important role innitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and areduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.As a result of a favorable global demand environment for grains, nitrogen fertilizer prices rose to near historic levels beginning in 2011. In addition,North American producers began to benefit from lower natural gas prices due to the significant increase in shale basin and other non-conventional productionin the region. The combination of higher nitrogen fertilizer prices globally and a feedstock cost advantage led to high margins for North American nitrogenfertilizer producers. This resulted in numerous announcements for expansion plans for existing plants as well as new facility development in the corn belt andthe gulf coast. The majority of the additional supply from this expansion phase in North America is expected to come online in 2016. The nitrogen fertilizerbusiness expects product pricing may experience volatility as the new supply displaces imports into the gulf coast and corn belt. However, over the longer-term the U.S. is expected to remain a net importer of nitrogen fertilizer with domestic prices influenced by the higher cost of imported tons into the U.S.Since mid-2013, global nitrogen fertilizer prices have trended down as global grain supply increased and growth in grain demand slowed due to morechallenging worldwide economic considerations. During 2015, there were announced transactions for further consolidation in the North American nitrogenfertilizer market, including the nitrogen fertilizer business' definitive merger agreement under which it will acquire all outstanding units of Rentech Nitrogen.Refer to Part II, Item 8, Note 1 ("Organization and History of the Company") of this Report for further discussion of the mergers. While there is risk of short-term volatility given the inherent nature of the commodity cycle, the longer-term fundamentals for the U.S. nitrogen fertilizerindustry remain intact. The nitrogen fertilizer business views the anticipated combination of (i) increasing global population, (ii) decreasing arable land percapita, (iii) continued evolution to more protein-based diets in developing countries, (iv) sustained use of corn as feedstock for the domestic production ofethanol and (v) positioning at the lower end of the global cost curve will continue to provide a solid foundation for nitrogen fertilizer producers in the U.S.In order to assess the operating performance of the nitrogen fertilizer business, the nitrogen fertilizer business calculates the product pricing at gate as aninput to determine its operating margin. Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. Thenitrogen fertilizer business believes product pricing at gate is a meaningful measure because it sells products at its plant gate and terminal locations' gates(sold gate) and delivered to the customer's designated delivery site (sold delivered). The relative percentage of sold gate versus sold delivered can changeperiod to period. The product pricing at gate provides a measure that is consistently comparable period to period.The nitrogen fertilizer business and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to out-of-region competitors in serving the U.S. farm belt agricultural market; therefore, the nitrogen fertilizer business is able to cost-effectively sell substantially allof its products in the higher margin agricultural market. Further, the nitrogen fertilizer business believes that a significant portion of its competitors' revenuesare derived from the lower margin industrial market. The nitrogen fertilizer business' products leave the plant either in railcars for destinations locatedprincipally on the Union Pacific Railroad or in trucks for direct shipment to customers. The nitrogen fertilizer business does not currently incur significantintermediate transfer, storage, barge freight or pipeline freight charges; however, it does incur costs to maintain60Table of Contentsand repair its railcar fleet. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportationcosts low are keys to maintaining profitability.As a result of the UAN expansion project completed in 2013, the nitrogen fertilizer business will continue to upgrade substantially all of its ammoniaproduction into UAN for as long as it makes economic sense to do so. The value of nitrogen fertilizer products is also an important consideration inunderstanding the nitrogen fertilizer business' results. For the years ended December 31, 2015, 2014 and 2013, the nitrogen fertilizer business upgradedapproximately 96%, 97% and 95%, respectively, of its ammonia production into UAN, a product that presently generates greater profit than ammonia.The high fixed cost of the nitrogen fertilizer business' direct operating expense structure also directly affects its profitability. Using a pet cokegasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixedoperating expenses include a large portion of electrical energy, employee labor, maintenance, including contract labor, and outside services. The nitrogenfertilizer business estimates fixed costs averaged approximately 80% of direct operating expenses over the 24 months ended December 31, 2015.The nitrogen fertilizer business' largest raw material expense used in the production of ammonia is pet coke, which it purchases from the petroleumbusiness and third parties. For the years ended December 31, 2015, 2014 and 2013, the nitrogen fertilizer business incurred approximately $11.9 million,$13.6 million and $14.6 million, respectively, for pet coke, which equaled an average cost per ton of $25, $28 and $30, respectively.The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from the adjacent Coffeyville crudeoil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price the nitrogen fertilizer business payspursuant 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") or a petcoke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN that excludes transportation cost("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.Safe and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of thenitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment andrelated inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planningprocess that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors.The nitrogen fertilizer plant generally undergoes a full facility turnaround every two to three years. Turnarounds are expected to last 14-21 days. A lessinvolved facility shutdown was performed during the second quarter of 2014 and included both the installation of a waste heat boiler and the completion ofseveral key tasks in order to upgrade the pressure swing adsorption ("PSA") unit. The Nitrogen Fertilizer Partnership underwent a full facility turnaround inthe third quarter of 2015, and the gasification, ammonia and UAN units were down for between 17 to 20 days each at a cost, exclusive of the impacts due tothe lost production during the downtime, of approximately $7.0 million for the year ended December 31, 2015, respectively. The Nitrogen FertilizerPartnership is planning to undergo the next scheduled full facility turnaround in the second half of 2017.Agreements With the Refining Partnership and the Nitrogen Fertilizer PartnershipWe are party to several agreements with the Nitrogen Fertilizer Partnership that govern the business relations among the Nitrogen Fertilizer Partnershipand its affiliates on the one hand and us and our other affiliates on the other hand. In connection with the Refining Partnership IPO in January 2013, some ofour subsidiaries party to these agreements became subsidiaries of the Refining Partnership.These intercompany agreements include (i) the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to thenitrogen fertilizer business; (ii) a services agreement, pursuant to which our management operates the nitrogen fertilizer business; (iii) a feedstock and sharedservices agreement, which governs the provision of feedstocks, including, but not limited to, hydrogen, high-pressure steam, nitrogen, instrument air, oxygenand natural gas; (iv) a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; (v) an easement agreement;(vi) an environmental agreement; and (vii) a lease agreement pursuant to which the petroleum business leases office space and laboratory space to theNitrogen Fertilizer Partnership. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily at leastas favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.61Table of ContentsIn connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining Partnership, including (i) a $250.0 millionintercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates thepetroleum business.Simultaneously with the execution of the Merger Agreement discussed in Part II, Item 8, Note 1 ("Organization and History of the Company") of thisReport, the Nitrogen Fertilizer Partnership entered into a commitment letter (the "commitment letter") with CRLLC. Refer to Part II, Item 7, "Liquidity andCapital Resources" of this Report for further discussion of the commitment letter.On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty theindebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. Refer to Part II, Item 7, "Liquidity and Capital Resources" of this Reportfor further discussion of the guaranty terms.Crude Oil Supply AgreementOn August 31, 2012, Coffeyville Resources Refining and Marketing, LLC ("CRRM") and Vitol Inc. ("Vitol") entered into an Amended and RestatedCrude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil andintermediation logistics, which helps the petroleum business to reduce its inventory position and mitigate crude oil pricing risk. The Vitol Agreement willautomatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal atleast 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.Factors Affecting ComparabilityOur 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 thereasons presented and discussed below. Year Ended December 31, 2015 2014 2013 (in millions)Loss on extinguishment of debt(1) $— $— $26.1Share-based compensation(2) 12.8 12.3 18.4(Gain) loss on derivatives, net 28.6 (185.6) (57.1)Major scheduled turnaround expenses(3) 109.2 6.8 —Flood insurance recovery(4) (27.3) — —_______________________________________(1)Represents the write-off of previously deferred financing costs, unamortized original issue discount and the premium paid related to the extinguishmentof the 10.875% Second Lien Senior Secured Notes due 2017 (the "Old Second Lien Notes").(2)Represents impact of share-based compensation awards.(3)Represents expense associated with major scheduled turnaround activities performed at the Coffeyville refinery ($102.2 million in 2015 and $5.5million in 2014), the Wynnewood refinery ($1.3 million in 2014) and the nitrogen fertilizer plant ($7.0 million in 2015).(4)Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyvillerefinery on June/July 2007. Refer to Part II, Item 8, Note 13 ("Commitments and Contingencies") of this Report for further details.Noncontrolling InterestPrior to the Refining Partnership IPO on January 23, 2013, the noncontrolling interest reflected in our consolidated financial statements represented theapproximately 30% interest in the Nitrogen Fertilizer Partnership held by public common unitholders, which was adjusted each reporting period for thenoncontrolling ownership percentage of the Nitrogen Fertilizer Partnership's net income and related distributions. As a result of the Refining Partnership IPO,CVR Energy recorded an additional noncontrolling interest for the Refining Partnership common units sold to the public, which represented an62Table of Contentsapproximately 19% interest of the Refining Partnership. Effective with the Refining Partnership's IPO, the noncontrolling interest reflected on theConsolidated Balance Sheets was impacted additionally by the noncontrolling ownership percentage of the net income of the Refining Partnership andrelated distributions for each future reporting period. As a result of the Refining Partnership's closing of the Underwritten Offering, the noncontrolling interestrelated to the Refining Partnership reflected in our consolidated financial statements subsequent to the completion of the offering in the second quarter of2013 and prior to June 30, 2014 was approximately 29%. Upon completion of the Second Underwritten Offering on June 30, 2014 and through July 23,2014, the non-controlling interest reflected in our consolidated financial statements was approximately 33%. On July 24, 2014, upon exercise of theunderwriters' option associated with the Second Underwritten Offering, the noncontrolling interest reflected in our consolidated financial statements isapproximately 34%. Additionally, as a result of the Nitrogen Fertilizer Partnership's Secondary Offering, the noncontrolling interest related to the NitrogenFertilizer Partnership reflected in our consolidated financial statements subsequent to the completion of the Secondary Offering on May 28, 2013 and as ofDecember 31, 2015 is approximately 47%.The revenue and expenses from the Refining Partnership and Nitrogen Fertilizer Partnership are consolidated with CVR Energy's ConsolidatedStatements of Operations because each of the general partners is owned by CVR Refining Holdings and CRLLC, respectively, wholly-owned subsidiaries ofCVR Energy. Therefore, CVR Energy has the ability to control the activities of the Refining Partnership and Nitrogen Fertilizer Partnership. However, thepercentage of ownership held by the public unitholders for the Refining Partnership and the Nitrogen Fertilizer Partnership is reflected as net incomeattributable to noncontrolling interest in our Consolidated Statements of Operations and reduces consolidated net income to derive net income attributableto CVR Energy. Distributions to CVR Partners UnitholdersRefer to Part II, Item 5, "CVR Partners, LP Cash Distribution Policy," of this Report for a summary of CVR Partners' distribution policy and the cashdistributions paid to the Nitrogen Fertilizer Partnership unitholders during the years ended December 31, 2015 and 2014.Distributions to CVR Refining UnitholdersRefer to Part II, Item 5, "CVR Refining, LP Cash Distribution Policy," of this Report for a summary of CVR Refining's distribution policy and the cashdistributions paid to the Refining Partnership unitholders during the years ended December 31, 2015 and 2014.CVR Energy DividendsRefer to Part II, Item 5, "CVR Energy, Inc. Dividend Policy," of this Report for a summary of our dividend policy and the cash dividends paid to ourstockholders during the years ended December 31, 2015 and 2014.Industry FactorsPetroleum BusinessEarnings for the petroleum business depend largely on its refining margins, which have been and continue to be volatile. Refining margins are impactedprimarily by the relationship or spread between crude oil and refined product prices. The petroleum business' refineries reside in the Group 3 marketingregion and are supplied with advantaged domestic and Canadian crudes.Crude oil discounts are a major contributor to the petroleum business earnings. Canadian heavy sour crude oil production continues to grow and withlimited export capacity provides an advantaged crude to the mid-continent refiners. As a result of an expansion project, the petroleum business increased itsability to process higher volumes of heavy sour crude oil and take advantage of this opportunity.Additionally, the relationship between current spot prices and future prices can impact profitability. As such, the petroleum business believes that itsapproximately 7.0 million barrels of crude oil storage in Cushing, Oklahoma and other locations allows it to take advantage of the contango market whensuch conditions exist. Contango markets are generally characterized by prices for future delivery that are higher than the current, or spot, price of acommodity. This condition provides economic incentive to hold or carry a commodity in inventory.63Table of ContentsNitrogen Fertilizer BusinessGlobal demand for fertilizers is driven primarily by population growth, dietary changes in the developing world and increased consumption of bio-fuels.According to the International Fertilizer Industry Association, from 1973 to 2013, global fertilizer demand grew 1.9% annually. Fertilizer use is projected toincrease by 45% between 2005 and 2030 to meet global food demand according to a study funded by the Food and Agricultural Organization of the UnitedNations. Currently, the developed world uses fertilizer more intensively than the developing world, but sustained economic growth in emerging markets isincreasing food demand and fertilizer use. As an example, China's wheat and coarse grains production increased 51% between 2005 and 2015, but still failedto keep pace with increases in demand, prompting China to grow its grain imports by more than 200% over the same period, according to the United StatesDepartment of Agriculture ("USDA").World grain demand increased 9%, from 2012 to 2015, according to the USDA, leading to a tighter grain supply environment and significant increases ingrain prices that is supportive of fertilizer prices.Nitrogen fertilizer prices have decoupled from their historical correlation with natural gas prices and are now driven primarily by demand dynamics. Atexisting grain prices and prices implied by futures markets, farmers are expected to generate profits leading to relatively inelastic demand for fertilizers.The United States is the world's largest exporter of coarse grains, accounting for 33% of world exports and 29% of world production during the 2014-2015 marketing year, according to the USDA. Fertecon estimates the United States is the world's third largest consumer of nitrogen fertilizer and historicallythe world's first or second largest importer of nitrogen fertilizer, importing approximately 42% of its nitrogen fertilizer needs during the 2014-2015 marketingyear. North American producers have a significant and sustainable cost advantage over the majority of producers that export to the U.S. market.The three primary forms of nitrogen fertilizer used in the U.S. are ammonia, urea and UAN. Unlike ammonia and urea, UAN can be applied throughout thegrowing season and can be applied in tandem with pesticides and herbicides, providing farmers with flexibility and cost savings. As a result of these factors,UAN typically commands a premium price to urea and ammonia, on a nitrogen equivalent basis.64Table of ContentsResults of OperationsIn this "Results of Operations" section, we first review our business on a consolidated basis, and then separately review the results of operations of each ofour petroleum and nitrogen fertilizer businesses on a standalone basis.Consolidated Results of OperationsThe period to period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financialstatements. This "Results of Operations" section compares the year ended December 31, 2015 with the year ended December 31, 2014 and the year endedDecember 31, 2014 with the year ended December 31, 2013.Net sales consist principally of sales of refined fuel and nitrogen fertilizer products. For the petroleum business, net sales are mainly affected by crude oiland refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of productionrepresented by higher value light products, such as gasoline, rather than lower value finished products, such as pet coke. In the nitrogen fertilizer business,net sales are primarily impacted by manufactured tons and nitrogen fertilizer prices.Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred toas crack spreads. See " — Major Influences on Results of Operations." We discuss the results of the petroleum business in the context of per barrel consumedcrack spreads and the relationship between net sales and cost of product sold.Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions andtherefore do not equal the sum of the operating results of the petroleum and nitrogen fertilizer businesses.65Table of ContentsThe following table provides an overview of our results of operations during the past three fiscal years: Year Ended December 31, 2015 2014 2013 (in millions, except per share data)Statements of Operations Data Net sales$5,432.5 $9,109.5 $8,985.8Cost of product sold(1)4,190.4 8,066.0 7,563.2Direct operating expenses(1)584.7 515.1 455.8Flood insurance recovery(27.3) — —Selling, general and administrative expenses(1)99.0 109.7 113.5Depreciation and amortization164.1 154.4 142.8Operating income421.6 264.3 710.5Interest expense and other financing costs(48.4) (40.0) (50.5)Interest income1.0 0.9 1.2Gain (loss) on derivatives, net(28.6) 185.6 57.1Loss on extinguishment of debt— — (26.1)Other income (expense), net36.7 (3.7) 13.5Income before income tax expense382.3 407.1 705.7Income tax expense84.5 97.7 183.7Net income297.8 309.4 522.0Less: Net income attributable to noncontrolling interest 128.2 135.5 151.3Net income attributable to CVR Energy stockholders$169.6 $173.9 $370.7 Basic earnings per share$1.95 $2.00 $4.27Diluted earnings per share$1.95 $2.00 $4.27Dividends declared per share$2.00 $5.00 $14.25Adjusted EBITDA(2)$498.8 $473.5 $659.7 Weighted-average common shares outstanding: Basic86.8 86.8 86.8Diluted86.8 86.8 86.8_______________________________________(1)Amounts are shown exclusive of depreciation and amortization.Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expense and selling,general and administrative expense: Year Ended December 31, 2015 2014 2013 (in millions)Depreciation and amortization excluded from cost of product sold$6.7 $6.3 $5.0Depreciation and amortization excluded from direct operating expenses149.7 141.8 134.5Depreciation and amortization excluded from selling, general and administrative expense7.7 6.3 3.3Total depreciation and amortization$164.1 $154.4 $142.866Table of Contents(2)EBITDA and Adjusted EBITDA. EBITDA represents net income before (i) interest expense and other financing costs, net of interest income, (ii)income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for (i) FIFO impact (favorable)unfavorable, (ii) share-based compensation, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v) gain (loss) onderivatives, net, (vi) current period settlements on derivative contracts, (vii) flood insurance recovery and (viii) expenses associated with thepending Rentech Nitrogen mergers. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for netincome or cash flow from operations. Management believes that EBITDA and Adjusted EBITDA enable investors to better understand and evaluateour ongoing operating results and allows for greater transparency in reviewing our overall financial, operational and economic performance.EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define theseterms differently. Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the years ended December 31, 2015,2014 and 2013: Year Ended December 31, 2015 2014 2013 (in millions) (unaudited)Net income attributable to CVR Energy stockholders$169.6 $173.9 $370.7Add: Interest expense and other financing costs, net of interest income47.4 39.1 49.3Income tax expense84.5 97.7 183.7Depreciation and amortization164.1 154.4 142.8EBITDA adjustments included in noncontrolling interest(75.2) (65.2) (50.1)EBITDA390.4 399.9 696.4Add: FIFO impact (favorable) unfavorable60.3 160.8 (21.3)Share-based compensation12.8 12.3 18.4Loss on extinguishment of debt— — 26.1Major scheduled turnaround expenses109.2 6.8 —(Gain) loss on derivatives, net28.6 (185.6) (57.1)Current period settlement on derivative contracts(a)(26.0) 122.2 6.4Flood insurance recovery(b)(27.3) — —Expenses associated with the Rentech Nitrogen mergers(c)2.3 — —Adjustments included in noncontrolling interest(51.5) (42.9) (9.2)Adjusted EBITDA$498.8 $473.5 $659.7_______________________________________(a)Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled withcounterparties. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recoveryassociated with these contracts.(b)Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyvillerefinery on June/July 2007. Refer to Part II, Item 8, Note 13 ("Commitments and Contingencies") of this Report for further details.(c)Represents legal and other professional fees and other merger-related expenses incurred by the Nitrogen Fertilizer Partnership in regards to thepending Rentech Nitrogen mergers. Refer to Part II, Item 8, Note 1 ("Organization and History of the Company") of this Report for further details.67Table of ContentsYear Ended December 31, 2015 Compared to the Year Ended December 31, 2014 (Consolidated)Net Sales. Consolidated net sales were $5,432.5 million for the year ended December 31, 2015, compared to $9,109.5 million for the year endedDecember 31, 2014. The decrease of $3,677.0 million was largely the result of a decrease in our petroleum segment's net sales of $3,667.8 million due tosignificantly lower sales prices. The petroleum segment's average sales price per gallon for the year ended December 31, 2015 of $1.61 for gasoline and $1.62for distillate decreased by 36.4% and 42.3%, respectively, as compared to the year ended December 31, 2014. The nitrogen fertilizer segment net salesdecreased by $9.5 million due to lower UAN sales prices and volumes, partially offset by higher ammonia sales volumes.Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was$4,190.4 million for the year ended December 31, 2015, as compared to $8,066.0 million for the year ended December 31, 2014. The decrease of $3,875.6million primarily resulted from a decrease of $3,869.8 million in cost of product sold at the petroleum segment. The decrease at the petroleum segment wasdue to a decrease in the cost of consumed crude and purchased products for resale. The decrease in consumed crude oil costs was due to a 47.5% decrease incrude oil prices. The nitrogen fertilizer segment cost of product sold (exclusive of depreciation and amortization) also decreased by $6.8 million primarily asa result of lower freight and distribution costs and lower consumption and lower pricing of pet coke.Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation andamortization) were $584.7 million for the year ended December 31, 2015, as compared to $515.1 million for the year ended December 31, 2014. The increaseof $69.6 million was primarily due to an increase of $62.5 million at the petroleum segment as a result of the major scheduled turnaround activities performedat the Coffeyville refinery, partially offset by decreases in repair and maintenance and energy and utility costs. The nitrogen fertilizer segment also had anincrease in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of higher major scheduled turnaroundexpenses.Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrativeexpenses (exclusive of depreciation and amortization) were $99.0 million for the year ended December 31, 2015, as compared to $109.7 million for the yearended December 31, 2014. The decrease of $10.7 million was primarily the result of lower legal expenses, IT-related costs and consulting costs, partiallyoffset by higher personnel costs.Operating Income. Consolidated operating income was $421.6 million for the year ended December 31, 2015, as compared to operating income of$264.3 million for the year ended December 31, 2014, an increase of $157.3 million. Petroleum segment operating income increased $154.5 millionprimarily due to higher refining margins and the flood insurance recovery, partially offset by increased direct operating expenses. Nitrogen fertilizer segmentoperating income decreased $14.1 million primarily as a result of lower net sales and higher direct operating expenses, partially offset by lower cost ofproduct sold.Interest Expense. Consolidated interest expense for the year ended December 31, 2015 was $48.4 million as compared to $40.0 million for the yearended December 31, 2014. The increase of $8.4 million resulted primarily from lower capitalized interest for the year ended December 31, 2015 as comparedto the year ended December 31, 2014, following the completion of several larger capital projects in late 2014.Gain (Loss) on Derivatives, Net. For the year ended December 31, 2015, the petroleum segment recorded a $28.6 million net loss on derivativescompared to a $185.6 million net gain on derivatives for the year ended December 31, 2014. This change was primarily due to changes in crack spreadsduring the period. The petroleum segment enters into over-the-counter commodity swap contracts to fix the margin on a portion of its future gasoline anddistillate production.Income Tax Expense. Income tax expense for the year ended December 31, 2015 was $84.5 million or 22.1% of income before income taxes, ascompared to income tax expense for the year ended December 31, 2014 of $97.7 million or 24.0% of income before income taxes. This is in comparison to acombined federal and state expected statutory rate of 39.5% for 2015 and 39.6% for 2014. Our 2015 effective tax rate is lower than the expected statutory rateprimarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests in CVR Refining's and CVR Partners' earningsand the benefits related to the domestic production activities deduction and state income tax credits.Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling interest represents the 47% interest in the NitrogenFertilizer Partnership held by public unitholders as of and for the years ended December 31, 2015 and 2014. Additionally, it represents the 34% interest in theRefining Partnership held by public unitholders from July 24, 201468Table of Contentsthrough December 31, 2015, the 33% interest held by public unitholders from June 30, 2014 through July 23, 2014 and the 29% interest held by publicunitholders from May 20, 2013 through June 29, 2014.Net Income Attributable to CVR Stockholders. For the year ended December 31, 2015, net income attributable to CVR stockholders decreased to$169.6 million as compared to net income of $173.9 million for the year ended December 31, 2014.Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 (Consolidated)Net Sales. Consolidated net sales were $9,109.5 million for the year ended December 31, 2014, compared to $8,985.8 million for the year endedDecember 31, 2013. The increase of $123.7 million was primarily the result of an increase in petroleum net sales of $146.2 million due to higher overall salesvolumes largely offset by lower sales prices for gasoline and distillates. The petroleum segment's average sales price per gallon for the year endedDecember 31, 2014 of $2.53 for gasoline and $2.81 for distillates each decreased by 7.0%, as compared to the year ended December 31, 2013. The nitrogenfertilizer segment net sales decreased by $25.0 million due to lower UAN sales prices and lower ammonia sales volumes, partially offset by high UAN salesvolumes.Cost of Product Sold (Exclusive of Depreciation and Amortization). Consolidated cost of product sold (exclusive of depreciation and amortization) was$8,066.0 million for the year ended December 31, 2014, as compared to $7,563.2 million for the year ended December 31, 2013. The increase of $502.8million primarily resulted from an increase of $486.7 million in cost of product sold at the petroleum segment. The increase at the petroleum segment was dueto increases in the cost of consumed crude oil and higher refined fuels purchased for resale. The increase in consumed crude costs was due to higherconsumed volumes, partially offset by lower crude oil prices. The nitrogen fertilizer segment cost of product sold (exclusive of depreciation andamortization) also increased $13.9 million primarily as a result of increased distribution costs due to increased railcar regulatory inspections and repairs andincreased ammonia purchases.Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation andamortization) were $515.1 million for the year ended December 31, 2014, as compared to $455.8 million for the year ended December 31, 2013. The increaseof $59.3 million was primarily due to an increase at the petroleum segment for expenses related to energy and utility costs, repairs and maintenance andlabor. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily theresult of higher energy and utility costs and refractory brick amortization.Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrativeexpenses (exclusive of depreciation and amortization) were $109.7 million for the year ended December 31, 2014, as compared to $113.5 million for the yearended December 31, 2013. The decrease of $3.8 million was primarily the result of lower share-based compensation and personnel costs, IT-related costs andconsulting, partially offset by higher legal costs.Operating Income. Consolidated operating income was $264.3 million for the year ended December 31, 2014, as compared to operating income of$710.5 million for the year ended December 31, 2013, a decrease of $446.2 million. Petroleum segment operating income decreased $395.8 million primarilydue to lower refining margins and higher direct operating expenses. Nitrogen fertilizer segment operating income decreased $42.1 million primarily as aresult of lower net sales and higher cost of product sold.Interest Expense. Consolidated interest expense for the year ended December 31, 2014 was $40.0 million as compared to $50.5 million for the yearended December 31, 2013. The decrease of $10.5 million resulted primarily from interest expense on the outstanding 2022 Notes (as defined below) for theyear ended December 31, 2014 as compared to interest expense for the year ended December 31, 2013 related to both the Second Lien Notes (prior to theirextinguishment in the first quarter of 2013) and the 2022 Notes and higher capitalized interest for the year ended December 31, 2014.Gain on Derivatives, Net. For the year ended December 31, 2014, the petroleum segment recorded a $185.6 million net gain on derivatives compared toa $57.1 million net gain on derivatives for the year ended December 31, 2013. This change was primarily due to changes in crack spreads during the period.The petroleum segment enters into over-the-counter commodity swap contracts to fix the margin on a portion of its future gasoline and distillate production.Loss on Extinguishment of Debt. For the year ended December 31, 2013, the petroleum segment incurred a $26.1 million loss on extinguishment ofdebt. The loss on extinguishment of debt was the result of the extinguishment of the Second Lien Notes and included amounts related to the premium paid,the write-off of previously deferred financing costs and the write-off of the unamortized original issue discount.69Table of ContentsIncome Tax Expense. Income tax expense for the year ended December 31, 2014 was $97.7 million or 24.0% of income before income taxes, ascompared to income tax expense for the year ended December 31, 2013 of $183.7 million or 26.0% of income before income taxes. This is in comparison to acombined federal and state expected statutory rate of 39.6% for both 2014 and 2013. Our 2014 effective tax rate is lower than the expected statutory rateprimarily due to the reduction of income subject to tax associated with our noncontrolling ownership interest in CVR Refining's and CVR Partners' earningsand the benefits related to the domestic production activities deduction and state income tax credits.Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling interest represents the 47% interest in the NitrogenFertilizer Partnership held by public unitholders from May 28, 2013 through December 31, 2014. Prior to May 28, 2013, public unitholders held a 30%interest in the Nitrogen Fertilizer Partnership. Additionally, it represents the 34% interest in the Refining Partnership held by public unitholders from July 24,2014 through December 31, 2014, the 33% interest held by public unitholders from June 30, 2014 through July 23, 2014, the 29% interest held by publicunitholders from May 20, 2013 through June 29, 2014 and the 19% interest held by public unitholders from the Refining Partnership IPO through May 19,2013.Net Income Attributable to CVR Stockholders. For the year ended December 31, 2014, net income attributable to CVR stockholders decreased to$173.9 million as compared to net income of $370.7 million for the year ended December 31, 2013.Petroleum Business Results of OperationsThe petroleum business includes the operations of both the Coffeyville and Wynnewood refineries. The following tables below provide an overview ofthe petroleum business' results of operations, relevant market indicators and its key operating statistics for the years ended December 31, 2015, 2014 and2013: Year Ended December 31,2015 2014 2013 (in millions)Consolidated Petroleum Business Financial Results Net sales$5,161.9 $8,829.7 $8,683.5Cost of product sold(1)4,143.6 8,013.4 7,526.7Direct operating expenses(1)(2)376.3 409.2 361.7Major scheduled turnaround expenses102.2 6.8 —Flood insurance recovery(27.3) — —Selling, general and administrative expenses(1)75.2 70.6 77.8Depreciation and amortization130.2 122.5 114.3Operating income361.7 207.2 603.0Interest expense and other financing costs(42.6) (34.2) (44.1)Interest income0.4 0.3 0.4Gain (loss) on derivatives, net(28.6) 185.6 57.1Loss on extinguishment of debt— — (26.1)Other income (expense), net0.3 (0.2) 0.1Income before income tax expense291.2 358.7 590.4Income tax expense— — —Net income$291.2 $358.7 $590.4 Gross profit(3)$436.9 $277.8 $680.8Refining margin(4)$1,018.3 $816.3 $1,156.8Adjusted Petroleum EBITDA(5)$602.0 $621.6 $712.070Table of Contents Year Ended December 31, 2015 2014 2013 (dollars per barrel)Key Operating Statistics Per crude oil throughput barrel: Refining margin(4)$14.45 $11.38 $16.90Gross profit(3)$6.20 $3.87 $9.94Direct operating expenses and major scheduled turnaround expenses(1)(2)$6.79 $5.80 $5.28Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6)$6.40 $5.44 $5.00Barrels sold (barrels per day)(6)204,708 209,669 198,142 Year Ended December 31, 2015 2014 2013 % % %Refining Throughput and Production Data (bpd) Throughput: Sweet176,097 86.0 179,059 86.2 149,147 75.4Medium2,460 1.2 2,022 1.0 19,151 9.7Heavy sour14,520 7.1 15,464 7.4 19,270 9.8Total crude oil throughput193,077 94.3 196,545 94.6 187,568 94.9All other feedstocks and blendstocks11,672 5.7 11,284 5.4 10,121 5.1Total throughput204,749 100.0 207,829 100.0 197,689 100.0Production: Gasoline99,961 48.5 102,275 48.9 94,561 47.7Distillate85,953 41.7 87,639 41.9 82,089 41.4Other (excluding internally produced fuel)20,074 9.8 19,149 9.2 21,617 10.9Total refining production (excluding internallyproduced fuel)205,988 100.0 209,063 100.0 198,267 100.0Product price (dollars per gallon): Gasoline$1.61 $2.53 $2.72 Distillate1.62 2.81 3.02 71Table of Contents Year Ended December 31, 2015 2014 2013Market Indicators (dollars per barrel) West Texas Intermediate (WTI) NYMEX$48.76 $92.91 $98.05Crude Oil Differentials: WTI less WTS (light/medium sour)(0.28) 5.95 2.64WTI less WCS (heavy sour)13.20 18.48 24.58NYMEX Crack Spreads: Gasoline19.89 17.29 21.44Heating Oil20.93 23.59 27.60NYMEX 2-1-1 Crack Spread20.41 20.44 24.52PADD II Group 3 Product Basis: Gasoline(2.12) (4.45) (4.54)Ultra-Low Sulfur Diesel(2.02) 0.75 0.58PADD II Group 3 Product Crack Spread: Gasoline17.76 12.84 16.90Ultra-Low Sulfur Diesel18.91 24.34 28.18PADD II Group 3 2-1-118.34 18.59 22.54_______________________________________(1)Amounts are shown exclusive of depreciation and amortization.(2)Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oilthroughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by theapplicable number of crude oil throughput barrels for the period.(3)Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization),direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, flood insurance recovery anddepreciation and amortization. Each of the components used in this calculation are taken directly from the petroleum business' financial results. Inorder to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by theapplicable number of crude oil throughput barrels for the period.(4)Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusiveof depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating the refineries'performance as a general indication of the amount above the cost of product sold that it is able to sell refined products. Each of the components usedin this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from the petroleum business'financial results. Our calculation of refining margin may differ from similar calculations of other companies in the industry, thereby limiting itsusefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures forrefining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining marginand refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate the petroleum business'ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.(5)Petroleum EBITDA represents net income for the petroleum segment before (i) interest expense and other financing costs, net of interest income, (ii)income tax expense and (iii) depreciation and amortization. Adjusted Petroleum EBITDA represents Petroleum EBITDA adjusted for (i) FIFO impact(favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v)(gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) flood insurance recovery. We present AdjustedPetroleum EBITDA because it is the starting point for the Refining Partnership's available cash for distribution. Petroleum EBITDA and AdjustedPetroleum EBITDA are not recognized terms under GAAP and should72Table of Contentsnot be substituted for net income as a measure of performance. Management believes that Petroleum EBITDA and Adjusted Petroleum EBITDAenable investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, help investors evaluate thepetroleum segment's ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economicperformance. Petroleum EBITDA and Adjusted Petroleum EBITDA presented by other companies may not be comparable to our presentation, sinceeach company may define these terms differently. Below is a reconciliation of net income for the petroleum segment to Petroleum EBITDA andPetroleum EBITDA to Adjusted Petroleum EBITDA for the years ended December 31, 2015, 2014 and 2013: Year Ended December 31, 2015 2014 2013 (in millions)Petroleum: Petroleum net income$291.2 $358.7 $590.4Add: Interest expense and other financing costs, net of interest income42.2 33.9 43.7Income tax expense— — —Depreciation and amortization130.2 122.5 114.3Petroleum EBITDA463.6 515.1 748.4Add: FIFO impact (favorable) unfavorable(a)60.3 160.8 (21.3)Share-based compensation, non-cash0.6 2.3 9.5Loss on extinguishment of debt— — 26.1Major scheduled turnaround expenses(b)102.2 6.8 —(Gain) loss on derivatives, net28.6 (185.6) (57.1)Current period settlements on derivative contracts(c)(26.0) 122.2 6.4Flood insurance recovery(d)(27.3) — —Adjusted Petroleum EBITDA$602.0 $621.6 $712.0_______________________________________(a)FIFO is the petroleum business' basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in theinventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase andan unfavorable FIFO impact when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of theaccounting period and at the end of the accounting period.(b)Represents expense associated with major scheduled turnaround activities performed at the Coffeyville refinery ($102.2 million in 2015 and $5.5million in 2014) and the Wynnewood refinery ($1.3 million in 2014).(c)Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled withcounterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recoveryassociated with these contracts.(d)Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyvillerefinery on June/July 2007. Refer to Part II, Item 8, Note 13 ("Commitments and Contingencies") of this Report for further details.(6)Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries.We utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number ofbarrels sold for the period to derive the metric.73Table of Contents Year Ended December 31, 2015 2014 2013 (in millions)Coffeyville Refinery Financial Results Net sales$3,220.6 $5,755.5 $5,370.8Cost of product sold (exclusive of depreciation and amortization)2,626.1 5,254.9 4,648.6Direct operating expenses (exclusive of depreciation and amortization)209.1 223.6 219.4Major scheduled turnaround expenses102.2 5.5 —Flood insurance recovery(27.3) — —Depreciation and amortization72.1 73.6 70.8Gross profit$238.4 $197.9 $432.0Plus: Direct operating expenses and major scheduled turnaround expenses (exclusive ofdepreciation and amortization)311.3 229.1 219.4Flood insurance recovery(27.3) — —Depreciation and amortization72.1 73.6 70.8Refining margin$594.5 $500.6 $722.2 Year Ended December 31, 2015 2014 2013 (dollars per barrel)Coffeyville Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin$14.37 $11.46 $17.90Gross profit$5.77 $4.53 $10.71Direct operating expenses and major scheduled turnaround expenses (exclusive ofdepreciation and amortization)$7.53 $5.24 $5.44Direct operating expenses and major scheduled turnaround expenses (exclusive ofdepreciation and amortization) per barrel sold$6.92 $4.73 $5.00Barrels sold (barrels per day)123,279 132,791 120,16674Table of Contents Year Ended December 31, 2015 2014 2013 % % %Coffeyville Refinery Throughput and ProductionData (bpd) Throughput: Sweet96,727 79.5 103,018 80.0 90,818 77.1Medium2,058 1.7 1,222 1.0 453 0.4Heavy sour14,520 11.9 15,464 12.0 19,270 16.3Total crude oil throughput113,305 93.1 119,704 93.0 110,541 93.8All other feedstocks and blendstocks8,400 6.9 9,047 7.0 7,253 6.2Total throughput121,705 100.0 128,751 100.0 117,794 100.0Production: Gasoline57,815 46.5 64,002 48.6 56,262 46.8Distillate53,136 42.7 56,381 42.8 50,353 41.9Other (excluding internally produced fuel)13,503 10.8 11,314 8.6 13,499 11.3Total refining production (excluding internallyproduced fuel)124,454 100.0 131,697 100.0 120,114 100.0 Year Ended December 31, 2015 2014 2013 (in millions)Wynnewood Refinery Financial Results Net sales$1,936.9 $3,069.8 $3,308.4Cost of product sold (exclusive of depreciation and amortization)1,516.3 2,758.1 2,877.5Direct operating expenses (exclusive of depreciation and amortization)166.2 185.5 142.4Major scheduled turnaround expenses— 1.3 —Depreciation and amortization50.2 41.8 38.6Gross profit$204.2 $83.1 $249.9Plus: Direct operating expenses and major scheduled turnaround expenses (exclusive ofdepreciation and amortization)166.2 186.8 142.4Depreciation and amortization50.2 41.8 38.6Refining margin$420.6 $311.7 $430.9 Year Ended December 31, 2015 2014 2013 (dollars per barrel)Wynnewood Refinery Key Operating Statistics Per crude oil throughput barrel: Refining margin$14.44 $11.11 $15.33Gross profit$7.01 $2.96 $8.89Direct operating expenses and major scheduled turnaround expenses (exclusive ofdepreciation and amortization)$5.71 $6.66 $5.06Direct operating expenses and major scheduled turnaround expenses (exclusive ofdepreciation and amortization) per barrel sold$5.59 $6.66 $5.00Barrels sold (barrels per day)81,429 76,878 77,97675Table of Contents Year Ended December 31, 2015 2014 2013 % % %Wynnewood Refinery Throughput and ProductionData (bpd) Throughput: Sweet79,370 95.6 76,041 96.2 58,329 73.0Medium402 0.5 800 1.0 18,698 23.4Heavy sour— — — — — —Total crude oil throughput79,772 96.1 76,841 97.2 77,027 96.4All other feedstocks and blendstocks3,272 3.9 2,237 2.8 2,868 3.6Total throughput83,044 100.0 79,078 100.0 79,895 100.0Production: Gasoline42,146 51.7 38,273 49.5 38,299 49.0Distillate32,817 40.2 31,258 40.4 31,736 40.6Other (excluding internally produced fuel)6,571 8.1 7,835 10.1 8,118 10.4Total refining production (excluding internallyproduced fuel)81,534 100.0 77,366 100.0 78,153 100.0Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014 (Petroleum Business)Net Sales. Petroleum net sales were $5,161.9 million for the year ended December 31, 2015, compared to $8,829.7 million for the year endedDecember 31, 2014. The decrease of $3,667.8 million was largely the result of significantly lower sales prices for transportation fuels and by-products. Theaverage sales price per gallon for the year ended December 31, 2015 for gasoline of $1.61 and distillate of $1.62 decreased by approximately 36.4% and42.3%, respectively, as compared to the year ended December 31, 2014. Overall sales volume decreased approximately 3.3% for the year ended December 31,2015 compared to the year ended December 31, 2014. Sales volumes for 2015 were impacted by decreased production as a result of the major scheduledturnaround completed at the Coffeyville refinery in the fourth quarter of 2015 and lower purchased product volumes for resale. Sales volumes for 2014 wereimpacted by reduced crude oil throughput and production as a result of the Coffeyville refinery shutdown following the isomerization unit fire during thethird quarter of 2014 and the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014. The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the year ended December 31,2015 compared to the year ended December 31, 2014: Year Ended December 31, 2015 Year Ended December 31, 2014 Total Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) PriceVariance VolumeVariance (in millions)Gasoline40.1 $67.52 $2,708.4 40.3 $106.21 $4,282.2 (0.2) $(1,573.8) $(1,552.1) $(21.7)Distillate33.1 $68.01 $2,248.2 34.9 $118.09 $4,122.3 (1.8) $(1,874.1) $(1,656.4) $(217.7)_______________________________________(1)Barrels in millions(2)Sales dollars in millionsCost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost ofcrude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Petroleum cost of product sold(exclusive of depreciation and amortization) was $4,143.6 million for the year ended December 31, 2015, compared to $8,013.4 million for the year endedDecember 31, 2014. The decrease of $3,869.8 million was primarily the result of a decrease in the cost of consumed crude and purchased products for resale.The decrease in consumed crude oil cost was due to a decrease in crude oil throughput volume and crude oil prices. The WTI benchmark crude oil pricedecreased 47.5% from the year ended December 31, 2015 as compared to the year ended December 31, 2014. The petroleum business' average cost per barrelof crude oil consumed for the year ended December 31,76Table of Contents2015 was $47.86 compared to $92.57 for the year ended December 31, 2014, a decrease of approximately 48.3%. Crude oil throughput volume decreased byapproximately 1.8% for the year ended December 31, 2015 as compared to the equivalent period in 2014 due primarily to the major scheduled turnaroundcompleted at the Coffeyville refinery in the fourth quarter of 2015. Sales volumes of refined fuels decreased by approximately 3.3% during the same period.The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under the FIFO accounting method, changes in crudeoil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventoryimpact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the years ended December 31, 2015 and2014, the petroleum business had an unfavorable FIFO inventory impact of $60.3 million compared to an unfavorable FIFO inventory impact of $160.8million, respectively. The major factor contributing to the unfavorable FIFO impact for the year ended December 31, 2014 was the decline in the market priceof WTI from $95.44 at the beginning of 2014 to $53.27 on December 31, 2014. The FIFO inventory impact for 2014 included a lower of cost or market write-down of $36.8 million, which was recorded in the fourth quarter as a result of the significant decline in the market price of crude oil.Refining margin per barrel of crude oil throughput increased to $14.45 for the year ended December 31, 2015 from $11.38 for the year endedDecember 31, 2014. Refining margin adjusted for FIFO impact was $15.31 per crude oil throughput barrel for the year ended December 31, 2015, ascompared to $13.62 per crude oil throughput barrel for the year ended December 31, 2014. Gross profit per barrel increased to $6.20 for the year endedDecember 31, 2015, as compared to gross profit per barrel of $3.87 in the equivalent period in 2014. The increase in refining margin and gross profit perbarrel was primarily due to the higher unfavorable FIFO impact in 2014 as result of the significant decline in the market price of crude oil.Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) forthe petroleum business include costs associated with the operations of the refineries, such as energy and utility costs, property taxes, catalyst and chemicalcosts, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses and major scheduled turnaround expenses(exclusive of depreciation and amortization) were $478.5 million for the year ended December 31, 2015, compared to direct operating expenses and majorscheduled turnaround expenses of $416.0 million for the year ended December 31, 2014. The increase of $62.5 million was primarily the result of majorscheduled turnaround activities performed at the Coffeyville refinery ($95.4 million), partially offset by decreases in repair and maintenance costs ($22.1million) and energy and utility costs ($18.9 million). The decrease in repairs and maintenance costs was due to opportunity maintenance performed at theCoffeyville refinery during the shutdown following the isomerization fire in the third quarter of 2014 and during the FCCU outage at the Wynnewoodrefinery during the fourth quarter of 2014. The decrease in energy and utility costs was due to a 27.6% decrease in natural gas cost per unit and a 14.7%decrease in natural gas consumption. Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2015 increased to $6.79per barrel as compared to $5.80 per barrel for the year ended December 31, 2014. The increase in the direct operating expenses per barrel of crude oilthroughput was primarily a function of higher overall expenses.Operating Income. Petroleum operating income was $361.7 million for the year ended December 31, 2015, as compared to operating income of $207.2million for the year ended December 31, 2014. The increase of $154.5 million was the result of an increase in the refining margin ($202.0 million) and theflood insurance recovery ($27.3 million), partially offset by increases in direct operating expenses ($62.5 million), depreciation and amortization ($7.7million) and selling, general and administrative expenses ($4.6 million).Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013 (Petroleum Business)Net Sales. Petroleum net sales were $8,829.7 million for the year ended December 31, 2014, compared to $8,683.5 million for the year endedDecember 31, 2013. The increase of $146.2 million was primarily the result of higher overall sales volumes largely offset by lower sales prices for gasolineand distillates. Overall sales volume increased 8.4% for the year ended December 31, 2014 compared to the year ended December 31, 2013. Sales volumes for2014 were impacted by reduced crude oil throughput and production as a result of the Coffeyville refinery shutdown following the isomerization unit fireduring the third quarter of 2014 and the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014. Sales volumes for 2013 were impactedby downtime associated with the FCCU outage at the Coffeyville refinery in the third quarter of 2013. The average sales price per gallon for the year endedDecember 31, 2014 for gasoline of $2.53 and distillate of $2.81 each decreased by approximately 7.0%, as compared to the year ended December 31, 2013.77Table of ContentsThe following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the year ended December 31,2014 compared to the year ended December 31, 2013: Year Ended December 31, 2014 Year Ended December 31, 2013 Total Variance Volume(1) $ per barrel Sales $(2) Volume(1) $ per barrel Sales $(2) Volume(1) Sales $(2) PriceVariance VolumeVariance (in millions)Gasoline40.3 $106.21 $4,282.2 37.8 $114.29 $4,330.0 2.5 $(47.8) $(325.9) $278.1Distillate34.9 $118.09 $4,122.3 30.6 $126.79 $3,880.6 4.3 $241.7 $(303.5) $545.2_______________________________________(1)Barrels in millions(2)Sales dollars in millionsCost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost ofcrude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Petroleum cost of product sold(exclusive of depreciation and amortization) was $8,013.4 million for the year ended December 31, 2014, compared to $7,526.7 million for the year endedDecember 31, 2013. The increase of $486.7 million was primarily the result of an increase in the cost of consumed crude oil and refined fuels purchased forresale. The increase in consumed crude oil cost was due to a 4.8% increase in consumed volumes, which was partially offset by lower crude oil prices. Theaverage cost per barrel of crude oil consumed for the year ended December 31, 2014 was $92.57 compared to $95.05 for the year ended December 31, 2013, adecrease of approximately 2.6%. Sales volumes of refined fuels increased by approximately 8.4%. The impact of FIFO accounting also impacted cost ofproduct sold during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventoryvaluation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and anunfavorable FIFO inventory impact when crude oil prices decrease. For the years ended December 31, 2014 and 2013, the petroleum business had anunfavorable FIFO inventory impact of $160.8 million compared to a favorable FIFO inventory impact of $21.3 million, respectively. The major factorcontributing to the unfavorable FIFO impact for the year ended December 31, 2014 was the decline in the market price of WTI from $95.44 at the beginningof 2014 to $53.27 on December 31, 2014. The FIFO inventory impact for 2014 includes a lower of cost or market write-down of $36.8 million, which wasrecorded in the fourth quarter as a result of the significant decline in the market price of crude oil.Refining margin per barrel of crude oil throughput decreased to $11.38 for the year ended December 31, 2014 from $16.90 for the year endedDecember 31, 2013. Refining margin adjusted for FIFO impact was $13.62 per crude oil throughput barrel for the year ended December 31, 2014, ascompared to $16.59 per crude oil throughput barrel for the year ended December 31, 2013. Gross profit per barrel decreased to $3.87 for the year endedDecember 31, 2014, as compared to gross profit per barrel of $9.94 in the equivalent period in 2013. The decrease in refining margin and gross profit perbarrel was primarily due to a decrease in sales prices of gasoline and distillate. The average sales price for both gasoline and distillates declinedapproximately 7.0% for the year ended December 31, 2014 as compared to the same period last year.Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) forthe petroleum business include costs associated with the operations of the refineries, such as energy and utility costs, property taxes, catalyst and chemicalcosts, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses and major scheduled turnaround expenses(exclusive of depreciation and amortization) were $416.0 million for the year ended December 31, 2014, compared to direct operating expenses of $361.7million for the year ended December 31, 2013. The increase of $54.3 million was primarily the result of the increase in expenses associated with energy andutility costs ($18.1 million), repairs and maintenance ($10.2 million), labor ($8.9 million), certain turnaround activities performed at the Coffeyville andWynnewood refineries ($6.8 million), production chemicals ($4.7 million) and rental costs ($4.5 million). The increase in energy and utility costs wasprimarily due to a 27.3% increase in natural gas cost per unit and a 12.5% increase in natural gas consumption. The increase in repairs and maintenance andturnaround costs was due to opportunity maintenance and turnaround activities performed at the Coffeyville refinery during the shutdown following theisomerization fire in the third quarter of 2014 and during the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014. Direct operatingexpenses per barrel of crude oil throughput for the year ended December 31, 2014 increased to $5.80 per barrel as compared to $5.28 per barrel for the yearended December 31, 2013. The increase in the direct operating expenses per barrel of crude oil throughput was primarily a function of higher overallexpenses.Operating Income. Petroleum operating income was $207.2 million for the year ended December 31, 2014, as compared to operating income of $603.0million for the year ended December 31, 2013. The decrease of $395.8 million was the result of78Table of Contentsa decrease in the refining margin ($340.5 million) and increases in direct operating expenses ($54.3 million) and depreciation and amortization ($8.2million), partially offset by a decrease in selling, general and administrative expenses ($7.2 million).Nitrogen Fertilizer Business Results of OperationsThe tables below provide an overview of the nitrogen fertilizer business' results of operations, relevant market indicators and its key operating statisticsfor the years ended December 31, 2015, 2014 and 2013: Year Ended December 31,2015 2014 2013 (in millions)Nitrogen Fertilizer Business Financial Results Net sales$289.2 $298.7 $323.7Cost of product sold(1)65.2 72.0 58.1Direct operating expenses(1)99.1 98.9 94.1Major scheduled turnaround expenses7.0 — —Selling, general and administrative(1)20.8 17.7 21.0Depreciation and amortization28.4 27.3 25.6Operating income68.7 82.8 124.9Interest expense and other financing costs(7.0) (6.7) (6.3)Other income, net0.3 — 0.1Income before income tax expense62.0 76.1 118.7Income tax expense— — 0.1Net income$62.0 $76.1 $118.6 Adjusted Nitrogen Fertilizer EBITDA(2)$106.8 $110.3 $152.879Table of Contents Year Ended December 31,2015 2014 2013Key Operating Statistics Production volume (thousand tons): Ammonia (gross produced)(3)385.4 388.9 402.0Ammonia (net available for sale)(3)(4)37.3 28.3 37.9UAN928.6 963.7 930.6 Pet coke consumed (thousand tons)469.9 489.7 487.0Pet coke (cost per ton)$25 $28 $30 Sales (thousand tons): Ammonia32.3 24.4 40.5UAN939.5 951.0 904.6 Product pricing at gate (dollars per ton)(5): Ammonia$521 $518 $643UAN$247 $259 $282 On-stream factors(6): Gasification90.2% 96.8% 95.6%Ammonia87.5% 92.6% 94.4%UAN87.3% 92.0% 91.9% Reconciliation to net sales (dollars in millions): Sales net at gate$248.8 $259.3 $281.5Freight in revenue27.2 27.5 30.2Hydrogen revenue11.8 10.1 11.4Other revenue1.4 1.8 0.6Total net sales$289.2 $298.7 $323.7 Year Ended December 31, 2015 2014 2013Market Indicators Natural gas NYMEX (dollars per MMBtu)$2.63 $4.26 $3.73Ammonia — Southern Plains (dollars per ton)510 539 581UAN — Corn belt (dollars per ton)284 314 337_______________________________________(1)Amounts are shown exclusive of depreciation and amortization.(2)Nitrogen Fertilizer EBITDA represents nitrogen fertilizer net income adjusted for (i) interest expense and other financing costs, net of interestincome, (ii) income tax expense and (iii) depreciation and amortization. Adjusted Nitrogen Fertilizer EBITDA represents Nitrogen Fertilizer EBITDAadjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, (iii) loss on extinguishment of debt and (iv) expensesassociated with the pending Rentech Nitrogen mergers, as applicable. We present Adjusted Nitrogen Fertilizer EBITDA because we have found ithelpful to consider an operating measure that excludes expenses, such as major scheduled turnaround expense, loss on extinguishment of debt andexpenses associated with the pending Rentech Nitrogen mergers, relating to transactions not reflective of the Nitrogen Fertilizer Partnership's coreoperations. In addition, we believe that it is useful to exclude from Adjusted Nitrogen Fertilizer EBITDA share-based compensation, non-cash,although it is a80Table of Contentsrecurring cost incurred in the ordinary course of business. We believe share-based compensation, non-cash, reflects a non-cash cost which mayobscure, for a given period, trends in the underlying business, due to the timing and nature of the equity awards.We also present Adjusted Nitrogen Fertilizer EBITDA because it is the starting point for calculating the Nitrogen Fertilizer Partnership's availablecash for distribution. Adjusted Nitrogen Fertilizer EBITDA is not a recognized term under GAAP and should not be substituted for net income as ameasure of performance. Management believes that Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDA enable investors andanalysts to better understand the Nitrogen Fertilizer Partnership's ability to make distributions to its common unitholders, help investors andanalysts evaluate its ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economicperformance by allowing investors to evaluate the same information used by management. Nitrogen Fertilizer EBITDA and Adjusted NitrogenFertilizer EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently.Below is a reconciliation of net income for the nitrogen fertilizer segment to Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDAfor the years ended December 31, 2015, 2014 and 2013: Year Ended December 31, 2015 2014 2013 (in millions)Nitrogen Fertilizer: Nitrogen Fertilizer net income$62.0 $76.1 $118.6Add: Interest expense and other financing costs, net7.0 6.7 6.3Income tax expense— — 0.1Depreciation and amortization28.4 27.3 25.6Nitrogen Fertilizer EBITDA97.4 110.1 150.6Add: Share-based compensation, non-cash0.1 0.2 2.2Major scheduled turnaround expenses7.0 — —Expenses associated with the Rentech Nitrogen mergers2.3 — —Adjusted Nitrogen Fertilizer EBITDA$106.8 $110.3 $152.8(3)Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. Net tonsavailable for sale represent the ammonia available for sale that was not upgraded into UAN.(4)In addition to produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately 29,300, 33,600 and 17,300 tons of ammonia duringthe years ended December 31, 2015, 2014 and 2013, respectively.(5)Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricingmeasure that is comparable across the fertilizer industry.(6)On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is a measure of operatingefficiency. Excluding the impact of the full facility turnaround and the Linde air separation unit outages, (i) the on-stream factors in 2015 wouldhave been 99.9% for gasification, 97.7% for ammonia and 97.6% for UAN. Excluding the impact of the downtime associated with the installation ofthe waste heat boiler, the PSA unit upgrade and the Linde air separation unit maintenance (ii) the on-stream factors in 2014 would have been 98.2%for gasification, 94.3% for ammonia and 93.7% for UAN. Excluding the impact of the UAN expansion coming online, the planned downtimeassociated with the replacement of damaged catalyst, the unplanned Linde air separation unit outages and the unplanned downtime associated withweather issues (iii) the on-stream factors in 2013 would have been 99.5% for gasification, 98.9% for ammonia and 98.0% for UAN.81Table of ContentsYear Ended December 31, 2015 compared to the Year Ended December 31, 2014 (Nitrogen Fertilizer Business)Net Sales. Nitrogen fertilizer net sales were $289.2 million for the year ended December 31, 2015, compared to $298.7 million for the year endedDecember 31, 2014. The net sales decrease of $9.5 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014 wasprimarily the result of lower UAN sales prices ($11.6 million), lower UAN sales volumes ($3.3 million) and lower hydrogen sales prices ($0.3 million),partially offset by higher ammonia sales volumes ($4.2 million) and higher hydrogen sales volumes ($2.0 million). For the year ended December 31, 2015,UAN, ammonia and hydrogen made up $258.8 million, $17.2 million and $11.8 million of the nitrogen fertilizer business' net sales, respectively. Thiscompared to UAN, ammonia and hydrogen net sales of $273.7 million, $13.1 million and $10.1 million, respectively, for the year ended December 31, 2014.The following table demonstrates the impact of changes in sales volumes and sales price for UAN, ammonia and hydrogen for the year ended December 31,2015 compared to the year ended December 31, 2014: Year Ended December 31, 2015 Year Ended December 31, 2014 Total Variance Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) PriceVariance VolumeVariance (in millions)UAN939,547 $275 $258.8 951,043 $288 $273.7 (11,496) $(14.9) $(11.6) $(3.3)Ammonia32,326 $533 $17.2 24,378 $536 $13.1 7,948 $4.1 $(0.1) $4.2Hydrogen1,196,320 $10 $11.8 996,516 $10 $10.1 199,804 $1.7 $(0.3) $2.0_______________________________________(1)UAN and ammonia sales volumes are in tons. Hydrogen sales volumes are in MSCF.(2)Includes freight charges. Hydrogen is reflected as $ per MSCF.(3)Sales dollars in millions.For the year ended December 31, 2015 compared to the year ended December 31, 2014, the nitrogen fertilizer segment's operations experienced adecrease of 1.2% in UAN sales unit volumes and an increase of 32.6% in ammonia sales unit volumes. The decrease in UAN sales volumes for the year endedDecember 31, 2015 compared to the year ended December 31, 2014 was partially attributable to the 2015 turnaround and the Linde air separation unit relatedoutages. The increase in ammonia sales for the year ended December 31, 2015 compared to the year ended December 31, 2014 was partially attributable tohigher customer demand.Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. Product pricing at gate for UAN decreasedapproximately 4.6% for the year ended December 31, 2015 as compared to the year ended December 31, 2014. Product pricing at gate for ammonia increasedapproximately 0.6% for the year ended December 31, 2015 as compared to the year ended December 31, 2014.Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold (exclusive of depreciation andamortization) includes cost of freight and distribution expenses, pet coke expenses, purchased ammonia and purchased hydrogen. Cost of product soldexcluding depreciation and amortization for the year ended December 31, 2015 was $65.2 million, compared to $72.0 million for the year endedDecember 31, 2014. The $6.8 million decrease was primarily the result of lower consumption of pet coke mostly due to the decrease in production during theturnaround and the Linde air separation unit related downtime, lower pet coke pricing, decreased distribution costs, freight expenses and purchased ammonia.The lower distribution costs is due to a smaller portion of the nitrogen fertilizer business' fleet due for regulatory inspections and related repairs during theyear ended December 31, 2015 as compared to the year ended December 31, 2014.Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) forthe nitrogen fertilizer business consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services, includingturnaround, and environmental and safety compliance costs as well as catalyst and chemical costs. Nitrogen fertilizer direct operating expenses (exclusive ofdepreciation and amortization) for the year ended December 31, 2015 were $106.1 million, as compared to $98.9 million for the year ended December 31,2014. The total increase of $7.2 million for the year ended December 31, 2015, as compared to the year ended December 31, 2014, resulted primarily fromhigher turnaround expenses ($7.0 million), personnel costs ($2.9 million) and repairs and maintenance ($2.2 million), partially offset by lower utilities, net($2.3 million), refractory brick amortization ($2.2 million) and outside services ($1.8 million). The increase in personnel costs is partially attributable to theincreased efforts required to complete activities during downtime. The increase in repairs and maintenance is due to the nitrogen fertilizer business being ableto perform an increased amount of normal repairs and maintenance during the downtime. The lower utilities, net are primarily the result of lower usage duringthe downtime from the turnaround and the Linde outages.82Table of ContentsOperating Income. Nitrogen fertilizer operating income was $68.7 million for the year ended December 31, 2015, as compared to operating income of$82.8 million for the year ended December 31, 2014. The decrease of $14.1 million for the year ended December 31, 2015 as compared to the year endedDecember 31, 2014 was the result of the decrease in net sales ($9.5 million) and increases in direct operating expenses ($7.2 million), selling, general andadministrative expenses ($3.1 million) and depreciation and amortization ($1.1 million), partially offset by a decrease in cost of product sold ($6.8 million).Year Ended December 31, 2014 compared to the Year Ended December 31, 2013 (Nitrogen Fertilizer Business)Net Sales. Nitrogen fertilizer net sales were $298.7 million for the year ended December 31, 2014, compared to $323.7 million for the year endedDecember 31, 2013. The net sales decrease of $25.0 million was the result of lower UAN sales prices ($25.8 million), lower ammonia sales volumes ($10.7million) and lower ammonia sales prices ($3.0 million), partially offset by higher UAN sales volumes ($14.6 million). For the year ended December 31, 2014,UAN, ammonia and hydrogen made up $273.7 million, $13.1 million and $10.1 million of the nitrogen fertilizer business' net sales, respectively. Thiscompared to UAN, ammonia and hydrogen net sales of $284.9 million, $26.8 million and $11.4 million, respectively, for the year ended December 31, 2013.The following table demonstrates the impact of changes in sales volumes and sales price for UAN, ammonia and hydrogen for the year ended December 31,2014 compared to the year ended December 31, 2013: Year Ended December 31, 2014 Year Ended December 31, 2013 Total Variance Volume(1) $ per ton(2) Sales $(3) Volume(1) $ per ton(2) Sales $(3) Volume(1) Sales $(3) PriceVariance VolumeVariance (in millions)UAN951,043 $288 $273.7 904,596 $315 $284.9 46,447 $(11.2) $(25.8) $14.6Ammonia24,378 $536 $13.1 40,535 $660 $26.8 (16,157) $(13.7) $(3.0) $(10.7)Hydrogen996,516 $10 $10.1 1,165,300 $10 $11.4 (168,784) $(1.3) $0.3 $(1.6)_______________________________________(1)UAN and ammonia sales volumes are in tons. Hydrogen sales volumes are in MSCF.(2)Includes freight charges. Hydrogen is reflected as $ per MSCF.(3)Sales dollars in millions.For the year ended December 31, 2014, the nitrogen fertilizer segment's operations experienced an increase of 5.1% in UAN sales unit volumes and adecrease of 39.9% in ammonia sales unit volumes. The increase in UAN and decrease in ammonia sales volume for the year ended December 31, 2014compared to the year ended December 31, 2013 was partially attributable to the UAN expansion being available for the full period in 2014.Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. Product pricing at gate for the year endedDecember 31, 2014 compared to the year ended December 31, 2013 decreased approximately 8.2% for UAN and 19.4% for ammonia, respectively.Cost of Product Sold (Exclusive of Depreciation and Amortization). Nitrogen fertilizer cost of product sold (exclusive of depreciation andamortization) includes cost of freight and distribution expenses, pet coke expenses, purchased ammonia and purchased hydrogen. Cost of product soldexcluding depreciation and amortization for the year ended December 31, 2014 was $72.0 million, compared to $58.1 million for the year endedDecember 31, 2013. The $13.9 million increase resulted from $15.3 million in higher costs from transactions with third parties, which is offset by lower costsfrom transactions with affiliates of $1.4 million. The higher third-party costs incurred during the year ended December 31, 2014 were primarily the result ofincreased distribution costs ($10.5 million) mostly due to the increase in railcar regulatory inspections and repairs as well as increased ammonia purchases($6.5 million), partially offset by lower freight and pet coke expenses. The increase in railcar regulatory inspections and repairs is related to a larger portion ofthe nitrogen fertilizer business' fleet due for regulatory inspections and related repairs during the year ended December 31, 2014 as compared to the prioryear.Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) forthe nitrogen fertilizer business consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services andenvironmental and safety compliance costs as well as catalyst and chemical costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation andamortization) for the year ended December 31, 2014 were $98.9 million, as compared to $94.1 million for the year ended December 31, 2013. The totalincrease of $4.8 million for the year ended December 31, 2014, as compared to the year ended December 31, 2013, was comprised of a $5.9 million increasein costs from transactions with third parties, partially offset by a $1.1 million decrease in direct operating83Table of Contentscosts from affiliates. The increase resulted primarily from higher utilities, net ($1.3 million), refractory brick amortization ($2.7 million), repairs andmaintenance ($1.2 million), partially offset by lower insurance costs ($1.1 million). The increased utility costs were largely due to higher electrical andnatural gas prices, partially offset by lower electrical volumes. The increase in refractory brick amortization is primarily due to a decrease in the estimateduseful life to reflect higher estimated rates of use in the production process.Operating Income. Nitrogen fertilizer operating income was $82.8 million for the year ended December 31, 2014, as compared to operating income of$124.9 million for the year ended December 31, 2013. The decrease of $42.1 million for the year ended December 31, 2014 as compared to the year endedDecember 31, 2013 was the result of the decrease in net sales ($25.0 million) and increases in cost of products sold ($13.9 million), direct operating expenses($4.8 million) and depreciation and amortization ($1.7 million), partially offset by a decrease in selling, general and administrative expense ($3.3 million).Liquidity and Capital ResourcesAlthough results are consolidated for financial reporting, CVR Energy, CVR Refining and CVR Partners are independent business entities and operatewith independent capital structures. Since the Nitrogen Fertilizer Partnership's IPO in April 2011 and the Refining Partnership's IPO in January 2013, with theexception of cash distributions paid to us by the Nitrogen Fertilizer Partnership and the Refining Partnership, the cash needs of the Nitrogen FertilizerPartnership and the Refining Partnership have been met independently from the cash needs of CVR Energy and each other with a combination of existingcash and cash equivalent balances, cash generated from operating activities and credit facility borrowings. The Refining Partnership's and the NitrogenFertilizer Partnership's ability to generate sufficient cash flows from their respective operating activities and to then make distributions on their commonunits, including to us (which we will need to pay salaries, reporting expenses and other expenses as well as dividends on our common stock) will continue tobe primarily dependent on producing or purchasing, and selling, sufficient quantities of refined and nitrogen fertilizer products at margins sufficient to coverfixed and variable expenses.We believe that the petroleum business and the nitrogen fertilizer business' cash flows from operations and existing cash and cash equivalents, alongwith borrowings under their respective existing credit facilities as necessary, will be sufficient to satisfy the anticipated cash requirements associated withtheir existing operations for at least the next twelve months, and that we have sufficient cash resources to fund our operations for at least the next twelvemonths. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors.Additionally, the ability to generate sufficient cash from operating activities depends on future performance, which is subject to general economic, political,financial, competitive, and other factors outside our control.Cash Balances and Other LiquidityAs of December 31, 2015, we had consolidated cash and cash equivalents of $765.1 million. Of that amount, $527.8 million was cash and cashequivalents of CVR Energy, $187.3 million was cash and cash equivalents of the Refining Partnership and $50.0 million was cash and cash equivalents ofthe Nitrogen Fertilizer Partnership. As of February 16, 2016, we had consolidated cash and cash equivalents of approximately $796.6 million.The Amended and Restated ABL Credit Facility provides the Refining Partnership with borrowing availability of up to $400.0 million with anincremental facility, subject to compliance with a borrowing base. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20,2017. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Refining Partnership and thecredit facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowingbase conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit. Asof February 16, 2016, the Refining Partnership had $262.1 million available under the Amended and Restated ABL Credit Facility. Availability under theAmended and Restated ABL Credit Facility was limited by borrowing base conditions.The Nitrogen Fertilizer Partnership's credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with anuncommitted incremental facility of up to $50.0 million. The Nitrogen Fertilizer Partnership's credit facility matures in April 2016. The Nitrogen FertilizerPartnership's credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As ofFebruary 16, 2016, the Nitrogen Fertilizer Partnership had $25.0 million available under the credit facility.As discussed in Note 9 ("Long-Term Debt") to Part II, Item 8 of this Report, the Nitrogen Fertilizer Partnership's credit facility matures in April 2016, andthe $125.0 million principal portion of the term loan facility is presented as a current84Table of Contentsliability as of December 31, 2015. On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLCagreed to guaranty the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. Refer to Note 9 ("Long-Term Debt") to Part II, Item8 of this Report for discussion of the guaranty. The Nitrogen Fertilizer Partnership is considering various capital structure and refinancing options in regard tothe credit facility and in contemplation of the Rentech Nitrogen mergers as discussed in "Pending Mergers." The Nitrogen Fertilizer Partnership anticipatesthese options will be adequate to fund the cash requirements of the maturing credit facility and the pending mergers.Simultaneously with the execution of the Merger Agreement discussed in Part II, Item 8, Note 1 ("Organization and History of the Company") of thisReport, the Nitrogen Fertilizer Partnership entered into a commitment letter with CRLLC, pursuant to which CRLLC has committed to, on the terms andsubject to the conditions set forth in the commitment letter, make available to CVR Partners term loan financing of up to $150.0 million, which amountswould be available solely to fund the repayment of all of the loans outstanding under Rentech Nitrogen's existing $50.0 million credit facility with GeneralElectric Capital Corporation, the cash consideration payable by the Nitrogen Fertilizer Partnership upon closing of the mergers and expenses associated withthe mergers. The term loan facility will bear interest at a rate of three-month LIBOR plus 3.0% per annum. Calculation of interest shall be on the basis of theactual number of days elapsed over a 360-day year. Such term loan, if drawn, would have a one-year term.The Refining Partnership and the Nitrogen Fertilizer Partnership have distribution policies in which they generally distribute all of their available casheach quarter, within 60 days after the end of each quarter. The Refining Partnership's distributions began with the quarter ended March 31, 2013 and wereadjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO). Thedistributions are made to all common unitholders. As of December 31, 2015, we held approximately 66% and 53% of the Refining Partnership's and theNitrogen Fertilizer Partnership's common units outstanding, respectively. The amount of each distribution will be determined pursuant to each generalpartner's calculation of available cash for the applicable quarter. The general partner of each partnership, as a non-economic interest holder, is not entitled toreceive cash distributions. As a result of each general partner's distribution policy, funds held by the Refining Partnership and the Nitrogen FertilizerPartnership will not be available for our use, and we as a unitholder will receive our applicable percentage of the distribution of funds within 60 daysfollowing each quarter. The Refining Partnership and the Nitrogen Fertilizer Partnership do not have a legal obligation to pay distributions and there is noguarantee that they will pay any distributions on the units in any quarter.Borrowing Activities2022 Notes. On October 23, 2012, CVR Refining, LLC ("Refining LLC") and its wholly-owned subsidiary, Coffeyville Finance Inc. ("CoffeyvilleFinance"), issued $500.0 million aggregate principal amount of the 2022 Notes. The net proceeds from the offering of the 2022 Notes were used to purchaseall of the First Lien Secured Notes due 2015 through a tender offer and settled redemption in the fourth quarter of 2012.The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interestexpense using the effective-interest amortization method. As of December 31, 2015, the 2022 Notes had an aggregate principal balance and a net carryingvalue of $500.0 million.The 2022 Notes were issued by Refining LLC and Coffeyville Finance and are fully and unconditionally guaranteed by CVR Refining and each ofRefining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) on a joint and several basis. CVR Refining has no independentassets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction and discharge of the Second Lien Notes,which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, CVR Partners and CRNF are not guarantors. The 2022Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that theoutstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes were no longersecured as of and after January 23, 2013.On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered exchange offer, whereby all $500.0 million of the outstanding2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchangeoffer fulfilled the Refining Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022Notes. The Refining Partnership incurred approximately $0.4 million of debt registration costs related to the registration and exchange offer during the yearended December 31, 2013, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method.85Table of ContentsThe 2022 Notes bear interest at a rate of 6.5% per annum and mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interestis payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, to holders of record at the close of business on April 15 and October 15,as the case may be, immediately preceding each such interest payment date.The issuers have the right to redeem the 2022 Notes at a redemption price of (i) 103.250% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the twelve-month period beginning onNovember 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2019; and(iv) 100% of the principal amount, if redeemed on or after November 1, 2020, in each case, plus any accrued and unpaid interest. Prior to November 1, 2017,some or all of the 2022 Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued andunpaid interest.In the event of a "change of control," the issuers are required to offer to buy back all of the 2022 Notes at 101% of their principal amount. A change ofcontrol is generally defined as (i) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of Refining LLC to anyperson other than qualifying owners (as defined in the indenture), (ii) liquidation or dissolution of Refining LLC, or (iii) any person, other than a qualifyingowner, directly or indirectly acquiring 50% of the voting stock of Refining LLC.The indenture governing the 2022 Notes imposes covenants that restrict the ability of the issuers and subsidiary guarantors to (i) issue debt, (ii) incur orotherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated orunsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of theirassets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes are ratedinvestment grade by both Standard & Poor's Rating Services and Moody's Investors Services, Inc. However, such covenants would be reinstituted if the 2022Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would resultin, or permit the trustee or the holders of at least 25% of the 2022 Notes to cause, the acceleration of the 2022 Notes, in addition to the pursuit of otheravailable remedies.The indenture governing the 2022 Notes prohibits the Refining Partnership from making distributions to its unitholders if any default or event of default(as defined in the indenture) exists. In addition, the indenture limits the Refining Partnership's ability to pay distributions to unitholders. The covenants willapply differently depending on the Refining Partnership's fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is notless than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, withoutsubstantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restrictedpayments, including distributions to its unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds"under the indenture. The Refining Partnership was in compliance with the covenants as of December 31, 2015, and the ratio was satisfied (not less than 2.5 to1.0).Amended and Restated Asset Based (ABL) Credit Facility. On December 20, 2012, CRLLC and certain subsidiaries (collectively, the "Credit Parties")entered into the Amended and Restated ABL Credit Facility with Wells Fargo Bank, National Association, as administrative agent and collateral agent for asyndicate of lenders. The Amended and Restated ABL Credit Facility replaced our prior ABL credit facility. Under the Amended and Restated ABL CreditFacility, the Refining Partnership assumed our position as borrower and our obligations under the Amended and Restated ABL Credit Facility upon theclosing of the Refining Partnership IPO on January 23, 2013. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving creditfacility, with sub-limits for letters of credit and swing line loans of $360.0 million and $40.0 million, respectively. The Amended and Restated ABL CreditFacility also includes a $200.0 million uncommitted incremental facility. The Amended and Restated ABL Credit Facility permits the payment ofdistributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all timesduring the three-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excessavailability and projected excess availability for the six-month period following the distribution is greater than 25% at all times, then the followingcondition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to orgreater than 1.10 to 1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and may be used for working capital and other generalcorporate purposes (including permitted acquisitions).Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicablemargin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% ofthe lesser of the borrowing base and the total commitments86Table of Contentsand (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customaryfees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of theborrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50%of the lesser of the borrowing base and the total commitments. The Refining Partnership is also required to pay customary letter of credit fees equal to, forstandby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, theapplicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the faceamount of, each letter of credit.The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Partiesand their subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness,make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amendedand restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. The Refining Partnership was in compliancewith the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2015.Old Senior Secured Notes. On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance completed the private offering of$225.0 million aggregate principal amount of Old Second Lien Notes. We redeemed all outstanding Old Second Lien Notes on January 23, 2013, followingthe closing of the Refining Partnership IPO, with a combination of proceeds from the Refining Partnership IPO and cash on hand.Nitrogen Fertilizer Partnership Credit Facility. On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, enteredinto a credit facility (the "Nitrogen Fertilizer Partnership credit facility") with a group of lenders including Goldman Sachs Lending Partners LLC, asadministrative and collateral agent. The Nitrogen Fertilizer Partnership credit facility includes a term loan facility of $125.0 million and a revolving creditfacility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the Nitrogen FertilizerPartnership credit facility matures in April 2016, as discussed above.Borrowings under the Nitrogen Fertilizer Partnership credit facility bear interest based on a pricing grid determined by the trailing four quarter leverageratio. The initial pricing for Eurodollar rate loans under the Nitrogen Fertilizer Partnership credit facility is the Eurodollar rate plus a margin of 3.50%, or forbase rate loans, the prime rate plus 2.50%. Under its terms, the lenders under the Nitrogen Fertilizer Partnership credit facility were granted a perfected, firstpriority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Nitrogen Fertilizer Partnership and all ofthe capital stock of CRNF and each domestic subsidiary owned by the Nitrogen Fertilizer Partnership or CRNF. CRNF is the borrower under the NitrogenFertilizer Partnership credit facility. All obligations under the Nitrogen Fertilizer Partnership credit facility are unconditionally guaranteed by the NitrogenFertilizer Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility are non-recourse to theCompany and its direct subsidiaries.As of December 31, 2015, no amounts were drawn under the Nitrogen Fertilizer Partnership's $25.0 million revolving credit facility.An event of default under the Nitrogen Fertilizer Partnership credit facility will be triggered if CVR Energy or any of its subsidiaries (other than theNitrogen Fertilizer Partnership and CRNF) terminates or violates any of its covenants in any of the intercompany agreements between the Nitrogen FertilizerPartnership and CVR Energy and its subsidiaries (other than the Nitrogen Fertilizer Partnership and CRNF) and such action has a material adverse effect onthe Nitrogen Fertilizer Partnership. If an event of default occurs, the administrative agent under the Nitrogen Fertilizer Partnership credit facility would beentitled to take various actions, including the acceleration of amounts due under the credit facility and all actions permitted to be taken by a secured creditor.Nitrogen Fertilizer Partnership Interest Rate SwapsThe Nitrogen Fertilizer Partnership has determined that the two interest rate swap agreements entered into in 2011 qualify for hedge accountingtreatment. The impact recorded for each of the years ended December 31, 2015, 2014 and 2013 was $1.1 million, in additional interest expense. For the yearsended December 31, 2015, 2014 and 2013, the Nitrogen Fertilizer Partnership recorded a decrease in fair market value on the interest rate swaps of $0.1million, $0.2 million and $0.2 million, respectively, which was unrealized in accumulated other comprehensive income (loss) ("AOCI"). The combined fairmarket87Table of Contentsvalue of the interest rate swaps recorded in other current liabilities on the Consolidated Balance Sheets at December 31, 2015 is not material. This amount isunrealized and, therefore, included in AOCI.Capital SpendingWe divide the petroleum business and the nitrogen fertilizer business' capital spending needs into two categories: maintenance and growth. Maintenancecapital 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 involvean expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses areexpensed when incurred.The following table summarizes our total actual capital expenditures for 2015 and current estimated capital expenditures in 2016 by operating segmentand major category. These estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in themanner allocated below: Year Ended December 31, 2015 Actual 2016 Estimate (in millions) (unaudited)Petroleum Business (the Refining Partnership): Coffeyville refinery: Maintenance$69.7 $60.0Growth73.2 50.0Coffeyville refinery total capital excluding major scheduled turnaround expenses142.9 110.0Wynnewood refinery: Maintenance25.6 40.0Growth6.4 6.0Wynnewood refinery total capital excluding major scheduled turnaround expenses32.0 46.0Other Petroleum: Maintenance8.1 20.0Growth11.7 24.0Other petroleum total capital excluding major scheduled turnaround expenses19.8 44.0Petroleum business total capital excluding major scheduled turnaround expenses194.7 200.0Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership): Maintenance9.5 7.0Growth7.5 3.0Nitrogen fertilizer business total capital excluding major scheduled turnaround expenses17.0 10.0Corporate7.0 10.0Total capital spending excluding major scheduled turnaround expenses$218.7 $220.0The petroleum business' and the nitrogen fertilizer business' estimated capital expenditures are subject to change due to unanticipated increases in thecost, scope and completion time for capital projects. For example, they may experience increases in labor or equipment costs necessary to comply withgovernment regulations or to complete projects that sustain or improve the profitability of the refineries or nitrogen fertilizer plant. Capital spending for theNitrogen Fertilizer Partnership's nitrogen fertilizer business and the Refining Partnership's petroleum business is determined by each partnership's respectiveboard of directors of its general partner.In October 2014, the board of directors of the general partner of the Refining Partnership approved the construction of a hydrogen plant at theCoffeyville refinery. The hydrogen plant will increase the overall plant liquid volume recovery and provide additional hydrogen that is needed forenvironmental compliance. The estimated cost of this project, excluding capitalized interest, is approximately $122.5 million with an anticipated completiondate in the second quarter of 2016. As of88Table of ContentsDecember 31, 2015, the Refining Partnership had incurred costs of approximately $77.7 million, excluding capitalized interest, for the hydrogen plant.During 2015, the Refining Partnership constructed two crude oil storage tanks in Cushing, Oklahoma, which provide the petroleum business with anadditional 0.5 million barrels of crude storage capacity. The tanks became operational in October 2015. As of December 31, 2015, the Refining Partnershiphad incurred costs of approximately $9.8 million, excluding capitalized interest, for the crude oil storage tanks. The total cost of this project, excludingcapitalized interest, is expected to be approximately $11.0 million to $12.0 million.Cash FlowsThe following table sets forth our consolidated cash flows for the periods indicated below: Year Ended December 31, 2015 2014 2013 (in millions)Net cash provided by (used in): Operating activities$536.8 $640.3 $440.1Investing activities(150.6) (296.6) (250.3)Financing activities(374.8) (432.1) (243.7)Net increase (decrease) in cash and cash equivalents$11.4 $(88.4) $(53.9)Cash Flows Provided by Operating ActivitiesFor purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capitalis defined as all other current assets and liabilities except trade working capital.Net cash flows provided by operating activities for the year ended December 31, 2015 were $536.8 million. The positive cash flow from operatingactivities generated over this period was primarily driven by $297.8 million of net income before noncontrolling interest and favorable impacts to tradeworking capital and other working capital. Trade working capital for the year ended December 31, 2015 resulted in a net cash inflow of $66.4 million, whichwas attributable to decreases in accounts receivable ($41.0 million) and inventory ($39.7 million), partially offset by a decrease in accounts payable ($14.3million). Each of the cash flow impacts in trade working capital were largely attributable to the crude oil pricing environment and significant decreases insales prices for gasoline and distillates at the petroleum business in 2015 as compared to 2014. Other working capital activities resulted in net cash inflow of$14.8 million, which was primarily related to decreases in prepaid expenses and other current assets ($40.4 million) and due from parent ($32.8 million),partially offset by decreases in other current liabilities ($52.1 million) and deferred revenue ($10.5 million). The decrease in prepaid expenses and othercurrent assets was primarily due to the sale of trading securities, the timing of payments associated with the petroleum business' crude oil intermediationagreement and a reduction in prepaid insurance. The decrease in due from parent was the result of the timing and application of overpayments to AEPC underthe Tax Allocation Agreement. The decrease in other current liabilities was primarily attributable to a decrease in the biofuel blending obligation at thepetroleum business as a result of increased RINs purchases during the year ended December 31, 2015 to fulfill the petroleum business' requirements under theRFS. The decrease in deferred revenue was primarily attributable to lower market demand for prepaid contracts at the nitrogen fertilizer business for the yearended December 31, 2015 compared to the year ended December 31, 2014.Net cash flows provided by operating activities for the year ended December 31, 2014 were $640.3 million. The positive cash flow from operatingactivities generated over this period was primarily driven by $309.4 million of net income before noncontrolling interest and favorable impacts to tradeworking capital of $211.2 million, partially offset by an unfavorable impact to other working capital of $6.3 million. Trade working capital for the yearended December 31, 2014 resulted in a net cash inflow of $211.2 million, which was attributable to decreases in inventory ($197.3 million) and accountsreceivable ($105.7 million), partially offset by a decrease in accounts payable ($91.8 million). Each of the cash flow impacts in trade working capital werelargely attributable to the crude oil pricing environment and significant reduction in pricing during the fourth quarter of 2014. The favorable trade workingcapital impacts for inventory and accounts receivable resulted from higher product prices and crude oil prices at the end of 2013 as compared to the end of2014. These favorable trade working capital impacts were partially offset by the decrease in accounts payable at the petroleum business as a result ofpayables related to crude purchases based on higher crude oil prices at the end of 2013 as compared to the end of 2014, as well as payments for a judgment inan on-going litigation matter during 2014. Other working capital activities resulted in net cash outflow of $6.389Table of Contentsmillion, which was primarily related to an increase in the due (to) from parent ($44.6 million), partially offset by an increase in other current liabilities ($15.0million), an increase in deferred revenue ($12.9 million) and a decrease in prepaid expenses and other current assets ($10.7 million). The increase in due to(from) parent was the result of overpayments to AEPC under the Tax Allocation Agreement. The increase in other current liabilities was primarily attributableto an increase in accruals related to the biofuel blending obligation as a result of higher RINs prices as of December 31, 2014 as compared to the prior year.The increase in deferred revenue was primarily attributable to higher market demand for prepaid contracts at the nitrogen fertilizer business for the year endedDecember 31, 2014 compared to the prior period. The decrease in prepaid expenses and other current assets was primarily due to a reduction in prepaidinsurance and the timing of payments related to certain other prepaid items.Net cash flows provided by operating activities for the year ended December 31, 2013 were $440.1 million. The positive cash flow from operatingactivities generated over this period was primarily driven by $522.0 million of net income before noncontrolling interest, partially offset by unfavorableimpacts to trade working capital $67.4 million and other working capital $53.2 million. Trade working capital for the year ended December 31, 2013 resultedin a net cash outflow of $67.4 million, which was primarily attributable to an increase in accounts receivable ($30.2 million) and a decrease in accountspayable of ($38.7 million). The increase in accounts receivable primarily resulted from increased sales volumes at the petroleum business as compared to theend of 2012 due to the turnaround at the Wynnewood refinery completed in the fourth quarter of 2012. The decrease in accounts payable was largely theresult of a decrease in amounts payable related to the turnaround completed at the Wynnewood refinery in the fourth quarter of 2012, partially offset byincreased payables for leased crude purchases due to increased crude gathering capacity and timing of payments. Other working capital activities resulted innet cash outflow of $53.2 million, which was primarily related to an increase in prepaid expenses and other current assets ($28.7 million) and a decrease inother current liabilities ($26.7 million), partially offset by an increase in due (to) from parent ($9.1 million). The increase in prepaid expenses and othercurrent assets was primarily due to timing of settlements associated with the petroleum business' crude oil intermediation agreement. The decrease in othercurrent liabilities was primarily attributable to a decrease in liabilities related to share-based compensation, property taxes and interest on borrowings ascompared to the prior year-end.Cash Flows Used In Investing ActivitiesNet cash used in investing activities for the year ended December 31, 2015 was $150.6 million compared to $296.6 million for the year endedDecember 31, 2014. The decrease of $146.0 million was the result of decreased purchases of available-for-sale securities ($78.3 million) and proceedsreceived from the sale of available-for-sale securities ($68.0 million) for the year ended December 31, 2015. Capital spending remained relatively consistentfor the year ended December 31, 2015 compared to the year ended December 31, 2014.Net cash used in investing activities for the year ended December 31, 2014 was $296.6 million compared to $250.3 million for the year endedDecember 31, 2013. The increase in cash used in investing activities was primarily the result of purchases of held available-for-sale securities during the yearended December 31, 2014, partially offset by a $38.1 million decrease in capital spending. The decrease in capital spending was primarily the result ofdecreases in nitrogen fertilizer capital expenditures of approximately $22.7 million following the completion of the UAN expansion project in February2013.Cash Flows Used In Financing ActivitiesNet cash used in financing activities for the year ended December 31, 2015 was approximately $374.8 million. The net cash used in financing activitiesfor the year ended December 31, 2015 was primarily attributable to dividend payments to common stockholders of $173.7 million and distributions to theRefining Partnership and Nitrogen Fertilizer Partnership common unitholders of $199.7 million.Net cash used in financing activities for the year ended December 31, 2014 was approximately $432.1 million. The net cash used in financing activitiesfor the year ended December 31, 2014 was primarily attributable to dividend payments to common stockholders of $434.2 million, distributions to theRefining Partnership and Nitrogen Fertilizer Partnership common unitholders of $184.9 million, partially offset by proceeds of $188.3 million from theRefining Partnership's Second Underwritten Offering.Net cash used in financing activities for the year ended December 31, 2013 was approximately $243.7 million. The net cash used in financing activitiesfor the year ended December 31, 2013 was primarily attributable to dividend payments of $1,237.3 million, distributions to the Refining Partnership andNitrogen Fertilizer Partnership common unitholders of $164.2 million and payments to extinguish the Second Lien Notes of $243.4 million, largely offset byproceeds from CVR Refining's initial public offering of $655.7 million, proceeds from CVR Refining's Underwritten Offering of $393.6 million, proceeds90Table of Contentsfrom CVR Energy's sale of CVR Refining's units to AEPC of $61.5 million and proceeds from the Secondary Offering of CVR Partners' common units of$292.6 million.As of and for the year ended December 31, 2015, there were no borrowings or repayments under the Amended and Restated ABL credit facility or theNitrogen Fertilizer Partnership revolving credit facility.Capital and Commercial CommitmentsIn addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimumpayments as of December 31, 2015 relating to long-term debt outstanding, operating leases, capital lease obligations, unconditional purchase obligationsand other specified capital and commercial commitments for the five-year period following December 31, 2015 and thereafter. Payments Due by Period Total 2016 2017 2018 2019 2020 Thereafter (in millions)Contractual Obligations Long-term debt(1)$625.0 $125.0 $— $— $— $— $500.0Operating leases(2)23.5 8.0 5.5 3.9 2.1 1.5 2.5Capital lease obligations(3)48.5 1.6 1.9 2.1 2.3 2.6 38.0Unconditional purchase obligations(4)1,349.6 141.0 125.6 124.3 123.5 107.8 727.4Environmental liabilities(5)3.7 2.0 0.5 0.5 0.1 0.1 0.5Interest payments(6)270.1 38.7 37.1 36.9 36.7 36.4 84.3Total$2,320.4 $316.3 $170.6 $167.7 $164.7 $148.4 $1,352.7Other Commercial Commitments Standby letters of credit(7)$27.8 $— $— $— $— $— $—_______________________________________(1)Consists of the 2022 Notes and the Nitrogen Fertilizer Partnership's term loan facility outstanding as of December 31, 2015. The Nitrogen FertilizerPartnership's term loan facility matures in April 2016. Refer to Note 9 ("Long-Term Debt") to Part II, Item 8 of this Report for further discussion.(2)The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, underoperating leases for various periods.(3)The amount includes commitments under capital lease arrangements for two leases associated with pipelines and storage and terminal equipment atthe Wynnewood refinery.(4)The amount includes (a) commitments under several agreements for the petroleum operations related to pipeline usage, petroleum products storageand petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville, (c) a product supply agreement withLinde, (d) a pet coke supply agreement with HollyFrontier Corporation with a term ending in December 2016, (e) commitments related to ourbiofuels blending obligation and (f) approximately $781.5 million payable ratably over fifteen years pursuant to petroleum transportation serviceagreements between CRRM and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together,"TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of December 31, 2015, whereapplicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing,Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. The petroleum business began receiving crude oil under theagreements in the first quarter of 2011.(5)Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardouswaste management units at our sites in Coffeyville and Phillipsburg, Kansas and Wynnewood, Oklahoma. We also are required to make paymentswith respect to other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See"Business — Environmental Matters."91Table of Contents(6)Interest payments are based on stated interest rates for our long-term debt outstanding and interest payments for the capital lease obligations as ofDecember 31, 2015.(7)Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.2 million of letters of credit issued in connectionwith environmental liabilities, $26.7 million in letters of credit to secure transportation services for crude oil and a $0.9 million letter of credit issuedto guarantee a portion of our insurance policy.The Refining Partnership's and the Nitrogen Fertilizer Partnership's ability to make payments on and to refinance their indebtedness, to fund budgetedcapital expenditures and to satisfy their other capital and commercial commitments will depend on their respective independent abilities to generate cashflow in the future. Their ability to refinance their respective indebtedness is also subject to the availability of the credit markets, which in recent periods havebeen extremely volatile. This, to a certain extent, is subject to refining spreads (for the Refining Partnership), fertilizer margins (for the Nitrogen FertilizerPartnership) and general economic, financial, competitive, legislative, regulatory and other factors they are unable to control. Our businesses may notgenerate sufficient cash flow from operations, and future borrowings may not be available to the Nitrogen Fertilizer Partnership under its revolving creditfacility or any replacement credit facility or to the Refining Partnership under the Amended and Restated ABL Credit Facility (or other credit facilities ourbusinesses may enter into in the future) in an amount sufficient to enable them to pay indebtedness or to fund other liquidity needs. They may seek to sellassets to fund liquidity needs but may not be able to do so. They may also need to refinance all or a portion of their indebtedness on or before maturity, andmay not be able to refinance such indebtedness on commercially reasonable terms or at all.Off-Balance Sheet ArrangementsWe do not have any "off-balance sheet arrangements" as such term is defined within the rules and regulations of the SEC.Recent Accounting PronouncementsRefer to Part II, Item 8, Note 2 ("Summary of Significant Accounting Policies"), of this Report for a discussion of recent accounting pronouncementsapplicable to us.Critical Accounting PoliciesWe prepare our consolidated 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 andsubsequent events. Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Report. Ourcritical accounting policies, which are described below, could materially affect the amounts recorded in our consolidated financial statements.GoodwillTo comply with Accounting Standards Codification ("ASC") Topic 350, Intangibles — Goodwill and Other ("ASC 350"), we perform a test for goodwillimpairment annually, or more frequently in the event we determine that a triggering event has occurred. Our annual testing is performed as of November 1each year. In accordance with ASC 350, we identified our reporting units based upon our two key operating segments. These reporting units are ourpetroleum and nitrogen fertilizer segments. For 2015, 2014 and 2013, the nitrogen fertilizer segment was the only reporting unit that had goodwill.In accordance with ASC 350, the nitrogen fertilizer segment may elect to perform a qualitative assessment to determine whether the two-step quantitativeimpairment test is required. If the nitrogen fertilizer segment elects to perform a qualitative assessment, the two-step impairment test is required only if thenitrogen fertilizer segment concludes that it is more likely than not that the reporting unit's fair value is less than its carrying amount. For the years endedDecember 31, 2015 and 2014, the nitrogen fertilizer segment elected to perform a qualitative assessment.The nitrogen fertilizer segment began the qualitative assessment by analyzing the key drivers and other external factors that impact the business in orderto determine if any significant events, transactions or other factors had occurred or are expected to occur that would impair earnings or competitiveness,thereby impairing the fair value of the nitrogen fertilizer segment. After assessing the totality of events and circumstances, it was determined that it was notmore likely than not that the fair value of the nitrogen fertilizer segment was less than the carrying value, and so it was not necessary to perform the two-stepvaluation. The key drivers that were considered in the evaluation of the nitrogen fertilizer segment's fair value included:92Table of Contents•general economic conditions;•fertilizer pricing;•input costs;•liquidity and capital resources; and•customer outlook.Long-Lived AssetsWe calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. Whenassets are placed in service, we make estimates of what we believe are their reasonable useful lives. We account for impairment of long-lived assets inaccordance 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 changesin circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by acomparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amountof an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of theassets 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 chargeswere recognized for any of the periods presented.Derivative Instruments and Fair Value of Financial InstrumentsThe petroleum business uses futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices and finishedgoods product prices to provide economic hedges of inventory positions. Although management considers these derivatives economic hedges, thesederivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging ("ASC 815"), andaccordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as acomponent of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices andassumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. The petroleum businessrecorded net gains (losses) from derivative instruments of $(28.6) million, $185.6 million and $57.1 million for the years ended December 31, 2015, 2014 and2013, respectively.The nitrogen fertilizer business uses forward swap contracts primarily to reduce the exposure to changes in interest rates on its debt and to provide a cashflow hedge. These derivative instruments have been designated as hedges for accounting purposes. Accordingly, these instruments are recorded at fair valuein the Consolidated Balance Sheets, at each reporting period end. The actual measurement of the cash flow hedge ineffectiveness is recognized in earnings, ifapplicable. The effective portion of the gain or loss on the swaps is reported in AOCI, in accordance with ASC 815.Other financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximatesfair value, as a result of the short-term nature of the instruments.Share-Based CompensationWe account for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation ("ASC 718"). ASC 718 requiresthat compensation costs relating to share-based payment transactions be recognized in a company's financial statements. ASC 718 applies to transactions inwhich an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based onthe fair value of those equity instruments. Total share-based compensation expense for the years ended December 31, 2015, 2014 and 2013 was $12.8million, $12.3 million and $18.4 million, respectively.Income TaxesWe provide for income taxes in accordance with ASC Topic 740, Income Taxes, accounting for uncertainty in income taxes. We record deferred tax assetsand liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. Weroutinely assess the realizability of our deferred tax assets and if93Table of Contentswe conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset would be reduced by avaluation allowance. We consider future taxable income in making such assessments which requires numerous judgments and assumptions. We recordcontingent income tax liabilities, interest and penalties, based on our estimate as to whether, and the extent to which, additional taxes may be due.Item 7A. Quantitative and Qualitative Disclosures About Market RiskThe risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates.None of our market risk sensitive instruments are held for trading.Commodity Price RiskThe petroleum business, as a manufacturer of refined petroleum products, and the nitrogen fertilizer business, as a manufacturer of nitrogen fertilizerproducts, all of which are commodities, have 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 physicalcommodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.The petroleum business uses a crude oil purchasing intermediary, Vitol, to purchase the majority of its non-gathered crude oil inventory for the refineries,which allows it to take title to and price its crude oil at locations in close proximity to the refineries, as opposed to the crude oil origination point, reducingits risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to thetime elapsed between raw material acquisition and the sale of finished goods. In addition, the petroleum business seeks to reduce the variability ofcommodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in the annual operatingplan. Accordingly, the petroleum business uses commodity derivative contracts to economically hedge future cash flows (i.e., gross margin or crack spreads)and product inventories. With regard to its hedging activities, the petroleum business may enter into, or have entered into, derivative instruments which serveto:•lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreadsthat generate positive cash flows;•hedge the value of inventories in excess of minimum required inventories; and•manage existing derivative positions related to a change in anticipated operations and market conditions.Further, the petroleum business intends to engage only in risk mitigating activities directly related to its businesses. The nitrogen fertilizer business has nothistorically hedged for commodity prices.Basis Risk. The effectiveness of our derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and thecash 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 existdue to several factors including time or location differences between the derivative instrument and the underlying physical commodity. Our selection of theappropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure.Examples of our basis risk exposure are as follows:•Time Basis — In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlyingcommodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity willprice ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will beweighted differently than the swap price as the result of timing.•Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related moreto New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area.94Table of ContentsPrice and Basis Risk Management Activities.In the event inventories exceed the petroleum business' target base level of inventories, it may enter into commodity derivative contracts to manage priceexposure to inventory positions that are in excess of its base level. Excess inventories are typically the result of plant operations, such as a turnaround orother 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 forNYMEX crack spreads, the petroleum business may enter into basis swap positions to lock the price difference. If the difference between the price of productson the NYMEX and Group 3 (or some other price benchmark as specified in the swap) is different than the value contracted in the swap, then it will receivefrom or owe to the counterparty the difference on each unit of product contracted in the swap, thereby completing the locking of its margin. An example ofthe petroleum business' use of a basis swap is in the winter heating oil season. The risk associated with not hedging the basis when using NYMEX forwardcontracts 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 wewould be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on theGroup 3 pricing.From time to time, the petroleum business also holds various NYMEX positions through a third-party clearing house. At December 31, 2015, theRefining Partnership had no open commodity positions. At December 31, 2015, the Refining Partnership's account balance maintained at the third-partyclearing house totaled approximately $7.5 million, which is reflected on the Consolidated Balance Sheets in cash and cash equivalents. NYMEX transactionsconducted for the year ended December 31, 2015 resulted in gain (loss) on derivatives, net of approximately $3.2 million.The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, the RefiningPartnership may enter into price and basis swaps in order to fix the price on a portion of its commodity purchases and product sales. The physical volumes arenot exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheetswith changes in fair value currently recognized in the Consolidated Statements of Operations. At December 31, 2015, the Refining Partnership had opencommodity hedging instruments consisting of 2.5 million barrels of crack spreads primarily to fix the margin on a portion of its future distillate production. Achange 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 commodity hedginginstruments of $2.5 million. Additionally, at December 31, 2015, the Refining Partnership had open commodity hedging instruments consisting of 1.4million barrels to fix the price on a portion of its future crude oil purchases and the basis on a portion of its future product sales. A change of $1.00 per barrelin the fair value of the benchmark crude or product basis would result in an increase or decrease in the related fair value of the commodity hedginginstruments of $1.4 million. The fair value of the outstanding contracts at December 31, 2015 was a net unrealized gain of $44.6 million, comprised of short-term unrealized gains and losses.Interest Rate RiskAs of December 31, 2015 and prior to the expiration of the interest rate swaps on February 12, 2016, the Nitrogen Fertilizer Partnership had exposure tointerest rate risk on 50% of its $125.0 million floating rate term debt. A 1.0% increase over the Eurodollar floor spread of 3.5%, as specified in the creditagreement, would increase interest cost to the Nitrogen Fertilizer Partnership by approximately $625,000 on an annualized basis, thus decreasing net incomeby the same amount.Subsequent to the expiration of the interest rate swaps on February 12, 2016, the Nitrogen Fertilizer Partnership has exposure to interest rate risk on100% of its $125.0 million floating rate debt. A 1.0% increase over the Eurodollar floor spread of 3.5%, as specified in the credit agreement, would increaseinterest cost to the Nitrogen Fertilizer Partnership by approximately $1,250,000 on an annualized basis, thus decreasing net income by the same amount.The credit facility expires on April 13, 2016. The Nitrogen Fertilizer Partnership is considering capital structure and refinancing options associated withthe credit facility maturity. The credit facility is discussed in Note 9 ("Long-Term Debt") and the interest rate swap agreements are discussed in Note 15("Derivative Financial Instruments") to Part II, Item 8 of this Report.95Table of ContentsForeign Currency ExchangeGiven that ours, the petroleum business' and the nitrogen fertilizer business' operations are based entirely in the United States, we are not significantlyexposed to foreign currency exchange rate risk. A portion of the petroleum business' Canadian crude oil purchases are conducted in Canadian dollars.Commitments for future periods under this agreement reflect the exchange rate between the Canadian Dollar and the U.S. Dollar as of the end of the reportingperiod. Based on the short period of time between the delivery and settlement of purchases of crude oil in Canadian dollars, the exposure to foreign currencyexchange rate risk and the resulting foreign currency gain (loss) is not material.96Table of ContentsItem 8. Financial Statements and Supplementary DataCVR Energy, Inc. and SubsidiariesINDEX TO CONSOLIDATED FINANCIAL STATEMENTSAudited Financial Statements:PageNumberReport of Independent Registered Public Accounting Firm — Consolidated Financial Statements98Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting99Consolidated Balance Sheets at December 31, 2015 and 2014100Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013101Consolidated Statements of Comprehensive Income for the years ended December 31, 2015, 2014 and 2013102Consolidated Statements of Changes in Equity for the years ended December 31, 2015, 2014 and 2013103Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013104Notes to Consolidated Financial Statements10597Table of ContentsReport of Independent Registered Public Accounting FirmThe Board of Directors and Stockholders of CVR Energy, Inc.We have audited the accompanying consolidated balance sheets of CVR Energy, Inc. (a Delaware corporation) and subsidiaries (the "Company") as ofDecember 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of thethree years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is toexpress an opinion on these 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 requirethat we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our auditsprovide 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 CVR Energy, Inc.and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2015 in conformity with accounting principles generally accepted in the United States of America.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internalcontrol over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control — Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 19, 2016 expressed an unqualified opinion./s/ GRANT THORNTON LLPHouston, TexasFebruary 19, 201698Table of ContentsReport of Independent Registered Public Accounting FirmThe Board of Directors and Stockholders of CVR Energy, Inc.We have audited the internal control over financial reporting of CVR Energy, Inc. (a Delaware corporation) and subsidiaries (the "Company") as ofDecember 31, 2015, based on criteria established in the 2013 Internal Control — Integrated Framework issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financialreporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report OnInternal Control Over Financial Reporting under Item 9A. Our responsibility is to express an opinion on the Company's internal control over financialreporting based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures aswe considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internalcontrol over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately andfairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the companyare being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financialstatements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluationof effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree ofcompliance with the policies or procedures may deteriorate.In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based oncriteria established in the 2013 Internal Control — Integrated Framework issued by COSO.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financialstatements of the Company as of and for the year ended December 31, 2015, and our report dated February 19, 2016 expressed an unqualified opinion onthose financial statements./s/ GRANT THORNTON LLPHouston, TexasFebruary 19, 201699Table of ContentsCVR Energy, Inc. and SubsidiariesCONSOLIDATED BALANCE SHEETS December 31, 2015 2014 (in millions, except share data)ASSETSCurrent assets: Cash and cash equivalents$765.1 $753.7Accounts receivable, net of allowance for doubtful accounts of $0.3 and $0.4, respectively95.8 136.7Inventories289.9 329.6Prepaid expenses and other current assets105.4 174.7Income tax receivable6.9 11.1Deferred income taxes— 6.3Due from parent11.6 44.5Total current assets1,274.7 1,456.6Property, plant, and equipment, net of accumulated depreciation1,967.1 1,916.0Intangible assets, net0.2 0.2Goodwill41.0 41.0Deferred financing costs, net6.2 8.4Other long-term assets16.6 40.3Total assets$3,305.8 $3,462.5LIABILITIES AND EQUITYCurrent liabilities: Note payable and capital lease obligations$1.6 $1.4Current portion of long-term debt125.0 —Accounts payable261.5 275.0Personnel accruals45.7 38.3Accrued taxes other than income taxes23.5 26.7Deferred revenue3.1 13.6Other current liabilities24.4 68.6Total current liabilities484.8 423.6Long-term liabilities: Long-term debt and capital lease obligations, net of current portion546.9 673.5Deferred income taxes639.7 638.3Other long-term liabilities33.9 51.8Total long-term liabilities1,220.5 1,363.6Commitments and contingencies Equity: CVR stockholders' equity: Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 shares issued0.9 0.9Additional paid-in-capital1,174.7 1,174.7Retained deficit(189.2) (184.9)Treasury stock, 98,610 shares at cost(2.3) (2.3)Accumulated other comprehensive loss, net of tax— (0.3)Total CVR stockholders' equity984.1 988.1Noncontrolling interest616.4 687.2Total equity1,600.5 1,675.3Total liabilities and equity$3,305.8 $3,462.5See accompanying notes to consolidated financial statements.100Table of ContentsCVR Energy, Inc. and SubsidiariesCONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 2015 2014 2013 (in millions, except per share data)Net sales$5,432.5 $9,109.5 $8,985.8Operating costs and expenses: Cost of product sold (exclusive of depreciation and amortization)4,190.4 8,066.0 7,563.2Direct operating expenses (exclusive of depreciation and amortization)584.7 515.1 455.8Flood insurance recovery(27.3) — —Selling, general and administrative expenses (exclusive of depreciation andamortization)99.0 109.7 113.5Depreciation and amortization164.1 154.4 142.8Total operating costs and expenses5,010.9 8,845.2 8,275.3Operating income421.6 264.3 710.5Other income (expense): Interest expense and other financing costs(48.4) (40.0) (50.5)Interest income1.0 0.9 1.2Gain (loss) on derivatives, net(28.6) 185.6 57.1Loss on extinguishment of debt— — (26.1)Other income (expense), net36.7 (3.7) 13.5Total other income (expense)(39.3) 142.8 (4.8)Income before income taxes382.3 407.1 705.7Income tax expense84.5 97.7 183.7Net income297.8 309.4 522.0Less: Net income attributable to noncontrolling interest128.2 135.5 151.3Net income attributable to CVR Energy stockholders$169.6 $173.9 $370.7 Basic earnings per share$1.95 $2.00 $4.27Diluted earnings per share$1.95 $2.00 $4.27Dividends declared per share$2.00 $5.00 $14.25 Weighted-average common shares outstanding: Basic86.8 86.8 86.8Diluted86.8 86.8 86.8See accompanying notes to consolidated financial statements.101Table of ContentsCVR Energy, Inc. and SubsidiariesCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year Ended December 31, 2015 2014 2013 (in millions)Net income$297.8 $309.4 $522.0Other comprehensive income (loss): Unrealized gain on available-for-sale securities, net of tax of $12.6, $0 and $2.4,respectively19.2 — 3.7Net gain reclassified into income on sale of available-for-sale-securities, net of tax of$(8.0), $0 and $(2.4), respectively (Note 14)(12.1) — (3.7)Net gain reclassified into income on reclassification of available-for-sale securities totrading securities, net of tax of $(4.6), $0, $0, respectively (Note 14)(7.1) — —Change in fair value of interest rate swaps, net of tax of $0, $0 and $0, respectively(0.1) (0.2) (0.2)Net loss reclassified into income on settlement of interest rate swaps, net of tax of $0.2,$0.2 and $0.3, respectively (Note 15)0.8 0.9 0.8Total other comprehensive income0.7 0.7 0.6Comprehensive income298.5 310.1 522.6Less: Comprehensive income attributable to noncontrolling interest128.6 135.9 151.5Comprehensive income attributable to CVR Energy stockholders$169.9 $174.2 $371.1See accompanying notes to consolidated financial statements.102Table of ContentsCVR Energy, Inc. and SubsidiariesCONSOLIDATED STATEMENTS OF CHANGES IN EQUITY Common Stockholders SharesIssued $0.01 ParValueCommonStock AdditionalPaid-InCapital RetainedEarnings(Deficit) TreasuryStock AccumulatedOtherComprehensiveIncome (Loss) Total CVRStockholders'Equity NoncontrollingInterest TotalEquity (in millions, except share data)Balance at December 31, 201286,929,660 $0.9 $582.3 $945.4 $(2.3) $(1.2) $1,525.1 $135.0 $1,660.1January issuance of CVRRefining's common units to thepublic, net of $148.0 tax impact— — 229.3 — — — 229.3 276.4 505.7May issuance of CVR Refining'scommon units to the public, netof $96.0 tax impact— — 148.9 — — — 148.9 148.7 297.6Sale of CVR Refining's commonunits to affiliate, net of $15.2tax impact— — 23.6 — — — 23.6 22.7 46.3Secondary offering of CVRPartners' common units topublic, net of $88.5 tax impact— — 129.7 — — 0.2 129.9 74.1 204.0Dividends paid to CVR Energystockholders— — — (1,237.3) — — (1,237.3) — (1,237.3)Distributions from CVR Partners topublic unitholders— — — — — — — (50.0) (50.0)Distributions from CVR Refiningto public unitholders— — — — — — — (114.2) (114.2)Share-based compensation— — 1.0 (2.6) — — (1.6) 2.8 1.2Excess tax deficiency from share-based compensation— — (0.1) — — — (0.1) — (0.1)Redemption of common units— — (0.3) — — — (0.3) (0.2) (0.5)Net income— — — 370.7 — — 370.7 151.3 522.0Other comprehensive income, netof tax— — — — — 0.4 0.4 0.2 0.6Balance at December 31, 201386,929,660 $0.9 $1,114.4 $76.2 $(2.3) $(0.6) $1,188.6 $646.8 $1,835.4June issuance of CVR Refining'scommon units to the public, net of$39.4 tax impact— — 60.3 — — — 60.3 88.6 148.9Dividends paid to CVR Energystockholders— — — (434.2) — — (434.2) — (434.2)Distributions from CVR Partners topublic unitholders— — — — — — — (48.2) (48.2)Distributions from CVR Refiningto public unitholders— — — — — — — (136.7) (136.7)Share-based compensation— — 0.1 (0.8) — — (0.7) 0.8 0.1Excess tax deficiency from share-based compensation— — (0.1) — — — (0.1) — (0.1)Net income— — — 173.9 — — 173.9 135.5 309.4Other comprehensive income, netof tax— — — — — 0.3 0.3 0.4 0.7Balance at December 31, 201486,929,660 $0.9 $1,174.7 $(184.9) $(2.3) $(0.3) $988.1 $687.2 $1,675.3Dividends paid to CVR Energystockholders— — — (173.7) — — (173.7) — (173.7)Distributions from CVR Partners topublic unitholders— — — — — — — (42.8) (42.8)Distributions from CVR Refiningto public unitholders— — — — — — — (156.9) (156.9)Share-based compensation— — 0.1 (0.2) — — (0.1) 0.3 0.2Excess tax deficiency from share-based compensation— — (0.1) — — — (0.1) — (0.1)Net income— — — 169.6 — — 169.6 128.2 297.8Other comprehensive income, netof tax— — — — — 0.3 0.3 0.4 0.7Balance at December 31, 201586,929,660 $0.9 $1,174.7 $(189.2) $(2.3) $— $984.1 $616.4 $1,600.5See accompanying notes to consolidated financial statements.103Table of ContentsCVR Energy, Inc. and SubsidiariesCONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 2015 2014 2013 (in millions)Cash flows from operating activities: Net income$297.8 $309.4 $522.0Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization164.1 154.4 142.8Allowance for doubtful accounts(0.1) (0.5) (1.1)Amortization of deferred financing costs2.8 2.8 2.9Deferred income taxes(10.4) 19.2 (93.3)Excess income tax deficiency of share-based compensation0.1 0.1 0.1Loss on disposition of assets1.8 0.4 0.1Loss on extinguishment of debt— — 26.1Share-based compensation12.8 12.3 18.4Gain on sale of available-for-sale securities(20.1) — (6.1)(Gain) loss on derivatives, net28.6 (185.6) (57.1)Current period settlements on derivative contracts(26.0) 122.2 6.4Changes in assets and liabilities: Accounts receivable41.0 105.7 (30.2)Inventories39.7 197.3 1.5Prepaid expenses and other current assets40.4 10.7 (28.7)Due to (from) parent32.8 (44.6) 9.1Other long-term assets3.8 (0.8) (0.5)Accounts payable(14.3) (91.8) (38.7)Accrued income taxes4.2 (0.3) (6.6)Deferred revenue(10.5) 12.9 (0.3)Other current liabilities(52.1) 15.0 (26.7)Other long-term liabilities0.4 1.5 —Net cash provided by operating activities536.8 640.3 440.1Cash flows from investing activities: Capital expenditures(218.7) (218.4) (256.5)Proceeds from sale of assets0.1 0.1 0.1Purchase of available-for-sale securities— (78.3) (18.6)Proceeds from sale of available-for-sale securities68.0 — 24.7Net cash used in investing activities(150.6) (296.6) (250.3)Cash flows from financing activities: Principal payments on senior secured notes— — (243.4)Payment of capital lease obligations(1.3) (1.2) (1.2)Payment of deferred financing costs— — (0.4)Proceeds from CVR Refining's initial public offering, net of offering costs— — 655.7Proceeds from CVR Refining's May 2013 offering, net of offering costs— — 393.6Proceeds from the sale of CVR Refining's common units to affiliate— — 61.5Proceeds from CVR Refining's June 2014 offering, net of offering costs— 188.3 —Proceeds from CVR Partners' secondary offering, net of offering costs— — 292.6Dividends to CVR Energy's stockholders(173.7) (434.2) (1,237.3)Distributions to CVR Refining's noncontrolling interest holders(156.9) (136.7) (114.2)Distributions to CVR Partners' noncontrolling interest holders(42.8) (48.2) (50.0)Excess income tax deficiency of share-based compensation(0.1) (0.1) (0.1)Redemption of common units— — (0.5)Net cash used in financing activities(374.8) (432.1) (243.7)Net increase (decrease) in cash and cash equivalents11.4 (88.4) (53.9)Cash and cash equivalents, beginning of period753.7 842.1 896.0Cash and cash equivalents, end of period$765.1 $753.7 $842.1Supplemental disclosures: Cash paid for income taxes, net of refunds (received)$57.9 $123.5 $274.5Cash paid for interest net of capitalized interest of $3.7, $9.4 and $3.6 for the years endedDecember 31, 2015, 2014 and 2013, respectively$45.4 $37.2 $54.9Non-cash investing and financing activities: Construction in progress additions included in accounts payable$22.3 $21.6 $32.8Change in accounts payable related to construction in progress additions$0.7 $(11.2) $(23.4)See accompanying notes to consolidated financial statements.104Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS(1) Organization and History of the CompanyOrganizationThe "Company," "CVR Energy," or "CVR" may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Anyreferences to the "Company" as of a date prior to October 16, 2007 (the date of the restructuring as further discussed in this Note) and subsequent to June 24,2005 are to Coffeyville Acquisition LLC ("CALLC") and its subsidiaries.CVR is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdingsin CVR Refining, LP ("CVR Refining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). TheRefining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces andmarkets nitrogen fertilizers in the form of UAN and ammonia. The Company's operations include two business segments: the petroleum segment and thenitrogen fertilizer segment.CALLC formed CVR Energy, Inc. as a wholly-owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering.The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in whichCVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split intotwo entities: CALLC and Coffeyville Acquisition II LLC.CVR's common stock is listed on the NYSE under the symbol "CVI." As of December 31, 2010, approximately 40% of its outstanding shares werebeneficially owned by GS Capital Partners V, L.P. and related entities ("GS" or "Goldman Sachs Funds") and Kelso Investment Associates VII, L.P. and relatedentities ("Kelso" or "Kelso Funds"). On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market itsremaining ownership interests in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered publicoffering, whereby Kelso sold into the public market its remaining ownership interest in CVR Energy.On December 15, 2011, CVR acquired all of the issued and outstanding shares of Gary-Williams Energy Corporation (subsequently converted to"WEC"). Assets acquired include a 70,000 bpcd rated capacity refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of company-ownedstorage tanks.On April 18, 2012, an affiliate of Icahn Enterprises L.P. ("IEP") entered into a Transaction Agreement (the "Transaction Agreement") with CVR, withrespect to its tender offer to purchase all of the issued and outstanding shares of CVR's common stock. On May 7, 2012, an affiliate of IEP announced that ithad acquired control of CVR pursuant to a tender offer for all of the Company's common stock (the "IEP Acquisition"). As of December 31, 2015, IEP and itsaffiliates owned approximately 82% of the Company's outstanding shares. Prior to the IEP Acquisition, the Company was owned 100% by the public.CVR Partners, LPIn conjunction with the consummation of CVR's initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizers, LLC("CRNF"), its nitrogen fertilizer business, to CVR Partners, which at the time was a newly created limited partnership, in exchange for a managing generalpartner interest ("managing GP interest"), a special general partner interest ("special GP interest," represented by special GP units) and a de minimis limitedpartner interest ("LP interest," represented by special LP units). CVR concurrently sold the managing GP interest, including the associated incentivedistribution rights ("IDRs"), to Coffeyville Acquisition III LLC ("CALLC III"), an entity owned by its then controlling stockholders and senior management.On April 13, 2011, the Nitrogen Fertilizer Partnership completed its initial public offering of 22,080,000 common units (the "Nitrogen FertilizerPartnership IPO") priced at $16.00 per unit. The common units, which are listed on the NYSE, began trading on April 8, 2011 under the symbol "UAN." Inconnection with the Nitrogen Fertilizer Partnership IPO, the IDRs were purchased by the Nitrogen Fertilizer Partnership and subsequently extinguished. Inaddition, the noncontrolling interest representing the managing GP interest was purchased by Coffeyville Resources, LLC ("CRLLC"), a subsidiary of CVR,for a nominal amount. The consideration for the IDRs was paid to the owners of CALLC III, which included the Goldman Sachs105Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Funds, the Kelso Funds and members of CVR's senior management. In connection with the Nitrogen Fertilizer Partnership IPO and through May 27, 2013, theCompany recorded a noncontrolling interest for the common units sold into the public market which represented approximately a 30% interest in theNitrogen Fertilizer Partnership.In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership's limited partner interests were converted into commonunits, the Nitrogen Fertilizer Partnership's special general partner interests were converted into common units, and the Nitrogen Fertilizer Partnership's specialgeneral partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, as discussed above, the managing generalpartner sold its IDRs to the Nitrogen Fertilizer Partnership. These interests were extinguished, and CALLC III sold the managing general partner to CRLLCfor a nominal amount. As a result of the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership has two types of partnership interestsoutstanding:•common units representing limited partner interests; and•a general partner interest, which is not entitled to any distributions, and which is held by the Nitrogen Fertilizer Partnership's general partner.On May 28, 2013, CRLLC completed a registered public offering (the "Secondary Offering") whereby it sold 12,000,000 Nitrogen Fertilizer Partnershipcommon units to the public at a price of $25.15 per unit. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6 million, afterdeducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceedsfrom the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5million in offering costs during the year ended December 31, 2013.Immediately subsequent to the closing of the Secondary Offering and as of December 31, 2015, public security holders held approximately 47% of thetotal Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of the total Nitrogen Fertilizer Partnership common units. Inaddition, CRLLC owns 100% of the Nitrogen Fertilizer Partnership's general partner, CVR GP, LLC, which only holds a non-economic general partnerinterest. The noncontrolling interest reflected on the Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, theNitrogen Fertilizer Partnership. Immediately subsequent to the completion of the pending mergers, which are discussed in the "CVR Partners, LP - PendingMergers" section below, it is estimated that CRLLC will hold approximately 34% of the Nitrogen Fertilizer Partnership's common units and 100% of theNitrogen Fertilizer Partnership's general partner interest.The Nitrogen Fertilizer Partnership has adopted a policy pursuant to which the Nitrogen Fertilizer Partnership will distribute all of the available cash itgenerates each quarter. The available cash for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership's general partnerfollowing the end of such quarter. The partnership agreement does not require that the Nitrogen Fertilizer Partnership make cash distributions on a quarterlybasis or at all, and the board of directors of the general partner of the Nitrogen Fertilizer Partnership can change the Nitrogen Fertilizer Partnership'sdistribution policy at any time.The Nitrogen Fertilizer Partnership is operated by CVR's senior management (together with other officers of the general partner) pursuant to a servicesagreement among CVR, the general partner and the Nitrogen Fertilizer Partnership. The Nitrogen Fertilizer Partnership's general partner, CVR GP, LLC,manages the operations and activities of the Nitrogen Fertilizer Partnership, subject to the terms and conditions specified in the partnership agreement. Theoperations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in itsindividual capacity are made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The generalpartner is not elected by the common unitholders and is not subject to re-election on a regular basis. The officers of the general partner manage the day-to-dayaffairs of the business of the Nitrogen Fertilizer Partnership. CVR, the Nitrogen Fertilizer Partnership, their respective subsidiaries and the general partner areparties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with theNitrogen Fertilizer Partnership IPO.106Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)CVR Partners, LP - Pending MergersOn August 9, 2015, CVR Partners, including its two newly-created direct wholly-owned subsidiaries Lux Merger Sub 1 LLC ("Merger Sub 1") and LuxMerger Sub 2 LLC ("Merger Sub 2"), entered into an Agreement and Plan of Merger (the "Merger Agreement") with Rentech Nitrogen Partners, L.P., apublicly traded partnership whose common units are listed on the New York Stock Exchange under the ticker symbol "RNF" ("Rentech Nitrogen"), andRentech Nitrogen GP, LLC ("Rentech Nitrogen GP"), pursuant to which CVR Partners will acquire Rentech Nitrogen and Rentech Nitrogen GP. The MergerAgreement provides that, upon the terms and subject to the conditions set forth therein, Merger Sub 1 will be merged with and into Rentech Nitrogen GP,with Rentech Nitrogen GP continuing as the surviving entity and a wholly-owned subsidiary of CVR Partners, and Merger Sub 2 will be merged with andinto Rentech Nitrogen, with Rentech Nitrogen continuing as the surviving entity and a wholly-owned subsidiary of CVR Partners (together, the "mergers"). Under the terms of the Merger Agreement, holders of common units representing limited partner interests in Rentech Nitrogen ("Rentech Nitrogencommon units") eligible to receive consideration will receive 1.04 common units (the "unit consideration") representing limited partner interests in CVRPartners ("CVR Partners common units") and $2.57 in cash, without interest, (the "cash consideration" and together with the unit consideration, the "mergerconsideration") for each Rentech Nitrogen common unit. Phantom units granted and outstanding under Rentech Nitrogen's equity plans and held by anemployee who will continue in the employment of a CVR Partners-affiliated entity upon closing of the mergers will be canceled and replaced with newincentive awards of substantially equivalent value and on similar terms. Each phantom unit granted and outstanding and held by (i) an employee who willnot continue in employment of a CVR Partners-affiliated entity, or (ii) a director of Rentech Nitrogen GP will, upon closing of the mergers, vest in full and beentitled to receive the merger consideration. The unit consideration is fixed, and the number of units included in the merger consideration will not beadjusted to reflect changes in the price of Rentech Nitrogen common units or CVR Partners common units. CVR Partners is expected to issue approximately40.7 million CVR Partners common units to former Rentech Nitrogen common unitholders pursuant to the mergers. Rentech Nitrogen owns and operates two fertilizer facilities. The facility located in East Dubuque, Illinois produces primarily ammonia and UAN usingnatural gas as the facility's primary feedstock. The facility located in Pasadena, Texas (the "Pasadena facility") produces ammonium sulfate, ammoniumthiosulfate and sulfuric acid, using ammonia and sulfur as the facility's primary feedstocks. Rentech Nitrogen is required to sell or spin off its Pasadenafacility as a condition to closing of the mergers (unless waived), and Rentech Nitrogen common unitholders may receive additional consideration for thePasadena facility in the event such a sale or spin-off is consummated. The completion of the mergers is subject to satisfaction or waiver of closing conditions, including (i) the adoption of the Merger Agreement by holdersof a majority of the outstanding Rentech Nitrogen common units, (ii) the effectiveness of a registration statement on Form S-4, (iii) the approval for listing ofthe CVR Partners common units issuable as part of the merger consideration on the New York Stock Exchange, (iv) the sale or spin-off by Rentech Nitrogenof Rentech Nitrogen's Pasadena facility on terms specified in the Merger Agreement, (v) the absence of certain events of default under the indenturegoverning Rentech Nitrogen's 6.5% Second Lien Senior Secured Notes due 2021 and (vi) other customary conditions. On February 15, 2016, the MergerAgreement was adopted by holders of a majority of the outstanding Rentech Nitrogen common units. On January 14, 2016, CVR Partners registrationstatement on Form S-4 with the Securities and Exchange Commission ("SEC") to register the CVR Partners common units issuable as part of the mergerconsideration was declared effective. The Merger Agreement includes customary restrictions on the conduct of the Nitrogen Fertilizer Partnership's business prior to the completion of themergers, generally requiring the Nitrogen Fertilizer Partnership to conduct its business in the ordinary course and subjecting the Nitrogen FertilizerPartnership to a variety of specified limitations. In accordance with the terms of the Merger Agreement, beginning with the distribution for the third quarter of2015 and until the closing of the mergers, the Nitrogen Fertilizer Partnership may not make or declare distributions in excess of available cash for distributionin respect of any quarter. The Merger Agreement contains certain termination rights for both CVR Partners and Rentech Nitrogen and further provides that upon termination of theMerger Agreement, under certain circumstances, either party may be required to make an expense reimbursement payment of $10.0 million, and RentechNitrogen may be required to pay CVR Partners a termination fee equal to $31.2 million. 107Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Simultaneously with the execution of the Merger Agreement, CVR Partners entered into a commitment letter (the "commitment letter") with CRLLC,pursuant to which CRLLC has committed to, on the terms and subject to the conditions set forth in the commitment letter, make available to CVR Partnersterm loan financing of up to $150.0 million, which amounts would be available solely to fund the repayment of all of the loans outstanding under RentechNitrogen's existing $50.0 million credit facility with General Electric Capital Corporation, the cash consideration payable by the Nitrogen FertilizerPartnership upon closing of the mergers and expenses associated with the mergers. The term loan facility will bear interest at a rate of three-month LIBORplus 3.0% per annum. Calculation of interest shall be on the basis of the actual number of days elapsed over a 360-day year. Such term loan, if drawn, wouldhave a one-year term.See Note 13 ("Commitments and Contingencies") for discussion of litigation related to the pending mergers.CVR Refining, LPIn contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC ("CVR Refining Holdings"), which inturn formed CVR Refining GP, LLC. CVR Refining Holdings and CVR Refining GP, LLC formed the Refining Partnership, which issued them a 100%limited partnership interest and a non-economic general partner interest, respectively. CVR Refining Holdings formed CVR Refining, LLC ("Refining LLC")and CRLLC contributed its petroleum and logistics subsidiaries, as well as its equity interests in Coffeyville Finance Inc. ("Coffeyville Finance"), toRefining LLC in October 2012. CVR Refining Holdings contributed Refining LLC to the Refining Partnership on December 31, 2012.On January 23, 2013, the Refining Partnership completed the initial public offering of its common units representing limited partner interests (the"Refining Partnership IPO"). The Refining Partnership sold 24,000,000 common units to the public at a price of $25.00 per unit, resulting in gross proceeds of$600.0 million, before giving effect to underwriting discounts and other offering expenses. Of the common units issued, 4,000,000 units were purchased byan affiliate of IEP. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00per unit in connection with the underwriters' exercise of their option to purchase additional common units, resulting in gross proceeds of $90.0 million,before giving effect to underwriting discounts and other offering costs. The common units, which are listed on the NYSE, began trading on January 17, 2013under the symbol "CVRR." In connection with the Refining Partnership IPO, the Refining Partnership paid approximately $32.5 million in underwriting feesand incurred approximately $3.9 million of other offering costs.Upon consummation of the Refining Partnership IPO, CVR indirectly owned the Refining Partnership's general partner and limited partnership interestsin the form of common units. Following the offering, the Refining Partnership has two types of partnership interests outstanding:•common units representing limited partner interests; and•a general partner interest, which is not entitled to any distributions, and which is held by the Refining Partnership's general partner.The net proceeds from the Refining Partnership IPO of approximately $653.6 million, after deducting underwriting discounts and commissions andoffering expenses, have been utilized as follows:•approximately $253.0 million was used to repurchase the 10.875% senior secured notes due 2017 (including accrued interest);•approximately $160.0 million was used to fund certain maintenance and environmental capital expenditures through 2014;•approximately $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery that were incurred during the fourth quarterof 2012;•approximately $85.1 million was distributed to CRLLC; and108Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)•the balance of the proceeds of approximately $101.5 million was allocated to be utilized by the Refining Partnership for general partnershippurposes.In connection with the Refining Partnership IPO and through May 19, 2013, the Company recorded a noncontrolling interest for the common units soldinto the public market, which represented an approximate 19% interest in the Refining Partnership. Prior to the Refining Partnership IPO, CVR owned 100%of the Refining Partnership and net income earned during this period was fully attributable to the Company.On May 20, 2013, the Refining Partnership completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to thepublic at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. Inconnection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of$30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described inthis paragraph are collectively referred to as the "Transactions." In connection with the Transactions, the Refining Partnership paid approximately $12.2million in underwriting fees and approximately $0.4 million in offering costs.The Refining Partnership utilized net proceeds of approximately $394.0 million from the Underwritten Offering (including net proceeds from theexercise of the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy.The net proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The RefiningPartnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC.Immediately following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of the total RefiningPartnership common units (including units owned by affiliates of IEP representing 4% of the total Refining Partnership common units), and CVR RefiningHoldings held approximately 71% of the total Refining Partnership common units.On June 30, 2014, the Refining Partnership completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000common units to the public at a price of $26.07 per unit. The Refining Partnership paid approximately $5.3 million in underwriting fees and approximately$0.5 million in offering costs. The Refining Partnership utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering toredeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July23, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately67% of the total Refining Partnership common units.On July 24, 2014, the Refining Partnership sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with theunderwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 millionfrom the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR RefiningHoldings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection withthe underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2015, public securityholders held approximately 34% of the total Refining Partnership common units (including units owned by affiliates of IEP representing 4% of the totalRefining Partnership common units), and CVR Refining Holdings held approximately 66% of the total Refining Partnership common units. In addition, CVRRefining Holdings owns 100% of the Refining Partnership's general partner, CVR Refining GP, LLC, which holds a non-economic general partner interest.The noncontrolling interest reflected on the Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the RefiningPartnership.The Refining Partnership's general partner, CVR Refining GP, LLC, manages the Refining Partnership's activities subject to the terms and conditionsspecified in the Refining Partnership's partnership agreement. The Refining Partnership's general partner is owned by CVR Refining Holdings. The operationsof its general partner, in its capacity as general partner, are109Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)managed by its board of directors. Actions by its general partner that are made in its individual capacity are made by CVR Refining Holdings as the solemember of the Refining Partnership's general partner and not by the board of directors of its general partner. The members of the board of directors of theRefining Partnership's general partner are not elected by the Refining Partnership's unitholders and are not subject to re-election on a regular basis. Theofficers of the general partner manage the day-to-day affairs of the business of the Refining Partnership.The Refining Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter. The available cashfor each quarter will be determined by the board of directors of the Refining Partnership's general partner following the end of such quarter. The partnershipagreement does not require that the Refining Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partnerof the Refining Partnership can change the distribution policy at any time.The Refining Partnership entered into a services agreement on December 31, 2012, pursuant to which the Refining Partnership and its general partnerobtain certain management and other services from CVR Energy. In addition, by virtue of the fact that the Refining Partnership is a controlled affiliate ofCVR Energy, the Refining Partnership is bound by an omnibus agreement entered into by CVR Energy, CVR Partners and the general partner of CVRPartners, pursuant to which the Refining Partnership may not 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 affiliatescontinue to own at least 50% of the Nitrogen Fertilizer Partnership's outstanding units.(2) Summary of Significant Accounting PoliciesPrinciples of ConsolidationThe accompanying CVR consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirectsubsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. The ownership interests of noncontrolling investors in itssubsidiaries are recorded as noncontrolling interests.The Nitrogen Fertilizer Partnership and the Refining Partnership are both consolidated based upon the fact that their general partners are owned by CVRand, therefore, CVR has the ability to control their activities. The Nitrogen Fertilizer Partnership's and the Refining Partnership's general partners managetheir respective operations and activities subject to the terms and conditions specified in their respective partnership agreements. The operations of eachgeneral partner in its capacity as general partner are managed by its board of directors. The limited rights of the common unitholders of the Nitrogen FertilizerPartnership and the Refining Partnership are demonstrated by the fact that the common unitholders have no right to elect either general partner or eithergeneral partner's directors on an annual or other continuing basis. Each general partner can only be removed by a vote of the holders of at least 66 2/3% of theoutstanding common units, including any common units owned by the general partner and its affiliates (including CVR) voting together as a single class.Actions by the general partner that are made in its individual capacity are made by the CVR subsidiary that serves as the sole member of the general partnerand not by the board of directors of the general partner. The officers of the general partner manage the day-to-day affairs of the business. The majority of theofficers of both general partners are also officers of CVR. Based upon the general partner's role and rights as afforded by the partnership agreements and thelimited rights afforded to the limited partners, the consolidated financial statements of CVR will include the assets, liabilities, cash flows, revenues andexpenses of the Nitrogen Fertilizer Partnership and the Refining Partnership.Cash and Cash EquivalentsFor purposes of the Consolidated Statements of Cash Flows, CVR considers all highly liquid money market accounts and debt instruments with originalmaturities of three months or less to be cash equivalents. Under the Company's cash management system, checks issued but not presented to banks frequentlyresult in book overdraft balances for accounting purposes and are classified as accounts payable in the Consolidated Balance Sheets. The change in bookoverdrafts are reported in the Consolidated Statements of Cash Flows as a component of operating cash flow for accounts payable as they do not representbank overdrafts. The amount of these checks included in accounts payable as of December 31, 2015 and 2014 was $24.7 million and $21.5 million,respectively.110Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Accounts Receivable, netCVR 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. Accountsoutstanding for longer than their contractual payment terms are considered past due. CVR determines its allowance for doubtful accounts by considering anumber of factors, including the length of time trade accounts are past due, the customer's ability to pay its obligations to CVR, and the condition of thegeneral economy and the industry as a whole. CVR writes off accounts receivable when they become uncollectible, and payments subsequently received onsuch receivables are credited to the allowance for doubtful accounts. Amounts collected on accounts receivable are included in net cash provided byoperating activities in the Consolidated Statements of Cash Flows. As of December 31, 2015 and 2014, no customers individually represented greater than10% of the total net accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2015 and 2014 was approximately9% and 8%, respectively, of the net accounts receivable balance.InventoriesInventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress, fertilizer products, and refined fuelsand by-products. Inventories are valued at the lower of the first-in, first-out ("FIFO") cost, or market for fertilizer products, refined fuels and by-products for allperiods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials andproduction 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 inboundfreight costs.Prepaid Expenses and Other Current AssetsPrepaid expenses and other current assets consist of prepayments for crude oil deliveries to the Refining Partnership's refineries for which title had nottransferred, non-trade accounts receivable, current portions of prepaid insurance, deferred financing costs, derivative agreements and other general currentassets.Property, Plant, and EquipmentAdditions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, arerecorded 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 usedin computing depreciation for such assets are as follows:AssetRange of UsefulLives, in YearsImprovements to land15 to 30Buildings20 to 30Machinery and equipment5 to 30Automotive equipment5 to 15Furniture and fixtures3 to 10Aircraft20Railcars25 to 30Leasehold improvements and assets held under capital leases are depreciated or amortized on the straight-line method over the shorter of the contractuallease term or the estimated useful life of the asset. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses arereported in direct operating expenses (exclusive of depreciation and amortization) in the Company's Consolidated Statements of Operations.111Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Goodwill and Intangible AssetsGoodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets areassets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite usefullives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested forimpairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. CVR uses November 1 of each year as itsannual valuation date for its goodwill impairment test. The Company performed its annual impairment review of goodwill for 2015, 2014 and 2013, which isattributable entirely to the nitrogen fertilizer segment and concluded there were no impairments. See Note 6 ("Goodwill") for further discussion.Deferred Financing CostsDeferred financing costs associated with debt issuances are amortized to interest expense and other financing costs using the effective-interest methodover the life of the debt. Additionally, any underwriting and original issue discount and premium related to debt issuances are amortized to interest expenseand other financing costs using the effective-interest method over the life of the debt. Deferred financing costs related to the Refining Partnership's Amendedand Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership's revolving credit facility are amortized to interest expense and other financing costsusing the straight-line method through the termination date of the respective facility.Planned Major Maintenance CostsThe direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense whenmaintenance services are performed. Planned major maintenance activities for the nitrogen plant generally occur every two to three years. The requiredfrequency of planned major maintenance activities varies by unit for the refineries, but generally is every four to five years. Costs associated with theseturnaround activities were included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.For the years ended December 31, 2015 and 2014, the Company's petroleum and nitrogen fertilizer segments incurred the following major scheduledturnaround expenses. No major scheduled turnaround expenses were incurred for the year ended December 31, 2013. For the Year Ended December 31, 2015 2014 (in millions)Petroleum segment Coffeyville refinery(1)$102.2 $5.5Wynnewood refinery(2)— 1.3 Nitrogen Fertilizer segment Nitrogen Fertilizer plant(3)7.0 —Total Major Scheduled Turnaround Expenses$109.2 $6.8_______________________________________(1)The Coffeyville refinery completed the first phase of its current major scheduled turnaround in mid-November 2015. The second phase is scheduled tobegin in late February 2016. During the outage at the Coffeyville refinery as discussed in Note 7 ("Insurance Claims"), the Refining Partnershipaccelerated certain planned turnaround activities scheduled for 2015 and incurred turnaround expenses for the year ended December 31, 2014.(2)During the fluid catalytic cracking unit ("FCCU") outage at the Wynnewood refinery, the Refining Partnership accelerated certain planned turnaroundactivities previously scheduled for 2016 and incurred turnaround expenses for the year ended December 31, 2014. The next turnaround for theWynnewood refinery is scheduled to occur in the spring of 2017.(3)The Nitrogen Fertilizer Partnership underwent a full facility turnaround in the third quarter of 2015. The Nitrogen Fertilizer Partnership is planning toundergo the next scheduled full facility turnaround in the second half of 2017.112Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Cost ClassificationsCost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, purchased refined products,pet coke expenses, renewable identification numbers ("RINs") expenses and freight and distribution expenses. Cost of product sold excluded depreciationand amortization of approximately $6.7 million, $6.3 million and $5.0 million for the years ended December 31, 2015, 2014 and 2013, 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 excludeddepreciation and amortization of approximately $149.7 million, $141.8 million and $134.5 million for the years ended December 31, 2015, 2014 and 2013,respectively.Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting,marketing, human resources, information technology and maintaining the corporate and administrative offices in Texas and Kansas. Selling, general andadministrative expenses excluded depreciation and amortization of approximately $7.7 million, $6.3 million and $3.3 million for the years endedDecember 31, 2015, 2014 and 2013, respectively.Income TaxesCVR accounts for income taxes utilizing the asset and liability approach. Under this method, deferred tax assets and liabilities are recognized for theanticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and theirrespective tax basis. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences areexpected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includesthe enactment date. See Note 8 ("Income Taxes") for further discussion.Impairment of Long-Lived AssetsCVR accounts for long-lived assets in accordance with accounting standards issued by the Financial Accounting Standards Board ("FASB") regardingthe treatment of the impairment or disposal of long-lived assets. As required by these standards, CVR reviews 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 amountof 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 estimatedundiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future netcash 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 ofare reported at the lower of their carrying value or fair value less cost to sell.Revenue RecognitionRevenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has theassumed risk of loss, and payment has been received or collection is reasonably assured. Deferred revenue represents customer prepayments under contracts toguarantee a price and supply of nitrogen fertilizer in quantities expected to be delivered in the next 12 months in the normal course of business. Excise andother 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 netcost basis in operating expenses on the Consolidated Statement 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 a principal in these transactions, taking title to the products in purchases from counterparties, and accepting the risks and rewards ofownership. The Company records revenue for the gross amount of the sales transactions, and records costs of purchases as an operating expense in theaccompanying consolidated financial statements.113Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Shipping CostsPass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of productsold (exclusive of depreciation and amortization).Derivative Instruments and Fair Value of Financial InstrumentsThe petroleum business uses futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices and finishedgoods product prices to provide economic hedges of inventory positions. Although management considers these derivatives economic hedges, thesederivative instruments do not qualify as hedges for hedge accounting purposes under Accounting Standards Codification ("ASC") Topic 815, Derivativesand Hedging ("ASC 815"), and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments arerecorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are basedon quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable.The nitrogen fertilizer business uses forward swap contracts primarily to reduce the exposure to changes in interest rates on its debt and to provide a cashflow hedge. These derivative instruments have been designated as hedges for accounting purposes. Accordingly, these instruments are recorded at fair valuein the Consolidated Balance Sheets at each reporting period end. The measurement of the cash flow hedge ineffectiveness is recognized in earnings, ifapplicable. The effective portion of the gain or loss on the swaps is reported in accumulated other comprehensive income (loss) ("AOCI"), in accordance withASC 815. See Note 15 ("Derivative Financial Instruments") for further discussion.Other financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximatesfair value, as a result of the short-term nature of the instruments. See Note 9 ("Long-Term Debt") for further discussion of the fair value of the debt instruments.Share-Based CompensationThe Company accounts for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation ("ASC 718"). ASC 718requires that compensation costs relating to share-based payment transactions be recognized in a company's financial statements. ASC 718 applies totransactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or servicesthat are based on the fair value of those equity instruments. See Note 3 ("Share-Based Compensation") for further discussion.Treasury StockThe Company accounts for its treasury stock under the cost method. To date, all treasury stock purchased was for the purpose of satisfying minimumstatutory tax withholdings due at the vesting of non-vested stock awards.Environmental MattersLiabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are consideredprobable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, internal and third party assessments ofcontamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, nooffset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as furtherinformation develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures arecapitalized at the time of the expenditure when such costs provide future economic benefits.Use of EstimatesThe consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles, using management's bestestimates and judgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of contingentassets and liabilities at the date of the financial114Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from these estimates andjudgments.Subsequent EventsThe Company evaluated subsequent events, if any, that would require an adjustment to the Company's consolidated financial statements or requiredisclosure in the notes to the consolidated financial statements through the date of issuance of the consolidated financial statements. See Note 20("Subsequent Events") for further discussion.Recent Accounting PronouncementsIn May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), whichrequires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The standard is effective for interim and annual periodsbeginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. OnJuly 9, 2015, the FASB approved a one-year deferral of the effective date making the standard effective for interim and annual periods beginning afterDecember 15, 2017. The FASB will continue to permit entities to adopt the standard on the original effective date if they choose. The Company has not yetselected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.In February 2015, the FASB issued ASU No. 2015-02, "Consolidations (Topic 810) - Amendments to the Consolidation Analysis." The new guidancemakes amendments to the current consolidation guidance, including introducing a separate consolidation analysis specific to limited partnerships and othersimilar entities. Under this analysis, limited partnerships and other similar entities will be considered a variable-interest entity ("VIE") unless the limitedpartners hold substantive kick-out rights or participating rights. The standard is effective for annual periods beginning after December 15, 2015. TheCompany is currently evaluating the standard and the impact, if any, on its consolidated financial statements and footnote disclosures; however, theCompany does not anticipate that the standard will impact the Company's conclusion with respect to the consolidation of the Refining and NitrogenFertilizer Partnerships.In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03"). The new standard requires that allcosts incurred to issue debt be presented in the balance sheet as a direct deduction from the carrying value of the debt. The standard is effective for interimand annual periods beginning after December 15, 2015 and is required to be applied on a retrospective basis. Early adoption is permitted. The Companyexpects that the adoption of ASU 2015-03 will result in a reclassification of certain debt issuance costs on the Consolidated Balance Sheets.In November 2015, the FASB issued ASU 2015-17, "Balance Sheet Classification of Deferred Taxes" ("ASU 2015-17"). The new standard requires thatall deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The standard is effectivefor interim and annual periods beginning after December 15, 2016 and early adoption is permitted. The new standard may be applied either prospectively orretrospectively upon adoption. The Company elected to early adopt ASU 2015-17 as of December 31, 2015 and applied the standard prospectively to theConsolidated Balance Sheet. The Consolidated Balance Sheet as of December 31, 2014 was not retrospectively adjusted. Refer to Note 8 ("Income Taxes")for further details.115Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(3) Share-Based CompensationLong-Term Incentive Plan — CVR EnergyCVR has a Long-Term Incentive Plan ("LTIP"), which permits the grant of options, stock appreciation rights, restricted shares, restricted stock units,dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restrictedstock). As of December 31, 2015, only restricted stock units and performance units remain outstanding under the LTIP. Individuals who are eligible to receiveawards and grants under the LTIP include the Company's employees, officers, consultants, advisors and directors. A summary of the principal features of theLTIP is provided below.Shares Available for Issuance. The LTIP authorizes a share pool of 7,500,000 shares of the Company's common stock, 1,000,000 of which may be issuedin respect of incentive stock options. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwiseterminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of shares available forissuance under the LTIP is increased by the number of shares previously allocable to the expired, canceled, settled or otherwise terminated portion of theaward. As of December 31, 2015, 6,787,341 shares of common stock were available for issuance under the LTIP.Restricted Stock UnitsA summary of restricted stock units activity and changes during the years ended December 31, 2015, 2014 and 2013 is presented below: RestrictedShares Weighted-AverageGrant-DateFair Value AggregateIntrinsicValue (in millions)Non-vested at December 31, 20121,145,611 $23.24 $55.9Granted2,600 54.75 Vested(709,959) 18.73 Forfeited(78,700) 42.80 Non-vested at December 31, 2013359,552 $28.09 $15.6Granted— — Vested(281,684) 23.89 Forfeited(29,857) 39.17 Non-vested at December 31, 201448,011 $45.89 $1.9Granted— — Vested(43,085) 45.55 Forfeited(4,327) 47.68 Non-vested at December 31, 2015599 $57.23 $—Through the LTIP, shares of restricted stock and restricted stock units (collectively "restricted shares") were previously granted to employees of theCompany. These restricted shares are generally graded-vesting awards, which vest over a three-year period. Compensation expense is recognized on astraight-line basis over the vesting period of the respective tranche of the award. The IEP Acquisition and related Transaction Agreement dated April 18,2012 between CVR and an affiliate of IEP discussed in Note 1 ("Organization and History of the Company") triggered a modification to outstanding awardsunder the LTIP converting the awards to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cashplus one CCP upon vesting. The CCPs expired on August 19, 2013. Restricted shares that vested in 2013, 2014 and 2015 were converted to restricted stockunits whereby the awards were settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value of the Company'scommon stock as determined at the most recent valuation date of December 31 of each year. The awards were remeasured at each subsequent reporting dateuntil they vested. As a result of the modification of the awards, the classification changed from equity-classified awards to liability-classified awards.116Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)In December 2012 and during 2013, awards of restricted stock units and dividend equivalent rights were granted to certain employees of CVR. Theawards vest over three years with one-third of the award vesting each year with the exception of awards granted to certain executive officers that vested overone year. The award granted in December 2012 to Mr. Lipinski, the Company's Chief Executive Officer and President, was canceled in connection with theissuance of certain performance unit awards as discussed further below. Each restricted stock unit and dividend equivalent right represents the right toreceive, upon vesting, a cash payment equal to (i) the fair market value of one share of the Company's common stock, plus (ii) the cash value of all dividendsdeclared and paid by the Company per share of the Company's common stock from the grant date to and including the vesting date. The awards, which areliability-classified, are remeasured each subsequent reporting date until they vest.As of December 31, 2015, total unrecognized compensation cost related to non-vested restricted stock units and associated dividend equivalent rightsand the weighted average period over which it will be recognized were nominal. Total compensation expense for the years ended December 31, 2015, 2014and 2013 was approximately $0.8 million, $2.6 million and $13.2 million, respectively, related to the restricted stock unit awards.As of December 31, 2014, the Company had a liability of $1.7 million for non-vested restricted stock unit awards and associated dividend equivalentrights, which is recorded in personnel accruals on the Consolidated Balance Sheets. The liability as of December 31, 2015 was nominal. For the years endedDecember 31, 2015, 2014 and 2013, the Company paid cash of $2.5 million, $9.9 million and $23.8 million, respectively, to settle liability-classifiedrestricted stock unit awards and dividend equivalent rights upon vesting.Performance Unit AwardsIn December 2013, the Company entered into performance unit awards agreements (the "2013 Performance Unit Awards Agreements") with Mr. Lipinski.Certain of the 2013 Performance Unit Awards Agreements were entered into in connection with the cancellation of Mr. Lipinski's December 2012 restrictedstock unit award, as discussed above. In accordance with accounting guidance related to the modification of share-based and other compensatory awardarrangements, the Company concluded that the cancellation and concurrent issuance of the performance awards created a substantive service period from theoriginal grant date of the December 2012 restricted stock unit award through December 31, 2014, the end of the performance period for the relatedperformance awards. Compensation cost for the related awards was recognized over the substantive service period. Total compensation expense for the yearsended and December 31, 2014 and 2013 related to the performance unit awards was $4.4 million and $3.9 million, respectively.The Company paid Mr. Lipinski approximately $6.8 million during 2014 for vested performance unit awards. As of December 31, 2014, the Companyhad a liability of $1.7 million recorded in personnel accruals on the Consolidated Balance Sheets for the final vested and unpaid 2013 Performance UnitAwards, which was paid in the first quarter of 2015.In December 2015, the Company entered into a performance unit award agreement (the "2015 Performance Unit Award Agreement") with Mr. Lipinski.Compensation cost for the 2015 Performance Unit Award Agreement will be recognized over the performance cycle from January 1, 2016 to December 31,2016. The performance unit award represents the right to receive, upon vesting, a cash payment equal to a defined threshold in accordance with the awardagreement, multiplied by a performance factor that is based upon the achievement of certain operating objectives. Assuming a target performance threshold,there was approximately $3.5 million of total unrecognized compensation cost related to the 2015 Performance Unit Award Agreement to be recognized overa weighted-average period of approximately 1.0 year.Long-Term Incentive Plan — CVR PartnersCommon Units and Phantom UnitsIn April 2011, the board of directors of the Nitrogen Fertilizer Partnership's general partner adopted the CVR Partners, LP Long-Term Incentive Plan("CVR Partners LTIP"). Individuals who are eligible to receive awards under the CVR Partners LTIP include (i) employees of the Nitrogen FertilizerPartnership and its subsidiaries, (ii) employees of its general partner, (iii) members of the board of directors of its general partner and (iv) employees,consultants and directors of CVR Energy. The CVR Partners LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights,restricted units, phantom units and other unit-based awards, each in respect of common units. The maximum number of common units issuable under the117Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)CVR Partners' LTIP is 5,000,000. As of December 31, 2015, there were 4,820,215 common units available for issuance under the CVR Partners LTIP.Through the CVR Partners LTIP, phantom and common units have been awarded to employees of the Nitrogen Fertilizer Partnership and its generalpartner and to members of the board of directors of its general partner. In 2013, 2014 and 2015, awards of phantom units and distribution equivalent rightswere granted to certain employees of the Nitrogen Fertilizer Partnership and its subsidiaries and its general partner. The awards are generally graded vestingawards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-linebasis over the vesting period of the respective tranche of the award. Each phantom unit and distribution equivalent right represents the right to receive, uponvesting, a cash payment equal to (i) the average fair market value of one unit of the Nitrogen Fertilizer Partnership's common units in accordance with theaward agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Nitrogen Fertilizer Partnership from the grant date to andincluding the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.A summary of common units and phantom units (collectively "units") activity and changes under the CVR Partners LTIP during the years endedDecember 31, 2015, 2014 and 2013 is presented below: Units Weighted-AverageGrant-DateFair Value AggregateIntrinsicValue (in millions)Non-vested at December 31, 2012201,812 $23.70 $5.1Granted58,536 16.13 Vested(89,229) 23.24 Forfeited— — Non-vested at December 31, 2013171,119 $21.34 $2.8Granted198,141 9.44 Vested(48,310) 20.95 Forfeited(77,004) 23.49 Non-vested at December 31, 2014243,946 $11.07 $2.4Granted245,199 7.87 Vested(94,854) 12.55 Forfeited(2,388) 10.99 Non-vested at December 31, 2015391,903 $8.71 $3.1As of December 31, 2015, there was approximately $2.7 million of total unrecognized compensation cost related to the awards under the CVR PartnersLTIP to be recognized over a weighted-average period of 1.8 years. Total compensation expense recorded for the years ended December 31, 2015, 2014 and2013 related to the awards under the CVR Partners LTIP was approximately $1.3 million, $0.4 million and $1.3 million, respectively.At December 31, 2015 and 2014, the Nitrogen Fertilizer Partnership had a liability of $0.7 million and $0.2 million, respectively, for cash-settled non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Consolidated Balance Sheets. Forthe years ended December 31, 2015, 2014 and 2013 the Nitrogen Fertilizer Partnership paid cash of $0.8 million, $0.4 million and $0.2 million, respectively,to settle liability-classified awards and associated distribution equivalent rights upon vesting.Performance-Based Phantom UnitsIn May 2014, the Nitrogen Fertilizer Partnership entered into a Phantom Unit Agreement with the Chief Executive Officer and President of its generalpartner that included performance-based phantom units and distribution equivalent rights. Compensation cost for these awards is being recognized over theperformance cycles of May 1, 2014 to December 31, 2014, January 1, 2015 to December 31, 2015 and January 1, 2016 to December 31, 2016, as the servicesare provided. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average118Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)closing price of the Nitrogen Fertilizer Partnership's common units in accordance with the award agreement, multiplied by a performance factor that is basedupon the level of the Nitrogen Fertilizer Partnership’s production of UAN, and (ii) the per unit cash value of all distributions declared and paid by theNitrogen Fertilizer Partnership from the grant date to and including the vesting date. Total compensation expense recorded for the years ended December 31,2015 and 2014 related to the award was not material. Based on current estimates of performance thresholds for the remaining performance cycles,unrecognized compensation expense and the liability associated with the unvested phantom units at December 31, 2015 were also not material.On December 31, 2014, the first award of Mr. Pytosh's Phantom Unit Agreement vested and a nominal amount was paid in 2015. On December 31, 2015,the second award of Mr. Pytosh's Phantom Unit Agreement vested and a nominal amount will be paid in 2016.Long-Term Incentive Plan – CVR RefiningIn connection with the Refining Partnership IPO, on January 16, 2013, the board of directors of the general partner of the Refining Partnership adoptedthe CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"). Individuals who are eligible to receive awards under the CVR Refining LTIPinclude (i) employees of the Refining Partnership and its subsidiaries, (ii) employees of the general partner, (iii) members of the board of directors of thegeneral partner and (iv) certain employees, consultants and directors of CRLLC and CVR Energy who perform services for the benefit of the RefiningPartnership. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards,other-unit based awards, cash awards, performance awards and distribution equivalent rights, each in respect of common units. The maximum number ofcommon units issuable under the CVR Refining LTIP is 11,070,000. As the phantom unit awards discussed below are cash-settled awards, they did not reducethe number of common units available for issuance under the plan. On August 14, 2013, the Refining Partnership filed a Form S-8 to register the commonunits.In 2013, 2014 and 2015, awards of phantom units and distribution equivalent rights were granted to employees of the Refining Partnership and itssubsidiaries, its general partner and certain employees of CRLLC and CVR Energy who perform services solely for the benefit of the Refining Partnership.The awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensationexpense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each phantom unit and distribution equivalentright represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Refining Partnership's commonunits in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Refining Partnership from thegrant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.119Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)A summary of phantom unit activity and changes under the CVR Refining LTIP during the years ended December 31, 2015, 2014 and 2013 is presentedbelow: Phantom Units Weighted-AverageGrant-DateFair Value AggregateIntrinsicValue (in millions)Non-vested at January 16, 2013— $— $—Granted187,177 21.55 Vested— — Forfeited— — Non-vested at December 31, 2013187,177 $21.55 $4.2Granted281,948 17.74 Vested(61,002) 21.55 Forfeited(4,176) 21.55 Non-vested at December 31, 2014403,947 $18.89 $6.8Granted302,319 20.40 Vested(136,531) 19.26 Forfeited(58,144) 18.87 Non-vested at December 31, 2015511,591 $19.68 $9.7As of December 31, 2015, there was approximately $8.3 million of total unrecognized compensation cost related to the awards under the CVR RefiningLTIP to be recognized over a weighted-average period of 1.7 years. Total compensation expense recorded for the years ended December 31, 2015 and 2014related to the awards under the CVR Refining LTIP was $4.6 million and $2.4 million, respectively. Total compensation expense recorded for the year endedDecember 31, 2013 was not material. As of December 31, 2015 and 2014, the Refining Partnership had a liability of $2.3 million and $1.0 million,respectively, for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the ConsolidatedBalance Sheets. For the years ended December 31, 2015 and 2014, the Refining Partnership paid cash of $3.3 million and $1.4 million, respectively, to settleliability-classified phantom unit awards and associated distribution equivalent rights upon vesting.In December 2014, the Company granted an award of 227,927 incentive units in the form of stock appreciation rights ("SARs") to an executive of CVREnergy. In April 2015, the award granted was cancelled and replaced by an award of notional units in the form of SARs by CVR Refining pursuant to theCVR Refining LTIP. The replacement award is structured on the same economic and other terms as the incentive unit award and did not result in a materialimpact. Each SAR vests over three years and entitles the executive to receive a cash payment in an amount equal to the excess of the fair market value of oneunit of the Refining Partnership's common units for the first ten trading days in the month prior to vesting over the grant price of the SAR. The fair value willbe adjusted to include all distributions declared and paid by the Refining Partnership during the vesting period. The fair value of each SAR is estimated atthe end of each reporting period using the Black-Scholes option-pricing model. Assumptions utilized to value the award have been omitted due toimmateriality of the award. Total compensation expense during the years ended December 31, 2015 and 2014 and the liability related to the SARs as ofDecember 31, 2015 and 2014 were not material.Incentive Unit AwardsIn 2013, 2014 and 2015, the Company granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC, CVR Energyand CVR GP, LLC. The awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year.Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each incentive unit anddistribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the RefiningPartnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the RefiningPartnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reportingdate until they vest.120Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)A summary of incentive unit activity and changes during the years ended December 31, 2015, 2014 and 2013 is presented below: Incentive Units Weighted-AverageGrant-DateFair Value AggregateIntrinsicValue (in millions)Non-vested at December 31, 2012— $— $—Granted251,431 22.62 Vested— — Forfeited— — Non-vested at December 31, 2013251,431 $22.62 $5.7Granted332,586 17.81 Vested(65,601) 22.63 Forfeited(82,901) 22.62 Non-vested at December 31, 2014435,515 $18.95 $7.3Granted347,811 20.38 Vested(160,120) 19.33 Forfeited(18,264) 19.69 Non-vested at December 31, 2015604,942 $19.64 $11.5As of December 31, 2015, there was approximately $9.6 million of total unrecognized compensation cost related to non-vested incentive units to berecognized over a weighted-average period of approximately 1.7 years. Total compensation expense for the years ended December 31, 2015 and 2014 relatedto the incentive units was $5.7 million and $2.4 million, respectively. Total compensation expense for the year ended December 31, 2013 related to theincentive units was not material. As of December 31, 2015 and 2014, the Company had a liability of $2.6 million and $0.8 million, respectively, for non-vested incentive units and associated distribution equivalent rights, which is recorded in personnel accruals on the Consolidated Balance Sheets. For theyears ended December 31, 2015 and 2014, the Company paid cash of $3.9 million and $1.6 million, respectively, to settle liability-classified incentive unitawards and associated distribution equivalent rights upon vesting.(4) InventoriesInventories consisted of the following: December 31, 2015 2014 (in millions)Finished goods$114.5 $176.2Raw materials and precious metals81.2 88.0In-process inventories35.8 20.6Parts and supplies58.4 44.8 $289.9 $329.6Due to the crude pricing environment and subsequent reduction in sales prices for the petroleum business' refined products at the end of 2014, theRefining Partnership recorded a lower of FIFO cost or market inventory adjustment of approximately $36.8 million as of December 31, 2014. The inventoryadjustment is included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.121Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(5) Property, Plant and EquipmentA summary of costs for property, plant, and equipment is as follows: December 31, 2015 2014 (in millions)Land and improvements$38.6 $37.4Buildings53.6 50.4Machinery and equipment2,723.0 2,581.2Automotive equipment24.8 22.1Furniture and fixtures21.3 19.0Leasehold improvements3.6 3.4Aircraft3.6 3.7Railcars16.3 14.5Construction in progress122.3 71.5 3,007.1 2,803.2Accumulated depreciation1,040.0 887.2 $1,967.1 $1,916.0Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2015, 2014 and 2013 totaled approximately $3.7million, $9.4 million and $3.6 million, respectively. Land, building and equipment that are under a capital lease obligation had an original carrying value ofapproximately $24.8 million at both December 31, 2015 and 2014, respectively. Amortization of assets held under capital leases is included in depreciationexpense.(6) GoodwillThe Nitrogen Fertilizer Partnership completes its annual test for impairment of goodwill as of November 1 each year. The Nitrogen Fertilizer Partnershipelected to perform a qualitative evaluation for the years ended December 31, 2015 and 2014 to determine whether it was necessary to perform thequantitative two step goodwill analysis described in ASC 350, "Intangibles - Goodwill and Other." After assessing the totality of events and circumstances, itwas determined that it was not more likely than not that the fair value of the Nitrogen Fertilizer Partnership was less than the carrying value, and so it was notnecessary to perform the two-step goodwill impairment analysis. Based on the results of the tests, no impairment of goodwill was recorded for any of theperiods presented.(7) Insurance ClaimsOn July 29, 2014, the Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employeewho was fatally injured. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System,which was directly caused by the fire. The Coffeyville refinery returned to operations in mid-August, with all units except the isomerization unit in operationby August 23, 2014. The isomerization unit started operating on October 12, 2014. This interruption adversely impacted production of refined products forthe petroleum business in the third quarter of 2014. Total gross repair and other costs recorded related to the incident for the year ended December 31, 2014were approximately $6.3 million.The Refining Partnership is covered by property damage insurance policies at the time of the incident, which had an associated deductible of $5.0million for the Coffeyville refinery. The Refining Partnership anticipates amounts in excess of the $5.0 million deductible related to the isomerization unitfire incident will be recoverable under the property insurance policies. As of December 31, 2015 and 2014, the Refining Partnership had an insurancereceivable related to the incident of approximately $1.2 million and $1.3 million, respectively, which is included in prepaid expenses and other current assetsin the Consolidated Balance Sheet. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation andamortization).122Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)During the outage at the Coffeyville refinery as discussed above, the Refining Partnership accelerated certain planned turnaround activities scheduledfor 2015 and incurred approximately $5.5 million in turnaround expenses for the year ended December 31, 2014.(8) Income TaxesOn May 19, 2012, CVR became a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of IEP, and subsequently enteredinto a tax allocation agreement with AEPC (the "Tax Allocation Agreement"). The Tax Allocation Agreement provides that AEPC will pay all consolidatedfederal income taxes on behalf of the consolidated tax group. CVR is required to make payments to AEPC in an amount equal to the tax liability, if any, thatit would have paid if it were to file as a consolidated group separate and apart from AEPC.As of December 31, 2015 and 2014, the Company's Consolidated Balance Sheets reflected a receivable of $11.6 million and $44.5 million, respectively,for an overpayment of federal income taxes due to AEPC. The overpayment for 2015 will be applied as a credit against the Company's estimated tax to bepaid during 2016 while the overpayment for 2014 was applied as a credit against the Company's tax owed during 2015. These amounts are recorded as duefrom parent in the Consolidated Balance Sheets. During the years ended December 31, 2015, 2014 and 2013, the Company paid $57.5 million, $120.1million and $260.0 million, respectively, to AEPC under the Tax Allocation Agreement.Income tax expense (benefit) is comprised of the following: Year Ended December 31, 2015 2014 2013 (in millions)Current Federal$74.9 $76.1 $265.8State14.5 16.6 21.5Total current89.4 92.7 287.3Deferred Federal2.7 8.3 (93.5)State(7.6) (3.3) (10.1)Total deferred(4.9) 5.0 (103.6)Total income tax expense$84.5 $97.7 $183.7The following is a reconciliation of total income tax expense (benefit) to income tax expense (benefit) computed by applying the statutory federalincome tax rate (35%) to pretax income (loss): Year Ended December 31, 2015 2014 2013 (in millions)Tax computed at federal statutory rate$133.8 $142.5 $247.0State income taxes, net of federal tax benefit11.7 14.0 16.5State tax incentives, net of federal tax expense(7.2) (5.4) (9.0)Domestic production activities deduction(5.9) (5.5) (18.5)Non-deductible share-based compensation— 0.2 1.5Noncontrolling interest(44.9) (47.4) (53.0)Other, net(3.0) (0.7) (0.8)Total income tax expense$84.5 $97.7 $183.7The Company earns Kansas High Performance Incentive Program ("HPIP") credits for qualified business facility investment within the state of Kansas.CVR recognized a net income tax benefit of approximately $4.3 million, $2.8 million123Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)and $7.8 million on a credit of approximately $6.7 million, $4.3 million and $12.0 million for the years ended December 31, 2015, 2014 and 2013,respectively, with respect to the HPIP credits. The Company earns Oklahoma Investment credits for qualified manufacturing facility investment within thestate of Oklahoma. CVR recognized a net income tax benefit of approximately $2.9 million, $2.5 million and $1.2 million on a credit of approximately $4.4million, $3.9 million and $1.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, with respect to the Oklahoma Investment credits.As discussed in Note 2 ("Summary of Significant Accounting Policies"), the Company elected to early adopt ASU 2015-17 as of December 31, 2015. Thenew standard requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet.The Company applied the new standard prospectively to the Consolidated Balance Sheet as of December 31, 2015. The reclassification of current deferredincome taxes to noncurrent deferred income taxes was not material. The Consolidated Balance Sheet as of December 31, 2014 was not retrospectivelyadjusted.The income tax effect of temporary differences that give rise to significant portions of the deferred income tax assets and deferred income tax liabilities atDecember 31, 2015 and 2014 are as follows: Year Ended December 31, 2015 2014 (in millions)Deferred income tax assets: Personnel accruals$1.5 $1.8State tax credit carryforward, net11.0 12.6Contingent liabilities0.1 0.1Other— 2.1Total gross deferred income tax assets12.6 16.6Deferred income tax liabilities: Property, plant, and equipment(3.1) (2.7)Investment in CVR Partners(83.4) (76.1)Investment in CVR Refining(565.3) (569.4)Prepaid expenses(0.3) (0.3)Other(0.2) (0.1)Total gross deferred income tax liabilities(652.3) (648.6)Net deferred income tax liabilities$(639.7) $(632.0)CVR has Oklahoma state income tax credits of approximately $25.9 million which are available to reduce future Oklahoma state regular income taxes.These credits have an indefinite life.In assessing the realizability of deferred tax assets including credit carryforwards, management considers whether it is more likely than not that someportion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxableincome during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities,projected future taxable income, and tax planning strategies in making this assessment. Although realization is not assured, management believes that it ismore likely than not that all of the deferred tax assets will be realized and thus, no valuation allowance was provided as of December 31, 2015 and 2014.124Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)A reconciliation of the unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013 is as follows: Year Ended December 31, 2015 2014 2013 (in millions)Balance beginning of year$55.5 $45.2 $36.9Increase based on prior year tax positions— 0.5 —Decrease based on prior year tax positions— — (6.4)Increases in current year tax positions9.8 9.8 14.7Settlements— — —Reductions related to expirations of statute of limitations(16.3) — —Balance end of year$49.0 $55.5 $45.2Included in the balance of unrecognized tax benefits as of December 31, 2015, 2014 and 2013 are $31.8 million, $25.6 million and $19.1 million,respectively, of tax benefits that, if recognized, would affect the effective tax rate. Approximately $16.3 million of the unrecognized tax positions relating tothe characterization of partnership distributions received were recognized by the end of 2015 as a result of a lapse of the statute of limitations. Additionally,the Company believes that it is reasonably possible that approximately $11.6 million of its unrecognized tax positions relating to state tax credits may berecognized by the end of 2016 as a result of a lapse of the statute of limitations. Under ASU 2013-11, approximately $25.9 million and $13.5 million ofunrecognized tax benefits were netted with deferred tax asset carryforwards as of December 31, 2015 and 2014, respectively. The remaining unrecognized taxbenefits are included in other long-term liabilities in the Consolidated Balance Sheets.CVR recognizes interest expense (income) and penalties on uncertain tax positions and income tax deficiencies (refunds) in income tax expense. CVRrecognized interest expense of approximately $1.0 million during 2015. No penalties were recognized during 2015. As of December 31, 2015, CVR hasrecognized a liability for interest of approximately $7.5 million. No liability was recognized for penalties in 2015. In 2014, CVR recognized interest expenseof approximately $3.8 million. No penalties were recognized during 2014. As of December 31, 2014, CVR had recognized a liability for interest ofapproximately $6.5 million. No liability was recognized for penalties in 2014. In 2013, CVR recognized interest expense of approximately $2.2 million. Nopenalties were recognized during 2013.At December 31, 2015, the Company's tax filings are generally open to examination in the United States for the tax years ended December 31, 2012through December 31, 2014 and in various individual states for the tax years ended December 31, 2011 through December 31, 2014.(9) Long-Term DebtLong-term debt was as follows: December 31, 2015 December 31, 2014 (in millions)6.5% Senior Notes due 2022$500.0 $500.0CRNF credit facility125.0 125.0Capital lease obligations48.5 49.9Total debt673.5 674.9Current portion of long-term debt and capital lease obligations(126.6) (1.4)Long-term debt, net of current portion$546.9 $673.5Old Senior Secured NotesOn April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, completed a private offering of $225.0 million aggregate principalamount of 10.875% Second Lien Senior Secured Notes due 2017 (the "Old Second Lien125Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Notes"). The Old Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by the issuers. On January 23, 2013,$253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Old Second Lien Notes.The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Old Second Lien Notes then outstanding, (ii) pay theredemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. Therepurchase of the Old Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the year ended December 31, 2013,which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.2022 Senior Secured NotesOn October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% SecondLien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cashproceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes were secured bysubstantially the same assets that secured the then outstanding Old Second Lien Notes, subject to exceptions, until such time that the then outstanding OldSecond Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes are no longer secured. The 2022Notes are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries on a joint and several basis.CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction anddischarge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, the NitrogenFertilizer Partnership and CRNF, a wholly owned subsidiary of the Nitrogen Fertilizer Partnership, are not guarantors.The net proceeds from the offering of the 2022 Notes were used to purchase all of the then outstanding First Lien Secured Notes due 2015 through atender offer and settled redemption in the fourth quarter of 2012.The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interestexpense using the effective-interest amortization method. On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registeredexchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms thatwere registered under the Securities Act of 1933. The exchange offer fulfilled the Refining Partnership's obligations contained in the registration rightsagreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership incurred approximately $0.4 million of debt registrationcosts related to the registration and exchange offer during the year ended December 31, 2013, which are being amortized over the term of the 2022 Notes asinterest expense using the effective-interest amortization method.The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annuallyon May 1 and November 1 of each year, commencing on May 1, 2013.The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additionalindebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinateddebt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that theRefining Partnership can make distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio andthere is no default or event of default under the 2022 Notes. As of December 31, 2015, the Refining Partnership was in compliance with the covenantscontained in the 2022 Notes.Included in other current liabilities on the Consolidated Balance Sheets is accrued interest payable totaling approximately $5.4 million as of bothDecember 31, 2015 and 2014 related to the 2022 Notes. At December 31, 2015, the estimated fair value of the 2022 Notes was approximately $485.0 million.This estimate of fair value is Level 2 as it was determined by quotations obtained from a broker-dealer who makes a market in these and similar securities.126Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Amended and Restated Asset Based (ABL) Credit FacilityOn December 20, 2012, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties")entered into an amended and restated ABL credit agreement (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells FargoBank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility is scheduled tomature on December 20, 2017. Under the Amended and Restated ABL Credit Facility, the Refining Partnership assumed the Company's position as borrowerand the Company's obligations under the facility upon the closing of the Refining Partnership's IPO on January 23, 2013, as further discussed in Note 1("Organization and History of the Company").The Amended and Restated ABL Credit Facility is a senior secured asset-based revolving credit facility in an aggregate principal amount of up to $400.0million with an incremental facility, which permits an increase in borrowings of up to $200.0 million subject to additional lender commitments and certainother conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit Parties andtheir subsidiaries. The Amended and Restated ABL Credit Facility provides for loans and letters of credit in an amount up to the aggregate availability underthe facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of thetotal facility commitment for letters of credit.Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicablemargin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% ofthe lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case ifquarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and RestatedABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters ofcredit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans andletters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership is alsorequired to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount availableto be drawn under and for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawnunder, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Partiesand their respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incurindebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries.The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. The Credit Parties were incompliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2015.In connection with the Amended and Restated ABL Credit Facility, CRLLC and its subsidiaries incurred lender and other third-party costs ofapproximately $2.1 million for the year ended December 31, 2012, which are being deferred and amortized to interest expense and other financing costsusing a straight-line method over the term of the amended facility. Additionally, in accordance with guidance provided by the FASB regarding themodification of revolving debt arrangements, the remaining approximately $2.8 million of unamortized deferred financing costs associated with the priorABL credit facility will continue to be amortized over the term of the Amended and Restated ABL Credit Facility.As of December 31, 2015, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $290.1million and had letters of credit outstanding of approximately $27.8 million. There were no borrowings outstanding under the Amended and Restated ABLCredit Facility as of December 31, 2015. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as ofDecember 31, 2015.127Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Nitrogen Fertilizer Partnership Credit FacilityThe Nitrogen Fertilizer Partnership credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with anuncommitted incremental facility of up to $50.0 million. No amounts were outstanding under the revolving credit facility at December 31, 2015. There is noscheduled amortization. The credit facility matures on April 13, 2016; therefore, the principal portion of the term loan is presented as current portion of long-term debt on the Consolidated Balance Sheets as of December 31, 2015. The carrying value of the Nitrogen Fertilizer Partnership's debt approximates fairvalue. The Nitrogen Fertilizer Partnership is considering capital structure and refinancing options associated with the credit facility maturity.Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing forEurodollar rate loans under the credit facility is the Eurodollar rate plus a margin of 3.50% or, for base rate loans, the prime rate plus 2.50%. Under its terms,the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of theassets of CRNF and the Nitrogen Fertilizer Partnership. At December 31, 2015 the effective rate was approximately 4.60%, inclusive of the impact of interestrate swaps discussed in Note 15 ("Derivative Financial Instruments").The credit facility requires the Nitrogen Fertilizer Partnership to maintain a minimum interest coverage ratio and a maximum leverage ratio and containscustomary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creationof liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, sale-leaseback transactions andaffiliate transactions. The credit facility provides that the Nitrogen Fertilizer Partnership can make distributions to holders of its common units provided,among other things, it is in compliance with the leverage ratio and interest coverage ratio on a pro forma basis after giving effect to any distribution and thereis no default or event of default under the credit facility. As of December 31, 2015, CRNF was in compliance with the covenants contained in the creditfacility and there were no borrowings outstanding under the credit facility.In connection with the credit facility, the Nitrogen Fertilizer Partnership incurred lender and other third-party costs of approximately $4.8 million for theyear ended December 31, 2011. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility asinterest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility.On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty theindebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. If the credit facility becomes due prior to a refinancing by the NitrogenFertilizer Partnership, CRLLC is required to pay the indebtedness pursuant to this guaranty. The Nitrogen Fertilizer Partnership's obligation to repay CRLLCfor the indebtedness will be pursuant to a promissory note ("the Note"). The terms of the Note will be mutually agreed upon by the parties, provided, the termwill be the lesser of two years or such time that the Nitrogen Fertilizer Partnership obtains third-party financing ("New Debt") of at least $125.0 million onterms acceptable to the Nitrogen Fertilizer Partnership with a term of greater than one year from the inception of the New Debt.128Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Deferred Financing CostsFor the years ended December 31, 2015, 2014 and 2013, amortization of deferred financing costs reported as interest expense and other financing coststotaled approximately $2.8 million, $2.8 million and $2.9 million, respectively.Estimated amortization of deferred financing costs is as follows: Year Ending December 31,DeferredFinancing (in millions)2016$2.220171.820180.920190.920200.9Thereafter1.7 $8.4Capital Lease ObligationsThe Refining Partnership maintains two leases, accounted for as a capital lease and a finance obligation, related to the Magellan Pipeline Terminals, L.P.("Magellan Pipeline") and Excel Pipeline LLC ("Excel Pipeline"). The underlying assets and related depreciation were included in property, plant andequipment. 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 has166 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. Thelease has 165 months remaining and will expire in September 2029. As of December 31, 2015, the outstanding obligation associated with these arrangementstotaled approximately $48.5 million, of which $46.9 million is included in long-term liabilities and $1.6 million is included in current liabilities in theConsolidated Balance Sheets.Future payments required under capital lease at December 31, 2015 are as follows:Year Ending December 31,Capital Lease (in millions)2016$6.420176.520186.520196.520206.52021 and thereafter57.2Total future payments89.6Less: amount representing interest41.1Present value of future minimum payments48.5Less: current portion1.6Long-term portion$46.9129Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(10) DividendsOn January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Dividends are subject to change at the discretion ofthe board of directors. The Company began paying regular quarterly dividends in the second quarter of 2013. Additionally, the Company declared and paidone special cash dividend during the year ended December 31, 2014.The following is a summary of the quarterly and special dividends paid to stockholders during the years ended December 31, 2015 and 2014: December 31, 2014 March 31, 2015 June 30, 2015 September 30, 2015 Total Dividends Paid in 2015 (in millions, except per share data)Dividend typeQuarterly Quarterly Quarterly Quarterly Amount paid to IEP$35.6 $35.6 $35.6 $35.6 $142.4Amounts paid to public stockholders7.8 7.8 7.8 7.8 31.3Total amount paid$43.4 $43.4 $43.4 $43.4 $173.7Per common share$0.50 $0.50 $0.50 $0.50 $2.00Shares outstanding86.8 86.8 86.8 86.8 December 31, 2013 March 31, 2014 June 30, 2014 July 17, 2014 September 30, 2014 Total DividendsPaid in 2014 (in millions, except per share data)Dividend typeQuarterly Quarterly Quarterly Special Quarterly Amount paid to IEP$53.4 $53.4 $53.4 $142.4 $53.4 $356.0Amounts paid to publicstockholders11.7 11.7 11.7 31.3 11.7 78.2Total amount paid$65.1 $65.1 $65.1 $173.7 $65.1 $434.2Per common share$0.75 $0.75 $0.75 $2.00 $0.75 $5.00Shares outstanding86.8 86.8 86.8 86.8 86.8 (11) Earnings Per ShareThe computations of the basic and diluted earnings per share for the years ended December 31, 2015, 2014 and 2013 are as follows: For the Year Ended December 31, 2015 2014 2013 (in millions, except per share data)Net income attributable to CVR Energy stockholders$169.6 $173.9 $370.7 Weighted-average shares of common stock outstanding - Basic86.8 86.8 86.8Weighted-average shares of common stock outstanding - Diluted86.8 86.8 86.8 Basic earnings per share$1.95 $2.00 $4.27Diluted earnings per share$1.95 $2.00 $4.27There were no dilutive awards outstanding during the years ended December 31, 2015, 2014 and 2013 as all unvested awards under the LTIP wereliability-classified awards. See Note 3 ("Share-Based Compensation").130Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(12) Benefit PlansCVR sponsors and administers two defined-contribution 401(k) plans, the CVR Energy 401(k) Plan and the CVR Energy 401(k) Plan for RepresentedEmployees (the "Plans"), in which CVR employees may participate. Participants in the Plans may elect to contribute a designated percentage of their eligiblecompensation in accordance with the Plans, subject to statutory limits. CVR provides a matching contribution of 100% of the first 6% of eligiblecompensation contributed by participants. Contributions to the represented plan are determined in accordance with provisions of negotiated labor contracts.Participants in both Plans are immediately vested in their individual contributions. Both Plans provide for a three-year vesting schedule for CVR's matchingcontributions and contain a provision to count service with predecessor organizations. CVR's contributions under the Plans were approximately $7.3 million,$6.6 million and $6.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.(13) Commitments and ContingenciesThe minimum required payments for CVR's operating lease agreements and unconditional purchase obligations are as follows:Year Ending December 31,OperatingLeases UnconditionalPurchaseObligations(1) (in millions)2016$8.0 $141.020175.5 125.620183.9 124.320192.1 123.520201.5 107.8Thereafter2.5 727.4 $23.5 $1,349.6_______________________________________(1)This amount includes approximately $781.5 million payable ratably over fifteen years pursuant to petroleum transportation service agreementsbetween Coffeyville Resources Refining Marketing, LLC ("CRRM") and each of TransCanada Keystone Pipeline Limited Partnership andTransCanada Keystone Pipeline, LP (together "TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar andthe U.S. dollar as of December 31, 2015, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day ofcrude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. CRRM began receivingcrude oil under the agreements in the first quarter of 2011.CVR leases various equipment, including railcars and real properties, under long-term operating leases expiring at various dates. For the years endedDecember 31, 2015, 2014 and 2013, lease expense totaled approximately $8.7 million, $9.3 million and $9.4 million, respectively. The lease agreementshave various remaining terms. Some agreements are renewable, at CVR's option, for additional periods. It is expected, in the ordinary course of business, thatleases will be renewed or replaced as they expire.Additionally, in the normal course of business, the Company has long-term commitments to purchase oxygen, nitrogen, electricity, storage capacity andpipeline transportation services. For the years ended December 31, 2015, 2014 and 2013, total expense of $135.9 million, $137.8 million and $126.1 million,respectively, was incurred related to long-term commitments.Crude Oil Supply AgreementOn August 31, 2012, CRRM and Vitol Inc. ("Vitol"), entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "VitolAgreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce theRefining Partnership's inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms(each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any RenewalTerm. The Vitol Agreement currently extends through December 31, 2016.131Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)LitigationFrom time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described belowunder, "Environmental, Health, and Safety ("EHS") Matters." Liabilities related to such litigation are recognized when the related costs are probable and canbe reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice oflegal counsel, and other information and events pertaining to a particular case. It is possible that management's estimates of the outcomes will change withinthe next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any otherlitigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance thatmanagement's beliefs or opinions with respect to liability for potential litigation matters will prove to be accurate.Proxy MattersOn June 21, 2012, Goldman, Sachs & Co. ("GS") filed suit against CVR in state court in New York, alleging that CVR failed to pay GS fees allegedly dueto GS by CVR pursuant to an engagement letter dated March 21, 2012, which according to the allegations set forth in the complaint, provided that GS wasengaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock, made by Carl C. Icahn and certain of hisaffiliates. On September 8, 2014, the court (in its decision granting GS's motion for summary judgment against CVR) directed the court clerk to enterjudgment against CVR in the amount of approximately $22.6 million. CVR filed its notice of appeal on October 3, 2014. On November 24, 2014, CVR paidthe judgment to GS, subject to a right of refund if it is successful on appeal. In October 2015, CVR entered into a settlement agreement with GS pursuant towhich (i) CVR received settlement proceeds, (ii) the parties executed a mutual release and (iii) CVR’s appeal has been dismissed. The settlement did not havea material effect on the consolidated financial statements.On August 10, 2012, Deutsche Bank ("DB") filed suit against CVR in state court in New York, alleging that CVR failed to pay DB fees allegedly due toDB by CVR pursuant to an engagement letter dated March 23, 2012, which according to the allegations set forth in the complaint, provided that DB wasengaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock made by Carl C. Icahn and certain of hisaffiliates. On September 8, 2014, the court (in its decision granting DB's motion for summary judgment against CVR) directed the court clerk to enterjudgment against CVR in the amount of approximately $22.7 million. CVR filed its notice of appeal on October 3, 2014. On October 27, 2014, CVR paid thejudgment to DB, subject to a right of refund if it is successful on appeal. In October 2015, CVR entered into a settlement agreement with DB pursuant towhich (i) CVR received settlement proceeds, (ii) the parties executed a mutual release and (iii) CVR’s appeal has been dismissed. The settlement did not havea material effect on the consolidated financial statements.Rentech Nitrogen Mergers LitigationOn August 29, 2015, Mike Mustard, a purported unitholder of Rentech Nitrogen, filed a class action complaint on behalf of the public unitholders ofRentech Nitrogen against Rentech Nitrogen, Rentech Nitrogen GP, Rentech Nitrogen Holdings, Inc., Rentech, Inc., CVR Partners, DSHC, LLC, Merger Sub 1and Merger Sub 2, and the members of the board of directors of Rentech Nitrogen GP (the "Rentech Nitrogen Board"), in the Court of Chancery of the State ofDelaware (the "Mustard Lawsuit"). The Mustard Lawsuit alleges, among other things, that the consideration offered by CVR Partners is unfair and inadequateand that, by pursuing a transaction that is the result of an allegedly conflicted and unfair process, certain of the defendants have breached their duties owed tothe unitholders of Rentech Nitrogen, and are engaging in self-dealing. Specifically, the lawsuit alleges that the director defendants: (i) failed to take steps tomaximize the value of Rentech Nitrogen to its public shareholders, (ii) failed to properly value Rentech Nitrogen, and (iii) ignored or did not protect againstthe numerous conflicts of interest arising out of the proposed transaction. The Mustard Lawsuit also alleges that Rentech Nitrogen, Rentech Nitrogen GP,Rentech Nitrogen Holdings, Inc., Rentech, Inc., CVR Partners, DSHC, LLC, Merger Sub 1 and Merger Sub 2 aided and abetted the director defendants in theirpurported breach of fiduciary duties.On October 6, 2015, Jesse Sloan, a purported unitholder of Rentech Nitrogen, filed a class action complaint on behalf of the public unitholders ofRentech Nitrogen against Rentech Nitrogen, Rentech Nitrogen GP, CVR Partners, Merger Sub 1 and Merger Sub 2, and the members of the Rentech NitrogenBoard, in the United States District Court for the Central District of California (the "Sloan Lawsuit"). The Sloan Lawsuit alleges, among other things, that theattempted sale of Rentech Nitrogen to132Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)CVR Partners was conducted by means of an unfair process and for an unfair price. Specifically, the lawsuit alleges that (i) Rentech Nitrogen GP and theRentech Nitrogen Board breached their obligations under the partnership agreement and their implied duty of good faith and fair dealing by causing RentechNitrogen to enter into the merger agreement and failing to disclose material information to unitholders of Rentech Nitrogen, (ii) the Rentech Nitrogen Boardviolated fiduciary duties owed to the unitholders of Rentech Nitrogen based primarily on allegations of inadequate consideration, restrictive deal protectiondevices and improper disclosure, (iii) each of the defendants aided and abetted in the foregoing breaches described in items (i) and (ii), and (iv) RentechNitrogen and the Rentech Nitrogen Board violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 14a-9 thereunder based onimproper disclosure contained in the Registration Statement on Form S-4 (Registration No. 333-206982), which was originally filed with the SEC by CVRPartners on September 17, 2015.Among other remedies, the plaintiffs in these actions seek to enjoin the mergers and seek unspecified money damages. The lawsuits are at a preliminarystate, and the outcome of any such litigation is uncertain. An adverse ruling in these actions may cause the mergers to be delayed or not be completed, whichcould cause the Nitrogen Fertilizer Partnership not to realize some or all of the anticipated benefits of the mergers. No amounts have been recognized in theseconsolidated financial statements regarding the lawsuits.On February 1, 2016, the parties to the Mustard Lawsuit and the Sloan Lawsuit entered into a memorandum of understanding ("MOU") providing for theproposed settlement of the lawsuits. While the defendants believe that no supplemental disclosure is required under applicable laws, in order to avoid theburden and expense of further litigation, they have agreed, pursuant to the terms of the MOU, to make certain supplemental disclosures related to theproposed mergers. The MOU contemplates that the parties will enter into a stipulation of settlement. The stipulation of settlement will be subject tocustomary conditions, including court approval following notice to Rentech Nitrogen's unitholders. In the event that the parties enter into a stipulation ofsettlement, a hearing will be scheduled at which the United States District Court for the Central District of California (the "Court") will consider the fairness,reasonableness and adequacy of the proposed settlement. If the proposed settlement is finally approved by the Court, it will resolve and release all claims byunitholders of Rentech Nitrogen challenging any aspect of the proposed mergers, the merger agreement and any disclosure made in connection therewith,including in the prospectus and definitive proxy statement, pursuant to terms that will be disclosed to such unitholders prior to final approval of the proposedsettlement. In addition, in connection with the proposed settlement, the parties contemplate that plaintiffs' counsel will file a petition in the Court for anaward of attorneys' fees and expenses to be paid by Rentech Nitrogen or its successor. The proposed settlement is also contingent upon, among other things,the mergers becoming effective under Delaware law. There can be no assurance that the Court will approve the proposed settlement contemplated by theMOU. In the event that the proposed settlement is not approved and such conditions are not satisfied, the defendants will continue to vigorously defendagainst the allegations in the lawsuits.Property Tax MatterCRNF received a ten-year property tax abatement from Montgomery County, Kansas (the "County") in connection with the construction of the nitrogenfertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the County reclassified and reassessed CRNF'snitrogen fertilizer plant for property tax purposes. The reclassification and reassessment resulted in an increase in CRNF's annual property tax expense by anaverage of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year endedDecember 31, 2010, $11.4 million for the year ended December 31, 2011 and $11.3 million for the year ended December 31, 2012. CRNF protested theclassification and resulting valuation for each of those years to the Kansas Board of Tax Appeals ("BOTA"), followed by an appeal to the Kansas Court ofAppeals. However, CRNF fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2008 through 2012. TheKansas Court of Appeals, in a memorandum opinion dated August 9, 2013, reversed the BOTA decision in part and remanded the case to BOTA, instructingBOTA to classify each asset on an asset by asset basis instead of making a broad determination that the entire plant was real property as BOTA did originally.The County filed a motion for rehearing with the Kansas Court of Appeals and a petition for review with the Kansas Supreme Court, both of which have beendenied.In March 2015, BOTA concluded that based upon an asset by asset determination, a substantial majority of the assets in dispute will be classified aspersonal property for the 2008 tax year. CRNF and the County next will submit evidence of valuation to BOTA with respect to the real property, followingwhich, BOTA will issue its final decision. No amounts have been received or recognized in these consolidated financial statements related to the 2008property tax matter or BOTA's decision.133Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)On February 25, 2013, the County and CRNF agreed to a settlement for tax years 2009 through 2012, which has lowered and will lower CRNF's propertytaxes by about $10.7 million per year (as compared to the 2012 tax year) for tax years 2013 to 2016 based on current mill levy rates. In addition, thesettlement provides the County will support CRNF's application before BOTA for a ten-year tax exemption for the UAN expansion. Finally, the settlementprovides that CRNF will continue its appeal of the 2008 reclassification and reassessment discussed above.SEC MatterThe SEC is conducting an investigation in connection with the Company's disclosures following the announcement of a tender offer for the Company'sstock initiated in February 2012. The Company is cooperating with the SEC and has produced, at the SEC's request, documents pertaining to the tender offerand the Company's disclosures.Flood, Crude Oil Discharge and InsuranceCrude oil was discharged from the Coffeyville refinery on July 1, 2007, due to the short amount of time available to shutdown and secure the refinery inpreparation for the flood that occurred on June 30, 2007. On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf ofthe EPA seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard's claim foroversight costs. On September 23, 2011, the United States Department of Justice ("DOJ"), acting on behalf of the EPA and the United States Coast Guard, filedsuit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with theClean Air Act's Risk Management Program ("RMP"), the Clean Water Act ("CWA") and the OPA. CRRM reached an agreement with the DOJ resolving itsclaims under CWA and OPA. The agreement was memorialized in a Consent Decree that was filed with and approved by the Court on February 12, 2013 andMarch 25, 2013, respectively (the "2013 Consent Decree"). On April 19, 2013, CRRM paid a civil penalty (including accrued interest) in the amount of $0.6million related to the CWA claims and reimbursed the Coast Guard for oversight costs under OPA in the amount of $1.7 million. The 2013 Consent Decreealso requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training,the majority of which have already been completed.The parties also reached an agreement to settle DOJ's claims related to alleged non-compliance with RMP. The agreement was memorialized in a separateconsent decree that was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively, and provided for a civil penalty of $0.3million. On July 29, 2013, CRRM paid the civil penalty related to the RMP claims. In 2015, CRRM continued to implement the recommendations of severalaudits required by the RMP Consent Decree, which were related to compliance with RMP requirements.CRRM sought insurance coverage for the crude oil release and for the ultimate costs for remediation and third-party property damage claims. On July 10,2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company's environmental insurancecarriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights undervarious policy exclusions and limitations and cited potential coverage defenses. The Court issued summary judgment opinions that eliminated the majorityof the insurance defendants' reservations and defenses. CRRM has received $25.0 million of insurance proceeds under its primary environmental liabilityinsurance policy, which constitutes full payment of the primary pollution liability policy limit. During the second quarter of 2015, CRRM entered into asettlement agreement and release with the insurance carriers involved in the lawsuit, pursuant to which (i) CRRM received settlement proceeds ofapproximately $31.3 million, (ii) the parties mutually released each other from all claims relating to the flood and crude oil discharge and (iii) all pendingappeals have been dismissed. Of the settlement proceeds received, $27.3 million were recorded as a flood insurance recovery in the Consolidated Statementsof Operations for the year ended December 31, 2015. The remaining $4.0 million of settlement proceeds reduced CVR Refining's $4.0 million receivablerelated to this matter, which was included in other assets on the Consolidated Balance Sheets as of December 31, 2014.Environmental, Health, and Safety ("EHS") MattersThe petroleum and nitrogen fertilizer businesses are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related toEHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently availablefacts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potentialrecoveries.134Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)CRRM, CRNF, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Wynnewood Refining Company, LLC ("WRC") and Coffeyville ResourcesTerminal ("CRT") own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution andnitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT, WRC and CRT have exposure to potential EHS liabilities related to past and present EHSconditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservationand Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These personsinclude the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when therelease 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 ofinvestigating and remediating the release of hazardous substances. Similarly, the OPA generally subjects owners and operators of facilities to strict, joint andseveral liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into thewaters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.CRRM, CRNF, CRCT, WRC and CRT are subject to extensive and frequently changing federal, state and local, environmental and health and safetylaws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, thestorage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. Theultimate impact of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that the Company'soperations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are undergovernmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.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 RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-20and Docket No. VII-95-H-11, respectively). WRC and the Oklahoma Department of Environmental Quality ("ODEQ") have entered into a Consent Order(Case No. 15-056) to resolve certain legacy environmental issues related to historical groundwater contamination and the operation of a wastewaterconveyance. As of December 31, 2015 and 2014, environmental accruals of approximately $3.6 million and $1.1 million, respectively, were reflected in theConsolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders andthe ODEQ Consent Order, for which approximately $2.0 million and $0.2 million, respectively, are included in other current liabilities. Accruals weredetermined based on an estimate of payment costs through 2026, for which the scope of remediation was arranged with the EPA and ODEQ, and werediscounted at the appropriate risk free rates at December 31, 2015 and 2014, respectively. The accruals include estimated closure and post-closure costs ofapproximately $0.4 million and $0.9 million for two landfills at December 31, 2015 and 2014, respectively. The estimated future payments for these requiredobligations are as follows:Year Ending December 31,Amount (in millions)2016$2.020170.520180.520190.120200.1Thereafter0.5Undiscounted total3.7Less amounts representing interest at 1.87%0.1Accrued environmental liabilities at December 31, 2015$3.6Management 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.135Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Mobile Source Air Toxic II EmissionsIn 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires the reduction of benzene in gasoline by 2011. The MSAT IIprojects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. The projects were completed at a total cost ofapproximately $48.3 million and $89.0 million, excluding capitalized interest, by CRRM and WRC, respectively.Tier 3 Motor Vehicle Emission and Fuel StandardsIn April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which will require that gasoline contain no more than tenparts per million of sulfur on an annual average basis. Refineries must be in compliance with the more stringent emission standards by January 1, 2017;however, compliance with the rule is extended until January 1, 2020 for approved small volume refineries and small refiners. In March 2015, the EPAapproved the Wynnewood refinery's application requesting "small volume refinery" status; therefore, its compliance deadline is January 1, 2020. It is notanticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.Renewable Fuel StandardsCVR Refining is subject to the Renewable Fuel Standard ("RFS") which requires refiners to either blend "renewable fuels" in with their transportationfuels or purchase renewable fuel credits, known as RINs in lieu of blending. Due to mandates in the RFS requiring increasing volumes of renewable fuels toreplace petroleum products in the U.S. transportation fuel market, there may be a decrease in demand for petroleum products. Beginning in 2011, theCoffeyville refinery was required to blend renewable fuels into its transportation fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinerywas subject to the RFS for the first time. CVR Refining is not able to blend the substantial majority of its transportation fuels and has to purchase RINs on theopen market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS.The cost of RINs has been extremely volatile as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refersto the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels ofethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.On December 14, 2015, the EPA published in the Federal Register a final rule establishing the renewable fuel volume mandates for 2014, 2015 and 2016,and the biomass-based diesel mandate for 2017. The volumes included in the EPA's final rule increase each year, but are lower, with the exception of thevolumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authority to lower the volumes, but its decisionto do so has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit.The cost of RINs for the years ended December 31, 2015, 2014 and 2013 was approximately $123.9 million, $127.2 million and $180.5 million,respectively. As of December 31, 2015 and 2014, CVR Refining's biofuel blending obligation was approximately $9.5 million and $52.3 million,respectively, which is recorded in other current liabilities in the Consolidated Balance Sheets. The price of RINs has been extremely volatile and hasincreased over the last year. The future cost of RINs for the petroleum business is difficult to estimate. Additionally, the cost of RINs is dependent upon avariety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, themix of the petroleum business' petroleum products, as well as the fuel blending performed at its refineries and downstream terminals, all of which can varysignificantly from period to period.Coffeyville Second Consent DecreeIn March 2004, CRRM and CRT entered into a Consent Decree (the "2004 Consent Decree") with the EPA and the Kansas Department of Health andEnvironment (the "KDHE") to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.'s prior ownership andoperation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to installcontrols to reduce emissions of sulfur dioxide ("SO2"), nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities.136Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)In March 2012, CRRM entered into a second consent decree (the "Second Consent Decree") with the EPA and KDHE, which replaced the 2004 ConsentDecree (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second ConsentDecree was entered by the U.S. District Court for the District of Kansas on April 19, 2012. The Second Consent Decree gave CRRM more time to install theFCCU 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 alleged industry-wide non-compliance with four"marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The NationalPetroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the U.S. refining capacity) entering into consent decreesrequiring the payment of civil penalties and the installation of air pollution control equipment and enhanced operating procedures. Under the SecondConsent Decree, CRRM was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. Theremaining costs of complying with the Second Consent Decree are expected to be approximately $44.0 million. Additional incremental capital expendituresassociated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over aseveral year timeframe.CRRM has entered into an agreement with the EPA and KDHE to modify provisions in the Second Consent Decree relating to the installation of controlsto reduce air emissions of sulfur dioxide from the refinery's FCCU. Pursuant to the terms of the modification, CRRM will be permitted to use alternativemeans of control to those currently specified in the Second Consent Decree provided it can meet the limits specified in the modification. In consideration forthe EPA and KDHE's agreement to permit CRRM to use alternative controls, CRRM will pay higher stipulated penalties if it fails to meet the SO2 limits and,if it elects to install the original controls, will have to take additional steps to avoid negative impacts to the Verdigris River associated with the originalcontrols. The modification has been signed by CRRM, the EPA and KDHE, and on February 10, 2016, the modification was lodged with the United StatesDistrict Court for the District of Kansas. The modification is subject to public notice and comment and, ultimately, approval by the court.Wynnewood Clean Air Act ComplianceWRC entered into a Consent Order with ODEQ in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses certainhistoric Clean Air Act compliance issues related to the operations of the prior owner. 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. A substantial portionof the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be $3.0million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in theODEQ order.RCRA Compliance MattersIn January 2014, the EPA issued an inspection report to the Wynnewood refinery related to a RCRA compliance evaluation inspection conducted inMarch 2013. In February 2014, ODEQ notified WRC that it concurred with the EPA's inspection findings and would be pursuing enforcement. WRC andODEQ entered into a Consent Order in June 2015 resolving all alleged non-compliance associated with the RCRA compliance evaluation inspection, as wellas issues related to possible soil and groundwater contamination associated with the prior owner's operation of the refinery. The Consent Order requires WRCto take certain corrective actions, including specified groundwater remediation and monitoring measures pursuant to a work plan to be approved by ODEQ.CVR Refining does not anticipate that the costs of complying with the Consent Order will be material.Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the years ended December 31,2015, 2014 and 2013, capital expenditures were approximately $35.7 million, $100.6 million and $111.3 million, respectively, and were incurred to improvethe environmental compliance and efficiency of the operations.CRRM, CRNF, CRCT, WRC and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurancethat 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, financialcondition, or results of operations.137Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Wynnewood Refinery IncidentOn September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit during startup after a short outage as part of the turnaroundprocess. Two employees were fatally injured. Damage at the refinery was limited to the boiler. Additionally, there has been no evidence of environmentalimpact. The refinery was in the final stages of shutdown for turnaround maintenance at the time of the incident. The petroleum business completed an internalinvestigation of the incident and cooperated with OSHA in its investigation. OSHA also conducted a general inspection of the facility during the boilerincident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its SevereViolators Enforcement Program ("SVEP"). WRC is vigorously contesting the citations and OSHA's placement of WRC in the SVEP. Any penalties associatedwith OSHA's citations are not expected to have a material adverse effect on the consolidated financial statements. In addition to the above, the spouses of thetwo employees fatally injured have filed a civil lawsuit against CVR Refining and CVR Energy in Fort Bend County, Texas. The companies will vigorouslydefend the suit. It is currently too early to assess a potential outcome in the matter.Affiliate Pension ObligationsMr. Icahn, through certain affiliates, owns approximately 82% of the Company’s capital stock. Applicable pension and tax laws make each member of a"controlled group" of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable forcertain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well asliability for any unfunded liabilities that may exist at the time the plan is terminated. In addition, the failure to pay these pension obligations when due mayresult in the creation of liens in favor of the pension plan or the Pension Benefit Guaranty Corporation ("PBGC") against the assets of each member of thecontrolled group.As a result of the more than 80% ownership interest in CVR Energy by Mr. Icahn's affiliates, the Company is subject to the pension liabilities of allentities in which Mr. Icahn has a direct or indirect ownership interest of at least 80%. Two such entities, ACF Industries LLC ("ACF") and Federal-Mogul, arethe sponsors of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, asamended by the Pension Protection Act of 2006, for these plans have been met as of December 31, 2015. If the ACF and Federal-Mogul plans werevoluntarily terminated, they would be collectively underfunded by approximately $589.2 million and $473.8 million as of December 31, 2015 and 2014,respectively. These results are based on the most recent information provided by Mr. Icahn's affiliates based on information from the plans' actuaries. Theseliabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used tocalculate the liability. As members of the controlled group, CVR Energy would be liable for any failure of ACF and Federal-Mogul to make ongoing pensioncontributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within thecontrolled group that includes CVR Energy may have pension plan obligations that are, or may become, underfunded, and the Company would be liable forany failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The currentunderfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain "reportable events," such as if CVREnergy were to cease to be a member of the controlled group, or if CVR Energy makes certain extraordinary dividends or stock redemptions. The obligationto report could cause the Company to seek to delay or reconsider the occurrence of such reportable events. Based on the contingent nature of potentialexposure related to these affiliate pension obligations, no liability has been recorded in the consolidated financial statements.(14) Fair Value MeasurementsASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820") established a single authoritative definition of fair value when accountingrules require the use of fair value, set out a framework for measuring fair value and required additional disclosures about fair value measurements. ASC 820clarifies that fair value is an exit price, representing the amount from the perspective of a market participant that holds the asset or owes the liability at themeasurement date.ASC 820 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market transactions involvingidentical or comparable assets, liabilities or a group of assets and liabilities such as a business), the income approach (techniques to convert future amounts toa single current amount based on market expectations about those future amounts including present value techniques and option pricing), and the costapproach (amount that would be138Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)required currently to replace the service capacity of an asset which is often referred to as a replacement cost). ASC 820 utilizes a fair value hierarchy thatprioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:•Level 1 — Quoted prices in active markets for identical assets and liabilities•Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)•Level 3 — Significant unobservable inputs (including the Company's own assumptions in determining the fair value)The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of December 31, 2015 and 2014: December 31, 2015 Level 1 Level 2 Level 3 Total (in millions)Location and Description Cash equivalents$15.7 $— $— $15.7Other current assets (investments)0.1 — — 0.1Other current assets (other derivative agreements)— 44.7 — 44.7Total Assets$15.8 $44.7 $— $60.5Other current liabilities (other derivative agreements)— (0.1) — (0.1)Other current liabilities (interest rate swaps)— (0.1) — (0.1)Other current liabilities (biofuel blending obligations)— (2.7) — (2.7)Total Liabilities$— $(2.9) $— $(2.9) December 31, 2014 Level 1 Level 2 Level 3 Total (in millions)Location and Description Cash equivalents$69.0 $— $— $69.0Other current assets (investments)73.9 2.7 — 76.6Other current assets (other derivative agreements)— 25.0 — 25.0Other long-term assets (other derivative agreements)— 22.3 — 22.3Total Assets$142.9 $50.0 $— $192.9Other current liabilities (interest rate swaps)— (0.8) — (0.8)Other current liabilities (biofuel blending obligations)— (49.6) — (49.6)Other long-term liabilities (interest rate swaps)— (0.2) — (0.2)Total Liabilities$— $(50.6) $— $(50.6)As of December 31, 2015 and 2014, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company's cashequivalents, investments, derivative instruments and uncommitted biofuel blending obligation. Additionally, the fair value of the Company's debt issuancesis disclosed in Note 9 ("Long-Term Debt"). The Refining Partnership's commodity derivative contracts and uncommitted biofuel blending obligation, whichuse fair value measurements and are valued using broker quoted market prices of similar instruments, are considered Level 2 inputs. The Nitrogen FertilizerPartnership has interest rate swaps that are measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swapinstruments are based on discounted cash flow models that incorporate the cash flows of the derivatives,139Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. The Company had no transfers of assets or liabilitiesbetween any of the above levels during the year ended December 31, 2015.As of December 31, 2014, the aggregate cost basis for the Company's available-for-sale securities was approximately $73.6 million following an other-than-temporary impairment of $4.7 million during the year ended December 31, 2014. During the year ended December 31, 2015, the Company receivedproceeds of $68.0 million for the sale of a portion of its investment in available-for-sale securities. The aggregate cost basis for the available-for-salesecurities sold was approximately $47.9 million. Upon the sale of the available-for-sale securities, the Company reclassified an unrealized gain of $20.1million from AOCI and recognized a realized gain in other income in the Consolidated Statements of Operations for the year ended December 31, 2015. Atthe end of the first quarter of 2015, the Company's remaining available-for-sale securities with an aggregate cost basis of approximately $25.7 million werereclassified to trading securities based on management's ability and intent with respect to the securities. In connection with the transfer to trading securities,an unrealized gain previously recorded in AOCI of $11.7 million was reclassified to other income and was reflected in the Consolidated Statements ofOperations for the year ended December 31, 2015. During the second quarter of 2015, the trading securities were sold, and the Company received proceeds of$37.8 million and recognized an additional realized gain of $0.4 million in other income for the year ended December 31, 2015. As of December 31, 2015,the Company did not hold any further investments in available-for-sale securities.During the year ended December 31, 2013, the Company received proceeds of $24.7 million for the sale of its investments in marketable securities,which were previously classified as available-for-sale and reported at fair market value using quoted market prices. The aggregate cost basis for the available-for-sale securities sold was approximately $18.6 million. Upon the sale of the available-for-sale securities, the Company reclassified the unrealized gain of$6.1 million from AOCI and recognized a realized gain in other income for the year ended December 31, 2013.(15) Derivative Financial InstrumentsGain (loss) on derivatives, net and current period settlements on derivative contracts were as follows: Year Ended December 31, 2015 2014 2013 (in millions)Current period settlement on derivative contracts$(26.0) $122.2 $6.4Gain (loss) on derivatives, net(28.6) 185.6 57.1The Refining Partnership and Nitrogen Fertilizer Partnership are subject to price fluctuations caused by supply conditions, weather, economicconditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain futureproduction, the Refining Partnership from time to time enters into various commodity derivative transactions.The Refining Partnership has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivativefinancial instrument as a hedge. The Refining Partnership 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 forGAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) onderivatives, net in the Consolidated Statements of Operations. There are no premiums paid or received at inception of the derivative contracts and uponsettlement, there is no cost recovery associated with these contracts.The Refining Partnership maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include fundsavailable for withdrawal. These funds are included in cash and cash equivalents within the Consolidated Balance Sheets. The maintenance margin balance isincluded within other current assets within the Consolidated Balance Sheets. Dependent upon the position of the open commodity derivatives, the amountsare accounted for as other current assets or other current liabilities within the Consolidated Balance Sheets. From time to time, the Refining Partnership maybe required to deposit additional funds into this margin account. There were no open commodity positions as of December 31, 2015 or 2014. For the yearsended December 31, 2015, 2014 and 2013, the Company recognized net gains of $3.2 million and $0.3 million and a net loss of $2.9 million, respectively,which are recorded in gain (loss) on derivatives, net in the Consolidated Statements of Operations.140Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Commodity SwapsThe Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, the RefiningPartnership may enter into price and basis swaps in order to fix the price on a portion of its commodity purchases and product sales. The physical volumes arenot exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheetswith changes in fair value currently recognized in the Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets(Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At December 31, 2015and 2014, the Refining Partnership had open commodity hedging instruments consisting of 2.5 million and 9.1 million barrels of crack spreads, respectively,primarily to fix the margin on a portion of its future gasoline and distillate production. Additionally, at December 31, 2015, the Refining Partnership hadopen commodity hedging instruments consisting of 1.4 million barrels primarily to fix the price on a portion of its future crude oil purchases or the basis on aportion of its future product sales. The fair value of the outstanding contracts at December 31, 2015 was a net unrealized gain of $44.6 million, of which$44.7 million is included in current assets and $0.1 million is included in other current liabilities. The fair value of the outstanding contracts at December 31,2014 was a net unrealized gain of $47.3 million, of which $25.0 million is included in current assets and $22.3 million is included in other long-term assets.For the years ended December 31, 2015, 2014 and 2013, the Refining Partnership recognized a net loss of $36.4 million and net gains of $187.4 million and$60.1 million, respectively, which are recorded in gain (loss) on derivatives, net in the Consolidated Statements of Operations.Nitrogen Fertilizer Partnership Interest Rate SwapsCRNF has two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogenfertilizer business' $125.0 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements,which commenced on August 12, 2011 and expired on February 12, 2016, totals $62.5 million (split evenly between the two agreements). Under the terms ofthe interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three-month LIBOR and pay a fixed rate of 1.94%.Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three-month LIBOR and pay afixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest ofapproximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit facility. The agreements weredesignated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of AOCI, andwill be reclassified into interest expense when the interest rate swap transaction affects earnings. Any ineffective portion of the gain or loss will be recognizedimmediately in interest expense on the Consolidated Statements of Operations.The realized loss on the interest rate swap re-classed from AOCI into interest expense and other financing costs on the Consolidated Statements ofOperations was $1.1 million for each of the years ended December 31, 2015, 2014 and 2013. For the years ended December 31, 2015, 2014 and 2013, theNitrogen Fertilizer Partnership recognized a decrease in the fair value of the interest rate swap agreements of $0.1 million, $0.2 million and $0.2 million,respectively, which was unrealized in AOCI.Counterparty Credit RiskThe Refining Partnership's exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed toconcentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. The RefiningPartnership manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades tomandatory margin requirements until the contract settles. The Refining Partnership also monitors the creditworthiness of its commodity swap counterpartiesand assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuationadjustment to the fair value of the commodity swaps recorded in the Consolidated Balance Sheets. As of December 31, 2015, the counterparty credit riskadjustment was not material to the consolidated financial statements. Additionally, the Refining Partnership does not require any collateral to supportcommodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable tothe same party, which mitigates the risk associated with nonperformance.141Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)Offsetting Assets and LiabilitiesThe commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number ofcounterparties for which the Refining Partnership has entered into agreements governing the nature of the derivative transactions. Each of the counterpartyagreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed bythe Refining Partnership. As a result of the right to setoff, the Refining Partnership's recognized assets and liabilities associated with the outstandingderivative positions have been presented net in the Consolidated Balance Sheets. The interest rate swap agreements held by the Nitrogen FertilizerPartnership also provide for the right to setoff. However, as the interest rate swaps are in a liability position, there are no amounts offset in the ConsolidatedBalance Sheets as of December 31, 2015 and 2014. In accordance with guidance issued by the FASB related to "Disclosures about Offsetting Assets andLiabilities," the tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Consolidated BalanceSheets for the various types of open derivative positions at the Refining Partnership.The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2015 are recorded as current assets and current liabilitiesin prepaid expenses and other current assets and other current liabilities, respectively, in the Consolidated Balance Sheets as follows: As of December 31, 2015DescriptionGross Current Assets GrossAmountsOffset NetCurrent Assets Presented CashCollateral Not Offset NetAmount (in millions)Commodity Swaps$44.8 $(0.1) $44.7 $— $44.7Total$44.8 $(0.1) $44.7 $— $44.7 As of December 31, 2015DescriptionGross CurrentLiabilities GrossAmountsOffset NetCurrentLiabilities Presented CashCollateral Not Offset NetAmount (in millions)Commodity Swaps$0.1 $— $0.1 $— $0.1Total$0.1 $— $0.1 $— $0.1The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2014 are recorded as current assets and non-currentassets in prepaid expenses and other current assets and other long-term assets, respectively, in the Consolidated Balance Sheets as follows: As of December 31, 2014DescriptionGross Current Assets GrossAmountsOffset NetCurrent Assets Presented CashCollateral Not Offset NetAmount (in millions)Commodity Swaps$25.3 $(0.3) $25.0 $— $25.0Total$25.3 $(0.3) $25.0 $— $25.0 As of December 31, 2014DescriptionGross Non-CurrentAssets GrossAmountsOffset NetNon-CurrentAssets Presented CashCollateral Not Offset NetAmount (in millions)Commodity Swaps$22.3 $— $22.3 $— $22.3Total$22.3 $— $22.3 $— $22.3142Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(16) Related Party TransactionsIn May 2012, IEP announced that it had acquired control of CVR pursuant to a tender offer to purchase all of the issued and outstanding shares of theCompany's common stock. As of December 31, 2015, IEP owned approximately 82% of all common shares outstanding. See Note 1 ("Organization andHistory of the Company") for additional discussion.American Railcar EntitiesFrom March 2009 until June 2013, the Company, through the Nitrogen Fertilizer Partnership, leased 199 railcars from American Railcar Leasing LLC("ARL"), a company controlled by IEP, the Company's majority stockholder. On June 13, 2013, the Nitrogen Fertilizer Partnership purchased the railcarsunder the lease from ARL for approximately $5.0 million. For the year ended December 31, 2013, rent expense of $0.4 million was recorded related to thisagreement and was included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.In 2014, the Nitrogen Fertilizer Partnership purchased 50 new UAN railcars from American Railcar Industries, Inc. ("ARI"), an affiliate of IEP, forapproximately $6.7 million and 12 used UAN railcars from ARL for approximately $1.1 million. Also, ARI performed railcar maintenance for the NitrogenFertilizer Partnership, and the expenses associated with this maintenance were approximately $50,000 for the year ended December 31, 2014.International Truck PurchaseDuring the year ended December 31, 2013, the Refining Partnership purchased seven trucks from a subsidiary of Navistar International Corporation forapproximately $0.8 million.Tax Allocation AgreementCVR is a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of IEP, and has entered into a Tax Allocation Agreement.Refer to Note 8 ("Income Taxes") for a discussion of related party transactions under the Tax Allocation Agreement.Insight Portfolio GroupInsight Portfolio Group LLC is an entity formed and controlled by Mr. Icahn in order to maximize the potential buying power of a group of entities withwhich Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates.CVR Energy was a member of the buying group in 2012. In January 2013, CVR Energy acquired a minority equity interest in Insight Portfolio Group andagreed to pay a portion of Insight Portfolio Group's operating expenses in 2013. The Company paid Insight Portfolio Group approximately $0.1 million, $0.4million and $0.1 million during the years ended December 31, 2015, 2014 and 2013, respectively. The Company may purchase a variety of goods andservices as members of the buying group at prices and terms that management believes would be more favorable than those which would be achieved on astand-alone basis.CRLLC GuarantyOn February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty theindebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. Refer to Note 9 ("Long-Term Debt") for further discussion of the guarantyterms.143Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(17) Business SegmentsThe Company measures segment profit as operating income for petroleum and nitrogen fertilizer, CVR's two reporting segments, based on the definitionsprovided in ASC Topic 280 — Segment Reporting. All operations of the segments are located within the United States.PetroleumPrincipal products of the petroleum segment are refined fuels, propane, and petroleum refining by-products, including pet coke. The petroleum segment'sCoffeyville refinery sells pet coke to the Nitrogen Fertilizer Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizerplant. For the petroleum segment, a per-ton transfer price is used to record intercompany sales on the part of the petroleum segment and correspondingintercompany cost of product sold (exclusive of depreciation and amortization) for the nitrogen fertilizer segment. The per ton transfer price paid, pursuant tothe pet coke supply agreement that became effective October 24, 2007, is based on the lesser of a pet coke price derived from the price received by thenitrogen fertilizer segment for UAN (subject to a UAN based price ceiling and floor) or a pet coke price index for pet coke. The intercompany transactions areeliminated in the other segment. Intercompany sales included in petroleum net sales were approximately $6.8 million, $8.7 million and $9.6 million for theyears ended December 31, 2015, 2014 and 2013, respectively.The petroleum segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases describedbelow under "Nitrogen Fertilizer" of approximately $11.8 million, $10.1 million and $11.4 million for the years ended December 31, 2015, 2014 and 2013,respectively. The petroleum segment recorded intercompany revenue for hydrogen sales of approximately $0.6 million for the year ended December 31,2013.Nitrogen FertilizerThe principal product of the nitrogen fertilizer segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation andamortization) for the pet coke transfer described above was approximately $6.6 million, $9.2 million and $9.8 million for the years ended December 31,2015, 2014 and 2013, respectively.Pursuant to the feedstock agreement, the Company's segments have the right to transfer hydrogen between the Coffeyville refinery and nitrogen fertilizerplant. Sales of hydrogen to the petroleum segment have been reflected as net sales for the nitrogen fertilizer segment. Receipts of hydrogen from thepetroleum segment have been reflected in cost of product sold (exclusive of depreciation and amortization) for the nitrogen fertilizer segment. For the yearsended December 31, 2015, 2014 and 2013, the net sales generated from intercompany hydrogen sales were $11.8 million, $10.1 million and $11.4 million,respectively. For the years ended December 31, 2013, the nitrogen fertilizer segment also recognized approximately $0.6 million of cost of product soldrelated to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on theconsolidated financial statements.Other SegmentThe other segment reflects intercompany eliminations, corporate cash and cash equivalents, income tax activities and other corporate activities that arenot allocated to the operating segments.144Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)The following table summarizes certain operating results and capital expenditures information by segment: Year Ended December 31, 2015 2014 2013 (in millions)Net sales Petroleum$5,161.9 $8,829.7 $8,683.5Nitrogen Fertilizer289.2 298.7 323.7Intersegment elimination(18.6) (18.9) (21.4)Total$5,432.5 $9,109.5 $8,985.8Cost of product sold (exclusive of depreciation and amortization) Petroleum$4,143.6 $8,013.4 $7,526.7Nitrogen Fertilizer65.2 72.0 58.1Intersegment elimination(18.4) (19.4) (21.6)Total$4,190.4 $8,066.0 $7,563.2Direct operating expenses (exclusive of depreciation and amortization) Petroleum$478.5 $416.0 $361.7Nitrogen Fertilizer106.1 98.9 94.1Other0.1 0.2 —Total$584.7 $515.1 $455.8Depreciation and amortization Petroleum$130.2 $122.5 $114.3Nitrogen Fertilizer28.4 27.3 25.6Other5.5 4.6 2.9Total$164.1 $154.4 $142.8Operating income Petroleum$361.7 $207.2 $603.0Nitrogen Fertilizer68.7 82.8 124.9Other(8.8) (25.7) (17.4)Total$421.6 $264.3 $710.5Capital expenditures Petroleum$194.7 $191.3 $204.5Nitrogen fertilizer17.0 21.1 43.8Other7.0 6.0 8.2Total$218.7 $218.4 $256.5145Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Year Ended December 31, 2015 2014 2013 (in millions)Total assets Petroleum$2,195.2 $2,417.8 $2,533.3Nitrogen Fertilizer536.5 578.8 593.5Other574.1 465.9 539.0Total$3,305.8 $3,462.5 $3,665.8Goodwill Petroleum$— $— $—Nitrogen Fertilizer41.0 41.0 41.0Other— — —Total$41.0 $41.0 $41.0(18) Major Customers and SuppliersSales to major customers as a percentage of the respective segment's sales were as follows: Year Ended December 31, 2015 2014 2013Petroleum Customer A14% 13% 12%Nitrogen Fertilizer Customer B10% 17% 15%Customer C14% 10% 13% 24% 27% 28%The petroleum segment obtained crude oil from one third-party supplier under a long-term supply agreement during 2015, 2014 and 2013. The crude oilpurchased from this supplier is governed by a long-term contract. Volume contracted as a percentage of the total crude oil purchases (in barrels) for each ofthe periods was as follows: Year Ended December 31, 2015 2014 2013Petroleum Supplier A61% 67% 69%146Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)(19) Selected Quarterly Financial Information (unaudited)Summarized quarterly financial data for December 31, 2015 and 2014. Year Ended December 31, 2015 Quarter First Second Third Fourth (in millions, except per share data)Net sales$1,388.9 $1,624.2 $1,408.8 $1,010.6Operating costs and expenses: Cost of product sold (exclusive of depreciation and amortization)1,073.6 1,192.2 1,076.7 847.9Direct operating expenses (exclusive of depreciation andamortization)111.4 115.4 145.8 212.1Flood insurance recovery— (27.3) — —Selling, general and administrative (exclusive of depreciation andamortization)25.3 27.2 26.1 20.4Depreciation and amortization42.0 42.5 38.7 40.9Total operating costs and expenses1,252.3 1,350.0 1,287.3 1,121.3Operating income (loss)136.6 274.2 121.5 (110.7)Other income (expense): Interest expense and other financing costs(12.7) (11.9) (11.9) (11.9)Interest income0.2 0.3 0.3 0.2Gain (loss) on derivatives, net(51.4) (12.6) 11.8 23.6Other income, net36.0 0.2 0.3 0.2Total other income (expense)(27.9) (24.0) 0.5 12.1Income (loss) before income taxes108.7 250.2 122.0 (98.6)Income tax expense (benefit)24.0 58.1 23.1 (20.7)Net income (loss)84.7 192.1 98.9 (77.9)Less: Net income (loss) attributable to noncontrolling interest29.8 90.2 41.0 (32.9)Net income (loss) attributable to CVR Energy stockholders$54.9 $101.9 $57.9 $(45.0) Basic earnings (loss) per share$0.63 $1.17 $0.67 $(0.52)Diluted earnings (loss) per share$0.63 $1.17 $0.67 $(0.52)Dividends declared per share$0.50 $0.50 $0.50 $0.50 Weighted-average common shares outstanding Basic86.8 86.8 86.8 86.8Diluted86.8 86.8 86.8 86.8147Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued) Year Ended December 31, 2014 Quarter First Second Third Fourth (in millions, except per share data)Net sales$2,447.4 $2,540.3 $2,279.9 $1,841.8Operating costs and expenses: Cost of product sold (exclusive of depreciation and amortization)2,076.9 2,189.0 2,066.7 1,733.4Direct operating expenses (exclusive of depreciation andamortization)123.4 120.1 136.8 134.7Selling, general and administrative (exclusive of depreciation andamortization)26.3 28.0 31.8 23.5Depreciation and amortization37.3 38.6 37.8 40.8Total operating costs and expenses2,263.9 2,375.7 2,273.1 1,932.4Operating income (loss)183.5 164.6 6.8 (90.6)Other income (expense): Interest expense and other financing costs(10.1) (9.3) (9.4) (11.2)Interest income0.2 0.2 0.3 0.2Gain on derivatives, net109.4 35.9 25.7 14.5Other income (expense), net0.1 (2.2) 2.1 (3.6)Total other income (expense)99.6 24.6 18.7 (0.1)Income (loss) before income taxes283.1 189.2 25.5 (90.7)Income tax expense (benefit)69.4 45.2 4.2 (21.0)Net income (loss)213.7 144.0 21.3 (69.7)Less: Net income (loss) attributable to noncontrolling interest87.0 60.3 13.4 (25.3)Net income (loss) attributable to CVR Energy stockholders$126.7 $83.7 $7.9 $(44.4) Basic earnings (loss) per share$1.46 $0.96 $0.09 $(0.51)Diluted earnings (loss) per share$1.46 $0.96 $0.09 $(0.51)Dividends declared per share$0.75 $0.75 $2.75 $0.75 Weighted-average common shares outstanding Basic86.8 86.8 86.8 86.8Diluted86.8 86.8 86.8 86.8Factors Impacting the Comparability of Quarterly Results of OperationsAs discussed in Note 2 ("Summary of Significant Accounting Policies"), the Coffeyville refinery completed the first phase of its current major scheduledturnaround in mid-November 2015 at a total cost of approximately $101.5 million. Additionally, the Coffeyville refinery incurred approximately $0.7million in turnaround costs related to the second phase scheduled to begin in late February 2016. In total, the Coffeyville refinery incurred $102.2 million ofmajor scheduled turnaround expenses for the year ended December 31, 2015, of which approximately $1.7 million, $15.6 million and $84.9 million wereincluded in the second, third and fourth quarters of 2015, respectively. These costs are included in direct operating expenses (exclusive of depreciation andamortization) in the Consolidated Statements of Operations.148Table of ContentsCVR Energy, Inc. and SubsidiariesNOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)As discussed in Note 13 ("Commitments and Contingencies"), CRRM received an insurance recovery from its environmental insurance carriers in thesecond quarter of 2015 as a result of the flood and crude oil discharge at the Coffeyville refinery on June/July 2007.As discussed in Note 7 ("Insurance Claims"), the fire at the Coffeyville refinery's isomerization unit adversely impacted production of refined products forthe petroleum business in the third quarter of 2014. Total gross repair and other costs recorded related to the incident for the year ended December 31, 2014were approximately $6.3 million and are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statementsof Operations.During the fourth quarter of 2014, the FCCU at the Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a result of theFCCU outage, crude throughput and production at the Wynnewood refinery was significantly reduced during the fourth quarter of 2014. Additionally, theRefining Partnership incurred approximately $8.5 million in costs to repair the FCCU for the year ended December 31, 2014. These costs are included indirect operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.As discussed in Note 4 ("Inventories"), the Refining Partnership recorded a lower of FIFO cost or market inventory adjustment of approximately $36.8million during the fourth quarter of 2014, which is included in cost of product sold (exclusive of depreciation and amortization) in the ConsolidatedStatements of Operations.(20) Subsequent EventsDividendOn February 17, 2016, the board of directors of the Company declared a cash dividend for the fourth quarter of 2015 to the Company's stockholders of$0.50 per share, or $43.4 million in aggregate. The dividend will be paid on March 7, 2016 to stockholders of record at the close of business on February 29,2016. IEP will receive $35.6 million in respect of its 82% ownership interest in the Company's shares.Nitrogen Fertilizer Partnership DistributionOn February 17, 2016, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the fourth quarter of2015 to the Nitrogen Fertilizer Partnership's unitholders of $0.27 per unit, or $19.7 million in aggregate. The cash distribution will be paid on March 7, 2016to unitholders of record at the close of business on February 29, 2016. The Company will receive $10.5 million in respect of its Nitrogen FertilizerPartnership common units.149Table of ContentsItem 9. Changes in and Disagreements with Accountants on Accounting and Financial DisclosureNone.Item 9A. Controls and ProceduresEvaluation of Disclosure Controls and Procedures. As of December 31, 2015, we have evaluated, under the direction of our Chief Executive Officer andChief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitationsto the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of thecontrols and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their controlobjectives. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controlsand procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under theExchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, and that such information isaccumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timelydecisions regarding required disclosure.Management's Report On Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequateinternal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control overfinancial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Underthe supervision and with the participation of management, the Company conducted an evaluation of the effectiveness of its internal control over financialreporting based on the framework in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of theTreadway Commission ("COSO"). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the Company'sinternal control over financial reporting was effective as of December 31, 2015. Our independent registered public accounting firm, that audited theconsolidated financial statements included herein under Item 8, has issued a report on the effectiveness of our internal control over financial reporting. Thisreport can be found under Item 8.Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended December 31, 2015 that has materially affected or is reasonably likely to materiallyaffect, our internal control over financial reporting.Item 9B. Other InformationNone.150Table of ContentsPART IIIItem 10. Directors, Executive Officers and Corporate GovernanceInformation required by this Item regarding our directors, executive officers and corporate governance will be included under the captions "CorporateGovernance," "Proposal 1 — Election of Directors," "Members and Nominees of the Board," "Executive Officers," "Information Concerning ExecutiveOfficers Who are Not Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Stockholder Proposals" contained in our proxy statementfor the annual meeting of our stockholders, which will be filed with the SEC, and this information is incorporated herein by reference.Item 11. Executive CompensationInformation about executive and director compensation will be included under the captions "Corporate Governance — Compensation CommitteeInterlocks and Insider Participation," "Proposal 1 — Election of Directors," "Director Compensation for 2015," "Compensation Discussion and Analysis,""Compensation Committee Report" and "Compensation of Executive Officers" contained in our proxy statement for the annual meeting of our stockholders,which will be filed with the SEC and this information is incorporated herein by reference.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder MattersInformation about security ownership of certain beneficial owners and management will be included under the captions "Compensation of ExecutiveOfficers," "Securities Ownership of Certain Beneficial Owners and Officers and Directors" and "Equity Compensation Plans" contained in our proxy statementfor the annual meeting of our stockholders, which will be filed with the SEC, and this information is incorporated herein by reference.Item 13. Certain Relationships and Related Transactions, and Director IndependenceInformation about related party transactions between CVR Energy and its directors, executive officers and 5% stockholders that occurred during the yearended December 31, 2015 will be included under the captions "Certain Relationships and Related Party Transactions" and "Corporate Governance —Director Independence" contained in our proxy statement for the annual meeting of our stockholders, which will be filed with the SEC, and this informationis incorporated herein by reference.Item 14. Principal Accounting Fees and ServicesInformation about principal accounting fees and services will be included under the captions "Proposal 2 — Ratification of Selection of IndependentRegistered Public Accounting Firm" and "Fees Paid to the Independent Registered Public Accounting Firm" contained in our proxy statement for the annualmeeting of our stockholders, which will be filed with the SEC and this information is incorporated herein by reference.151Table of ContentsPART IVItem 15. Exhibits, Financial Statement Schedules(a)(1) Financial StatementsSee "Index to Consolidated Financial Statements" Contained in Part II, Item 8 of this Report.(a)(2) Financial Statement SchedulesAll schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission (the "SEC") are notrequired under the related instructions or are inapplicable and therefore have been omitted.(a)(3) ExhibitsExhibit NumberExhibit Title2.1**#Agreement and Plan of Merger, dated as of August 9, 2015, by and among CVR Partners, LP, Lux Merger Sub 1, LLC, Lux Merger Sub2, LLC, Rentech Nitrogen Partners, L.P., and Rentech Nitrogen GP, LLC (incorporated by reference to Exhibit 2.1 to the Form 8-K filedby CVR Partners, LP on August 13, 2015 (Commission File No. 001-35120)). 2.2**Transaction Agreement among CVR Energy, Inc., IEP Energy LLC and each of the other Offeror Parties (as defined therein) dated as ofApril 18, 2012 (incorporated by reference to Exhibit 2.1 to the Company's Form 8-K filed on April 23, 2012). 3.1**Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Company'sForm 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007). 3.1.1**Certificate of Designations, Rights and Preferences setting forth the terms of the Series A Preferred Stock of CVR Energy, Inc.(incorporated by reference to Exhibit 3.1 to the Company's Form 8-K filed on January 17, 2012). 3.2**Amended and Restated Bylaws of CVR Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Form 8-K filed onJuly 20, 2011). 4.1**Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1/A,File No. 333-137588, filed on June 5, 2007). 4.2**Indenture, dated as of October 23, 2012, among CVR Refining, LLC, Coffeyville Finance Inc., the Guarantors (as defined therein) andWells Fargo Bank, National Association, as Trustee and Collateral Trustee (incorporated by reference to Exhibit 4.1 to the Company'sForm 8-K filed on October 29, 2012). 4.3**Forms of 6.500% Second Lien Senior Secured Notes due 2022 (included within the Indenture filed as Exhibit 4.2). 10.1**Amended and Restated ABL Credit Agreement, dated as of December 20, 2012, among Coffeyville Resources, LLC, CVR Refining, LP,CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville ResourcesCrude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood RefiningCompany, LLC and certain of their affiliates, the lenders from time to time party thereto, Wells Fargo Bank, National Association, ascollateral agent and administrative agent (incorporated by reference to Exhibit 1.1 to the Company's Form 8-K filed on December 27,2012). 10.2**Amended and Restated ABL Pledge and Security Agreement, dated as of December 20, 2012, among CVR Refining, LP, CVRRefining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources CrudeTransportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood RefiningCompany, LLC and certain of their affiliates, and Wells Fargo Bank, National Association, as collateral agent (incorporated by referenceto Exhibit 1.2 to the Company's Form 8-K filed on December 27, 2012). 10.3**Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC,CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc.,Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville ResourcesRefining & Marketing, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors,and Credit Suisse, as collateral agent (incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on February 12, 2007). 152Table of ContentsExhibit NumberExhibit Title10.4**ABL Intercreditor Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Finance Inc., DeutscheBank Trust Company Americas, as collateral agent for the ABL secured parties, Wells Fargo Bank, National Association, as collateraltrustee for the secured parties in respect of the outstanding first lien obligations, and the outstanding second lien notes and certainsubordinated liens, respectively, and the Guarantors (as defined therein) (incorporated by reference to Exhibit 1.3 to the Company'sForm 8-K filed on February 28, 2011). 10.5**First Amended and Restated Collateral Trust and Intercreditor Agreement, dated as of April 6, 2010, among Coffeyville Resources, LLC,Coffeyville Finance Inc., the other grantors from time to time party thereto, Credit Suisse AG, Cayman Islands Branch, as administrativeagent, Wells Fargo Bank, National Association, as indenture agent, J. Aron & Company, as hedging counterparty, each additional firstlien representative and Wells Fargo Bank, National Association, as collateral trustee (incorporated by reference to Exhibit 10.33 to theCompany's Form 10-K for the year ended December 31, 2011, filed on February 29, 2012). 10.6**Omnibus Amendment Agreement and Consent under the Intercreditor Agreement, dated as of April 6, 2010, by and among CoffeyvilleResources, LLC, Coffeyville Finance Inc., Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville NitrogenFertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, and certain subsidiaries of theforegoing as Guarantors, the Requisite Lenders, Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, Collateral Agentand Revolving Issuing Bank, J. Aron & Company, as a hedge counterparty and Wells Fargo Bank, National Association, as CollateralTrustee (incorporated by reference to Exhibit 1.4 to the Company's Form 8-K filed on April 12, 2010). 10.7**Credit and Guaranty Agreement, dated as of April 13, 2011, among Coffeyville Resources Nitrogen Fertilizers, LLC, CVR Partners, LP,the lenders party thereto and Goldman Sachs Lending Partners LLC, as administrative agent and collateral agent (incorporated byreference to Exhibit 10.8 to the Company's Form 8-K filed on May 23, 2011). 10.8†**License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification PowerSystems, dated as of May 30, 1997 by and between GE Energy (USA), LLC (as successor in interest to Texaco DevelopmentCorporation) and Coffeyville Resources Nitrogen Fertilizers, LLC (as successor in interest to Farmland Industries, Inc.), as amended(incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed onApril 18, 2007). 10.9†**Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, by and between The BOC Group, Inc. (n/k/aLinde LLC) and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.6 to the Company'sRegistration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007). 10.9.1**First Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of October 31, 2008, by and betweenCoffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc. (n/k/a Linde LLC) (incorporated by reference to Exhibit 10.3 to theCompany's Form 10-Q for the quarter ended September 30, 2008, filed on November 13, 2008). 10.10†**Amended and Restated Crude Oil Supply Agreement, dated August 31, 2012, by and between Vitol Inc. and Coffeyville ResourcesRefining & Marketing, LLC (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q for the quarter ended September 30,2012, filed on November 6, 2012). 10.10.1**First Amendment to Amended and Restated Crude Oil Supply Agreement, dated as of June 8, 2015, by and between Vitol Inc. andCoffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for thequarter ended June 30, 2015, filed on July 30, 2015). 10.11†**Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, by and betweenPlains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.14 to theCompany's Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007). 10.12**Amended and Restated Electric Services Agreement dated as of August 1, 2010, by and between Coffeyville Resources NitrogenFertilizers, LLC and the City of Coffeyville, Kansas (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed onAugust 25, 2010). 10.13**++Fifth Amended and Restated Employment Agreement, dated as of December 31, 2015, by and between CVR Energy, Inc. and John J.Lipinski (incorporated by reference to Exhibit 10.18 to CVR Partners, LP's Form 10-K filed on February 18, 2016 (Commission File No.001-35120)). 10.14**++Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Robert W.Haugen (incorporated by reference to Exhibit 10.5 to the Company's Form 10-Q for the quarter ended March 31, 2011, filed on May 10,2011). 153Table of ContentsExhibit NumberExhibit Title10.14.1**++Amendment Number 1 to Third Amended and Restated Employment Agreement, dated as of December 31, 2013, by and between CVREnergy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.17.1 to the Company's Form 10-K filed on February 26,2014). 10.14.2**++Amendment Number 2 to Third Amended and Restated Employment Agreement, dated as of December 18, 2013, by and between CVREnergy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.18.2 to the Company's Form 10-K filed on February 20,2015). 10.15**++Employment Agreement, dated as of December 1, 2014, by and between CVR Energy, Inc. and Martin J. Power (incorporated byreference to Exhibit 10.19 to the Company's Form 10-K filed on February 20, 2015). 10.16**Second Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated April 13, 2011 (incorporated by referenceto Exhibit 10.7 to the Company's Form 8-K/A filed on May 23, 2011). 10.17**Amended and Restated Contribution, Conveyance and Assumption Agreement, dated as of April 7, 2011, among CoffeyvilleResources, LLC, CVR GP, LLC, Coffeyville Acquisition III LLC, CVR Special GP, LLC and CVR Partners, LP (incorporated byreference to Exhibit 10.1 to the Company's Form 8-K/A filed on May 23, 2011). 10.18**Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC andCoffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7 to the Company's Form 10-Q for the quarterended September 30, 2007, filed on December 6, 2007). 10.18.1**Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining andMarketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 to the Company'sForm 10-K for the year ended December 31, 2007, filed on March 28, 2008). 10.18.2**Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining andMarketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.1 to the Company'sForm 10-Q for the quarter ended June 30, 2008, filed on August 14, 2008). 10.19**Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011, by and between Coffeyville ResourcesRefining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.4 to theCompany's Form 8-K/A filed on May 23, 2011). 10.19.1**Amendment to Amended and Restated Feedstock and Shared Services Agreement, dated as of December 30, 2013, by and betweenCoffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference toExhibit 10.21.1 to the Company's Form 10-K filed on February 26, 2014). 10.20**Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining &Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.9 to the Company'sForm 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007). 10.21**Second Amended and Restated Services Agreement, dated as of May 4, 2012, among CVR Partners, LP, CVR GP, LLC and CVREnergy, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on August 2, 2012). 10.21.1**Amendment to Second Amended and Restated Services Agreement, dated as of February 17, 2014, among CVR Partners, LP,CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q filed on May 2, 2014). 10.22**Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc., CVR GP, LLC and CVR Partners, LP(incorporated by reference to Exhibit 10.2 to the Company's Form 8-K/A filed on May 23, 2011). 10.23**Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC andCoffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company's Form 10-Q for the quarterended September 30, 2007, filed on December 6, 2007). 10.24**Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, by and between Coffeyville Resources Refining &Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company'sForm 8-K/A filed on May 23, 2011). 154Table of ContentsExhibit NumberExhibit Title10.25**GP Services Agreement, dated as of November 29, 2011, by and between CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc.(incorporated by reference to Exhibit 10.22 to the Form 10-K for the year ended December 31, 2011, filed by CVR Partners, LP onFebruary 24, 2012 (Commission File No. 001-35120)). 10.25.1**Amendment to GP Services Agreement, dated as of June 27, 2014, by and between CVR Partners, LP, CVR GP, LLC and CVREnergy, Inc. (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q filed on August 1, 2014). 10.26**Trademark License Agreement, dated as of April 13, 2011, by and between CVR Energy, Inc. and CVR Partners, LP (incorporated byreference to Exhibit 10.9 to the Company's Form 8-K/A filed on May 23, 2011). 10.27**Lease and Operating Agreement, dated as of May 4, 2012, by and between Coffeyville Resources Terminal, LLC and CoffeyvilleResources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on August 2, 2012). 10.28**Form of Indemnification Agreement (incorporated by reference to Exhibit 10.49 to the Company's Form 10-K for the year endedDecember 31, 2008, filed on March 13, 2009). 10.29**++Amended and Restated CVR Energy, Inc. 2007 Long Term Incentive Plan, dated as of December 26, 2013 (incorporated by reference toExhibit 10.32 to the Company's Form 10-K filed on February 26, 2014). 10.29.1**++Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.33.1 to the Company's Registration Statementon Form S-1/A, File No. 333-137588, filed on June 5, 2007). 10.29.2**++Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.33.2 to the Company's Registration Statement onForm S-1/A, File No. 333-137588, filed on June 5, 2007). 10.29.3**++Form of Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.28.3 to the Company's Form 10-K for the yearended December 31, 2009, filed on March 12, 2010). 10.29.4**++Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on December 23,2011). 10.29.5**++Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on January 4,2013). 10.29.6**++Form of Incentive Unit Agreement (incorporated by reference to Exhibit 10.32.6 to the Company's Form 10-K filed on February 26,2014). 10.30**++Performance Unit Agreement, dated as of December 31, 2015, by and between CVR Energy, Inc. and John J. Lipinski (incorporated byreference to Exhibit 10.20 to CVR Partners, LP's Form 10-K filed on February 18, 2016 (Commission File No. 001-35120)). 10.31**++Other Unit Based Award Agreement, dated as of April 15, 2015, by and between CVR Energy, Inc. and Martin J. Power (incorporated byreference to Exhibit 10.3 to CVR Refining, LP's Form 10-K filed on February 19, 2016 (Commission File No. 001-35781)). 10.32**++CVR Partners, LP Long-Term Incentive Plan (adopted March 16, 2011) (incorporated by reference to Exhibit 10.1 to the Form S-8 filedby CVR Partners, LP on April 12, 2011 (Commission File No. 333-173444)). 10.32.1**++Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.4to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)). 10.32.2**++Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.5to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)). 10.32.3**++Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.38.3to the Company's Form 10-K filed on February 20, 2015). 10.33**++CVR Energy, Inc. Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LPon March 1, 2013 (Commission File No. 001-35120)). 10.34**++CVR Partners, LP Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LPon March 1, 2013 (Commission File No. 001-35120)). 10.35**Third Amended and Restated Limited Liability Company Agreement of CVR GP, LLC, dated April 13, 2011 (incorporated by referenceto Exhibit 3.4 to the Form 10-K for the year ended December 31, 2011 filed by CVR Partners, LP on February 24, 2012 (CommissionFile No. 001-35120)). 155Table of ContentsExhibit NumberExhibit Title10.36**First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, dated as of January 23, 2013 (incorporated byreference to Exhibit 3.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). 10.37**Contribution Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining Holdings, LLC and CVR RefiningHoldings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form S-1/A filed by CVR Refining, LP on January 8, 2013(Commission File No. 333-184200)). 10.38**++CVR Refining, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership's Form 8-K filed onJanuary 23, 2013 (Commission File No. 001-35781)). 10.38.1**++Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.41.1to the Company's Form 10-K filed on February 26, 2014). 10.38.2**++Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.44.2to the Company's Form 10-K filed on February 20, 2015). 10.39**Services Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc.(incorporated by reference to Exhibit 10.2 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). 10.39.1**Amendment to Services Agreement, dated as of February 17, 2014, by and among CVR Refining, LP, CVR Refining GP, LLC and CVREnergy, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on May 2, 2014). 10.39.2**Second Amendment to Services Agreement, dated as of June 27, 2014, by and among CVR Refining, LP, CVR Refining GP, LLC andCVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on August 1, 2014). 10.40**Trademark License Agreement, dated as of January 23, 2013, by and among CVR Refining, LP and CVR Energy, Inc. (incorporated byreference to Exhibit 10.3 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). 10.41**Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and among CVR Refining, LLC and CoffeyvilleResources, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by CVR Refining, LP on January 29, 2013(Commission File No. 001-35781)). 10.41.1**First Amendment to Credit Agreement, dated as of October 29, 2014, by and among CVR Refining, LLC and CoffeyvilleResources, LLC (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed October 30, 2014). 10.42**Reorganization Agreement, dated as of January 16, 2013, by and among CVR Refining, LP, CVR Refining GP, LLC, CVR RefiningHoldings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVRRefining, LP on January 23, 2013 (Commission File No. 001-35781)). 10.43**Amended and Restated Registration Rights Agreement, dated as of April 13, 2011, among CVR Partners, LP and CoffeyvilleResources, LLC (incorporated by reference to Exhibit 10.6 to the Company's Form 8-K/A filed by on May 23, 2011). 10.44**Registration Rights Agreement, dated as of January 23, 2013, by and among CVR Refining, LP, Icahn Enterprises Holdings L.P., CVRRefining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed byCVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). 10.45**Registration Rights Agreement, dated as of August 9, 2015, by and among CVR Partners, Coffeyville Resources, LLC, RentechNitrogen Holdings, Inc., and DSHC, LLC (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by CVR Partners, LP on August13, 2015 (Commission File No. 001-35120)). 10.46**Voting and Support Agreement, dated as of August 9, 2015, by and among CVR Partners, LP, Rentech, Inc., Rentech Nitrogen Holdings,Inc., and DSHC, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Partners, LP on August 13, 2015(Commission File No. 001-35120)). 10.47**Transaction Agreement, dated as of August 9, 2015, by and among CVR Partners, LP, Coffeyville Resources, LLC, Rentech, Inc.,Rentech Nitrogen Holdings, Inc., and DSHC, LLC (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by CVR Partners, LPon August 13, 2015 (Commission File No. 001-35120)). 156Table of ContentsExhibit NumberExhibit Title10.48**Transaction Agreement, dated as of August 9, 2015, by and among CVR Partners, LP, GSO Special Situations Overseas Master FundLtd., GSO Special Situations Fund LP, GSO Palmetto Opportunistic Investment Partners LP, GSO Credit-A Partners LP, Steamboat CreditOpportunities Master Fund LP, GSO Coastline Credit Partners LP, GSO Cactus Credit Opportunities Fund LP and GSO Aiguille desGrands Montets Fund II LP and GSO Capital Partners LP (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by CVRPartners, LP on August 13, 2015 (Commission File No. 001-35120)). 10.49**Commitment Letter, dated as of August 9, 2015, by and between Coffeyville Resources, LLC and CVR Partners, LP (incorporated byreference to Exhibit 10.4 to the Form 8-K filed by CVR Partners, LP on August 13, 2015 (Commission File No. 001-35120)). 21.1**List of Subsidiaries of CVR Energy, Inc. (incorporated by reference to Exhibit 21.1 to the Company's Form 10-K for the year endedDecember 31, 2012, filed on March 14, 2013). 23.1*Consent of Grant Thornton LLP. 31.1*Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer and President. 31.2*Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer and Treasurer. 32.1*Section 1350 Certification of Chief Executive Officer and President and Chief Financial Officer and Treasurer. 101*The following financial information for CVR Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2015,formatted in XBRL ("Extensible Business Reporting Language") includes: (1) Consolidated Balance Sheets, (2) ConsolidatedStatements of Operations, (3) Consolidated Statements of Comprehensive Income, (4) Consolidated Statements of Changes in Equity,(5) Consolidated Statements of Cash Flows and (6) the Notes to Consolidated Financial Statements, tagged in detail._______________________________________* Filed herewith. ** Previously filed. † Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment which has beengranted by the SEC. ++ Denotes management contract or compensatory plan or arrangement. # Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. CVR Energy hereby undertakes to furnish supplemental copies of any ofthe omitted schedules upon request by the U.S. Securities and Exchange Commission.PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporate by reference agreements as exhibits to the reports that wefile with or furnish to the SEC. The agreements are filed to provide investors with information regarding their respective terms. The agreements are notintended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in anyrepresentations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality differentfrom those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosureschedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in theagreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between theparties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants mayhave changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company's publicdisclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual stateof facts about the Company or its business or operations on the date hereof.157Table of ContentsSIGNATURESPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed onits behalf by the undersigned, thereunto duly authorized. CVR Energy, Inc. By:/s/ JOHN J. LIPINSKI Name:John J. Lipinski Title:Chief Executive Officer and PresidentDate: February 19, 2016Pursuant to the requirements of the Securities Exchange Act of 1934, this Report had been signed below by the following persons on behalf of theregistrant and in the capacity and on the dates indicated.SignatureTitleDate /s/ JOHN J. LIPINSKIChief Executive Officer, President and Director (Principal Executive Officer)February 19, 2016John J. Lipinski /s/ SUSAN M. BALLChief Financial Officer and Treasurer (Principal Financial and Accounting Officer)February 19, 2016Susan M. Ball Chairman of the Board of DirectorsFebruary 19, 2016Carl C. Icahn /s/ BOB G. ALEXANDERDirectorFebruary 19, 2016Bob G. Alexander /s/ SUNGHWAN CHODirectorFebruary 19, 2016SungHwan Cho /s/ ANDREW LANGHAMDirectorFebruary 19, 2016Andrew Langham /s/ COURTNEY MATHERDirectorFebruary 19, 2016Courtney Mather /s/ STEPHEN MONGILLODirectorFebruary 19, 2016Stephen Mongillo /s/ JAMES M. STROCKDirectorFebruary 19, 2016James M. Strock 158EXHIBIT 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Board of Directors and Stockholders of CVR Energy, Inc.We have issued our reports dated February 19, 2016, with respect to the consolidated financial statements and internal control over financial reportingincluded in the Annual Report of CVR Energy, Inc. on Form 10-K for the year ended December 31, 2015. We hereby consent to the incorporation byreference of said reports in the Registration Statements of CVR Energy, Inc. on Forms S-8 (File No. 333-146907 and File No. 333-148783)./s/ GRANT THORNTON LLPHouston, TexasFebruary 19, 2016EXHIBIT 31.1Certification of Chief Executive Officer and President Pursuant toRule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934,As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002I, John J. Lipinski, certify that:1.I have reviewed this report on Form 10-K of CVR Energy, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), forthe registrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by otherswithin those entities, particularly during the period in which this report is being prepared;b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's mostrecent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internalcontrol over financial reporting.Date: February 19, 2016By:/s/ JOHN J. LIPINSKI John J. LipinskiChief Executive Officer and PresidentEXHIBIT 31.2Certification of Chief Financial Officer and Treasurer Pursuant toRule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934,As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002I, Susan M. Ball, certify that:1.I have reviewed this report on Form 10-K of CVR Energy, Inc.;2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), forthe registrant and have:a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by otherswithin those entities, particularly during the period in which this report is being prepared;b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles;c)Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; andd)Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's mostrecent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant's internal control over financial reporting; and5.The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; andb)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internalcontrol over financial reporting.Date: February 19, 2016By:/s/ SUSAN M. BALL Susan M. BallChief Financial Officer and TreasurerEXHIBIT 32.1Certification Pursuant to 18 U.S.C. Section 1350,as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 In connection with the filing of the Annual Report on Form 10-K of CVR Energy, Inc., a Delaware corporation (the "Company"), for the year endedDecember 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned officers of the Companycertifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that, to such officer's knowledge:(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and,(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Companyas of the dates and for the periods expressed in the Report.Date: February 19, 2016By:/s/ JOHN J. LIPINSKI John J. LipinskiChief Executive Officer and President By:/s/ SUSAN M. BALL Susan M. BallChief Financial Officer and Treasurer

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