UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | For the fiscal year ended December 31, 20152017 |
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| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | For the transition period from to . |
Commission file number: 001-33492
CVR Energy, Inc.
(Exact name of registrant as specified in its charter)
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Delaware (State or Other Jurisdiction of Incorporation or Organization) | 61-1512186 (I.R.S. Employer Identification No.) |
2277 Plaza Drive, Suite 500 Sugar Land, Texas (Address of Principal Executive Offices) | 77479 (Zip Code) |
Registrant's Telephone Number, including Area Code:
(281) 207-3200
Securities registered pursuant to Section 12(b) of the Act:
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| Title of Each Class | Name of Each Exchange on Which Registered |
| Common Stock, $0.01 par value per share | The New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 or Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer"filer," "smaller reporting company," and "smaller reporting"emerging growth company" in Rule 12b-2 of the Exchange Act.
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Large accelerated filer þo | Accelerated filer oþ | Non-accelerated filero | Smaller reporting company o
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| | | (Do not check if a smaller reporting company) |
Smaller reporting company o | Emerging growth company o | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 20152017 (the last business day of the registrant's second fiscal quarter) was $588,400,939.$340,159,523. 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, owned 10% or more of the registrant's outstanding common stock as of June 30, 20152017 have been excluded from this number in that these persons may be deemed affiliates of the registrant. This determination of possible affiliate status is not necessarily a conclusive determination for other purposes.
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.
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| Class | Outstanding at February 16, 201620, 2018 |
| Common Stock, par value $0.01 per share | 86,831,050 shares |
Documents Incorporated By Reference
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| Document | Parts Incorporated |
Proxy Statement for the 20162018 Annual Meeting of Stockholders | Items 10, 11, 12, 13 and 14 of Part III |
TABLE OF CONTENTS
GLOSSARY OF SELECTED TERMS
The following are definitions of certain terms used in this Annual Report on Form 10-K for the year ended December 31, 20152017 (this "Report").
2021 Notes — $320.0 million aggregate principal amount of 6.5% Senior Notes due 2021, which were issued by CVR Nitrogen and CVR Nitrogen Finance.
2022 Notes — $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022, which were issued by Refining, LLC and Coffeyville Finance on October 23, 2012 and fully and unconditionally guaranteed by the Refining Partnership and each of Refining LLC's domestic subsidiaries other than Coffeyville Finance.
2023 Notes — $645.0 million aggregate principal amount of 9.25% Senior Secured Notes due 2023, which were issued through CVR Partners and CVR Nitrogen Finance Corporation.
2-1-1 crack spread — The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.
ABL Credit Facility —The Nitrogen Fertilizer Partnership's senior secured asset based revolving credit facility with a group of lenders and UBS AG, Stamford Branch, as administrative agent and collateral agent.
Amended and Restated ABL Credit Facility — The Refining Partnership's senior secured asset based revolving credit facility with a group of lenders and Wells Fargo, as administrative agent and collateral agent.
ammonia — Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applications and finished fertilizer products.
backwardation market — Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. The opposite of contango market.
barrel — Common unit of measure in the oil industry which equates to 42 gallons.
blendstocks — Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.
bpd — Abbreviation for barrels per 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 365the total number of days in the year (365 or 366 days), thus reflecting all operational and logistical limitations.
bulk sales — Volume sales through third-party pipelines, in contrast to tanker truck quantity rack sales.
capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as crude oil and other feedstock costs, product values and downstream unit constraints.
catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
contango marketCoffeyville Fertilizer Facility — Market situationCVR Partners' nitrogen fertilizer manufacturing facility located in which prices for future delivery are higher than the current or spot market priceCoffeyville, Kansas.
Coffeyville Finance — Coffeyville Finance Inc., a wholly-owned subsidiary of Refining LLC and an indirect wholly-owned subsidiary of the commodity. The opposite of backwardation market.Refining Partnership.
corn belt —The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.
crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.
Credit Parties —CRLLC and certain subsidiaries party to the Amended and Restated ABL Credit Facility.
CRLLC— Coffeyville Resources, LLC, a wholly-owned subsidiary of the Company.
CRPLLC —Coffeyville Resources Pipeline, LLC.
CRLLC Facility —The Nitrogen Fertilizer Partnership's $300.0 million senior term loan credit facility with CRLLC, which was repaid in full and terminated on June 10, 2016.
CRNF— Coffeyville Resources Nitrogen Fertilizers, LLC a subsidiary of the Nitrogen Fertilizer Partnership.
CRRM— Coffeyville Resources Refining & Marketing, LLC, a wholly-owned subsidiary of Refining LLC and indirect wholly-owned subsidiary of the Refining Partnership.
CVR Energy or CVR or Company — CVR Energy, Inc.
CVR Nitrogen —CVR Nitrogen, LP (formerly known as East Dubuque Nitrogen Partners, L.P. and also formerly known as Rentech Nitrogen Partners L.P.).
CVR Nitrogen GP— CVR Nitrogen GP, LLC (formerly known as East Dubuque Nitrogen GP, LLC and also formerly known as Rentech Nitrogen GP, LLC).
CVR Partners or the Nitrogen Fertilizer Partnership — CVR Partners, LP and its subsidiaries.
CVR Refining or the Refining Partnership — CVR Refining, LP. and its subsidiaries.
CVR Refining GP or general partner — CVR Refining GP, LLC., an indirect wholly-owned subsidiary of CVR Energy.
distillates — Primarily diesel fuel, kerosene and jet fuel.
East Dubuque Facility — CVR Partners' nitrogen fertilizer manufacturing facility located in East Dubuque, Illinois.
East Dubuque Merger —The transactions contemplated by the Merger Agreement, whereby the Nitrogen Fertilizer Partnership acquired CVR Nitrogen and CVR Nitrogen GP on April 1, 2016.
ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
farm belt — Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.
FCCU — Fluid Catalytic Cracking Unit.
feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel during the refining process.
Group 3 — A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include the Refining Partnership's Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and CHS'CHS Inc.'s refinery in McPherson, KS.
heavy crude oil — A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.
independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstockthroughputs in its refinery operations from third parties.
LIBOR — London Interbank Offered Rate.
light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.
MagellanMerger Agreement — Magellan Midstream Partners L.P., a publicly traded company, whose business isThe Agreement and Plan of Merger, dated as of August 9, 2015, whereby the transportation, storageNitrogen Fertilizer Partnership acquired CVR Nitrogen and distribution of refined petroleum products.CVR Nitrogen GP.
Midway — Midway Pipeline LLC
MMBtu — One million British thermal units or Btu: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.
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, andas well as products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.
Nitrogen Fertilizer Partnership IPOcredit facility — The initial public offeringCRNF's $125.0 million term loan, $25.0 million revolving and $50.0 million uncommitted incremental credit facility, guaranteed by the Nitrogen Fertilizer Partnership, entered into with a group of 22,080,000 common units representing limited partner interests of CVRlenders including Goldman Sachs Lending Partners LP (the "Nitrogen Fertilizer Partnership"),LLC, as administrative and collateral agent, which closedwas repaid in full and terminated on April 13, 2011.1, 2016.
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 at gate is also referred to as netback.
rack sales — Sales which are made at terminals into third-party tanker trucks.trucks or railcars.
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
Refining Partnership IPOLLC — CVR Refining, LLC, a wholly-owned subsidiary of the Refining Partnership.
Refining Partnership IPO—The initial public offering of 27,600,000 common units representing limited partner interests of CVRthe Refining LP (the "Refining Partnership"),Partnership, which closed on January 23, 2013 (which includes the underwriters' subsequently-exercisedsubsequently exercised option to purchase additional common units).
Secondary OfferingRFS — The registered public offering of 12,000,000 common units representing limited partner interestsRenewable Fuel Standard of the Nitrogen Fertilizer Partnership, which closed on May 28, 2013.EPA.
Second Underwritten OfferingRINs— 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).Renewable fuel credits, known as renewable identification numbers.
sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
spot market— A market in which commodities are bought and sold for cash and delivered immediately.
sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
Tender Offer — The cash tender offer commenced on April 29, 2016 by CVR Nitrogen and CVR Nitrogen Finance Corporation to purchase any and all of the outstanding 2021 Notes at 101.5% of par value.
throughput — The volume processed through a unit or a refinery or transported on a pipeline.
turnaround — A periodically required standard procedure to inspect, refurbish, repair and maintain the refinery or nitrogen fertilizer plant assets. This process 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 for the nitrogen fertilizer plant.
UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.
Underwritten OfferingVelocity — Velocity Central Oklahoma Pipeline LLC.
Vitol—Vitol Inc.
Vitol Agreement —The underwritten offering of 13,209,236 common units of the Refining Partnership, which closed on May 20, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional common units).Amended and Restated Crude Oil Supply Agreement between Vitol and CRRM.
VPP —Velocity Pipeline Partners, LLC.
WCS —Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity") of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.
WEC Wells Fargo Credit Agreement— Gary-Williams Energy Corporation, subsequently converted to Gary-Williams EnergyCVR Nitrogen's credit agreement with Wells Fargo, as successor-in-interest by assignment from General Electric Company, LLCas administrative agent, which was repaid in April 2016 and now known as Wynnewood Energy Company, LLC.
WRC — Wynnewood Refining Company, LLC, the owner of the Wynnewood, Oklahoma refinery and related assets with a rated capacity of 70,000 bpcd.terminated.
WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.
WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.
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 a wholly-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.
PART I
Item 1. Business
Overview
CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries ("CVR Energy," the "Company," "we," "us," or "our") is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP ("CVR Refining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces and markets nitrogen fertilizers in the form of UAN and ammonia. We own the general partner and a majorityapproximately 66% and 34% respectively, of the outstanding common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership. CVR Energy's common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "CVI," the Refining Partnership's common units are listed on the NYSE under the symbol "CVRR" and the Nitrogen Fertilizer Partnership's common units are listed on the NYSE under the symbol "UAN." As of December 31, 2017, Icahn Enterprises L.P. and its affiliates owned approximately 82% of our outstanding common stock.
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 are referred to as the "petroleum business" and the "nitrogen fertilizer business," respectively.
For the fiscal years ended December 31, 2015, 20142017, 2016 and 2013,2015, we generated consolidated net sales of $5.4$6.0 billion, $9.1$4.8 billion and $9.0$5.4 billion, respectively, and operating income of $421.6$177.8 million, $264.3$90.9 million and $710.5$421.6 million, respectively. The petroleum business generated $5.2$5.7 billion, $8.8$4.4 billion and $8.7$5.2 billion of net sales and the nitrogen fertilizer business generated $289.2$330.8 million, $298.7$356.3 million and $323.7$289.2 million of net sales, in each case, for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively. The petroleum business generated operating income of $361.7$203.8 million, $207.2$77.8 million and $603.0$361.7 million and the nitrogen fertilizer business generated operating income (loss) of $68.7$(9.2) million, $82.8$26.8 million and $124.9$68.7 million, in each case, for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and, therefore, are not a sum of the operating results of the petroleum and nitrogen fertilizer businesses.
Refer to Item 1, "Petroleum Business" and Item 1, "Nitrogen Fertilizer Business" and Item 8, Note 19 ("Business Segments") for further details on our business segments.
Our History
The Coffeyville refinery, which began operations in 1906, and the nitrogen fertilizer plant, built in 2000, were operated as components of Farmland Industries, Inc. ("Farmland") until March 3, 2004, the date on which Coffeyville Resources, LLC ("CRLLC") completed the acquisition of these assets through 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 CALLCCoffeyville Acquisition LLC ("CALLC") in order to consummate an initial public offering of its businesses.businesses previously acquired through a bankruptcy court auction. CVR Energy consummated its initial public offering on October 26, 2007. The Goldman Sachs Funds and the Kelso Funds completely sold their ownership interests by February 2011 and May 2011, respectively.
On April 13, 2011, the Nitrogen Fertilizer Partnership completed the Nitrogen Fertilizer Partnership IPO.initial public offering ("IPO"). The Nitrogen Fertilizer Partnership sold 22,080,000 common units at a price of $16.00 per common unit, resulting in gross proceeds of $353.3 million. The Nitrogen Fertilizer Partnership's common units are listed on the NYSE and are traded under the symbol "UAN." In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership paid approximately $24.7 million in underwriting fees and incurred approximately $4.4 million of other offering costs. As a result of the Nitrogen Fertilizer Partnership IPO and through May 27, 2013, CVR Energy indirectly owned approximately 70% of the Nitrogen Fertilizer Partnership's outstanding common units and 100% of the Nitrogen Fertilizer Partnership's general partner with its non-economic general partner interest.
On December 15, 2011, CVR Energy acquired all of the issued and outstanding shares of WEC. Assets acquired include a 70,000 bpcd rated capacity refinery 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 common stock 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 of CVR 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 the Transaction 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 affiliates owned 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 a price 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.Icahn Enterprises L.P. ("IEP"). Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per unit resulting in gross proceeds 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 Refining Partnership common units and 100% of the Refining Partnership's general partner, which holds a non-economic general partner interest. Prior to the Refining Partnership 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,April 1, 2016, the RefiningNitrogen Fertilizer Partnership completed an underwritten offeringthe East Dubuque Merger as contemplated by the Agreement and Plan of Merger, dated as of August 9, 2015 (the "Underwritten Offering""Merger Agreement") by selling 12,000,000 common units, whereby the Nitrogen Fertilizer Partnership acquired CVR Nitrogen and CVR Nitrogen GP. Pursuant to the public at a priceEast Dubuque Merger, the Nitrogen Fertilizer Partnership acquired the East Dubuque Facility.
Table of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection 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 in this paragraph are collectively referred to as the "Transactions." In connection with the Transactions, the Refining Partnership paid approximately $12.2 million in underwriting fees and approximately $0.4 million in offering costs.Contents
The Refining Partnership utilized net proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings, LLC ("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 Refining Partnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC.
Immediately following the closing of the TransactionsEast Dubuque Merger and prior to June 30, 2014,as of December 31, 2017, public security holders held approximately 29%66% of the total Refining Partnership common units (including units owned by affiliates of IEP representing 4% of total Refining Partnership common units), and CVR Refining Holdings 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 Partnership common 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, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5 million 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 the total Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53%34% of the
total Nitrogen Fertilizer Partnership common units. Inunits in addition CRLLC ownsto owning 100% of the Nitrogen Fertilizer Partnership’sPartnership'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 6,500,000 common 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 to redeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately 67% 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 the underwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.partner.
Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and asAs of December 31, 2015,2017, public security holders held approximately 34% of the total Refining Partnership common units (including units owned by affiliates of IEP, representing 4%3.9% of the total Refining Partnership common units), and CVR Refining Holdings, LLC ("CVR Refining Holdings") held approximately 66% of the total Refining Partnership common units, in addition to owning 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 and Rentech Nitrogen GP by merging two newly-created direct wholly-owned subsidiaries of CVR Partners with and into those entities with Rentech Nitrogen and 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.
Organizational Structure and Related Ownership
The following chart illustrates our organizational structure and the organizational structure of the Refining Partnership and the
Nitrogen Fertilizer Partnership as of the date of this Report.
Petroleum Business
The petroleum business, operated by the Refining Partnership, includes a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas with a rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing 20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). The combined crude capacity represents approximately 22%23% of the region's refining capacity. The Coffeyville refinery located in southeast Kansas is approximately 100 miles from Cushing, Oklahoma ("Cushing"), a major crude oil trading and storage hub. The Wynnewood refinery is located approximately 65 miles south of Oklahoma City, Oklahoma and approximately 130 miles from Cushing, Oklahoma.Cushing.
For the year ended December 31, 2015,2017, the Coffeyville refinery's product yield included gasoline (46%(50%), diesel fuel (primarily ultra-low sulfur diesel) (43%diesel ("ULSD")) (42%), and pet coke and other refined products such as natural gas liquids ("NGL") (propane and butane), slurry, sulfur and gas oil (11%(8%). The Wynnewood refinery's product yield included gasoline (52%(51%), diesel fuel (primarily ultra-low sulfur diesel) (36%ULSD) (37%), asphalt (5%), jet fuel (4%) and other products (3%) (slurry, sulfur and gas oil, and specialty products such as propylene and solvents).
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, Plainville and Plainville, Winfield, Kansas and Iola, Kansas.Denver, Colorado. The gathering system includes approximately 336570 miles of active owned, leased and leasedjoint venture pipelines and approximately 150130 crude oil transports and associated storage facilities, which allows it to gather crude oils from independent crude oil producers. The crude oil gathering system has a gathering capacity of over 65,000 bpd.80,000 bpd currently. Gathered crude oil provides an attractive and competitive base supply of crude oil for the Coffeyville and Wynnewood refineries. During 2015,2017, the petroleum business gathered an averageapproximately 86,000 bpd of approximately 69,000 bpd.price advantaged crudes from our gather area. The petroleum business also has 35,000 bpd of contracted capacity on the Keystone and Spearhead pipelines that allow it to supply price-advantaged Canadian and Bakken crudescrude to its refineries. It also has contracted capacity on the Pony Express and White Cliffs pipelines, which both became in-service during 2015. Both the Pony Express and White Cliffs pipelines originate in Colorado and extend to Cushing. During the fourth quarter of 2017, the Refining Partnership entered into a 50/50 joint venture, Midway Pipeline LLC ("Midway"), with a subsidiary of Plains All American Pipeline, L.P. ("Plains"), which acquired the approximately 100-mile, 16-inch pipeline that connects the Coffeyville refinery to Cushing, Oklahoma.and the Refining Partnership separately acquired from Plains the approximately 100-mile, 8- and 10-inch pipeline system connecting the Wynnewood refinery to Cushing. Refer to Part II, Item 8, Note 7 ("Equity Method Investments") of this Report for a discussion of the joint venture transaction.
Pipelines and Storage Tanks. The petroleum business owns a proprietary pipeline system capable of transporting approximately 170,000 bpd of crude oil from its Broome Station facility located near Caney, Kansas to its Coffeyville refinery. Crude oils sourced outside of the proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to the Broome Station tank farm via a pipeline owned by Midway. Crude oil is transported via the Cushing to Ellis crude oil pipeline system acquired from Plains Pipeline L.P. ("Plains").and, beginning in April 2017, the petroleum business also transports crude oil via a 65,000 bpd pipeline owned and operated by the VPP joint venture, to the Wynnewood refinery from a trucking terminal at Lowrance, Oklahoma. 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 of crude oil storage capacity at the Wynnewood refinery and (iii) 1.5 million barrels of crude oil storage capacity in Cushing, Oklahoma.Cushing. The petroleum business also leases additional crude oil storage capacity of approximately (iv) 2.82.3 million barrels in Cushing (v)and 0.2 million barrels in Duncan, OklahomaOklahoma. The Duncan storage supports CVR Refining's Wynnewood refinery while the Cushing storage supports both its Wynnewood and (vi) 0.1 million barrels at the Wynnewood refinery.Coffeyville refineries. In addition to crude oil storage, the petroleum business owns over 4.54.6 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 to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and to customers at throughput terminals on 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 and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery's ability to process lower quality crude oil and feedstocks in an economic manner. The two refineries' capacity weighted average complexity is 13.0. As a result of key investments in its refining assets and the addition of process units to comply with gasoline quality regulations, both of the refinery's complexities have increased. The Coffeyville refinery's complexity score is 13.3, and the Wynnewood refinery's complexity score is 12.6. The petroleum business' higher complexity provides it the flexibility to increase its refining margin over comparable refiners with lower complexities. The petroleum business has achieved significant increases in its refinery crude throughput 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.
Crude and Feedstock Supply
The Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, the Coffeyville refinery crude oil slate consists of a blend of mid-continent domestic grades and various Canadian medium and heavy sours, and it has recently introduced North Dakota Bakken and other similarly sourced crudes into its crude slate.crudes. While crude oil has historically constituted over 90% of the Coffeyville refinery's total throughput over the last five years, other feedstock inputs include normal butane, natural gasoline, alkylation feeds, naphtha, gas oil and vacuum tower bottoms.
The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutane, gasoline components, and normal butane are also typically used. Historically most of the Wynnewood refinery's crude oil has been acquired domestically, mainly from Texas and Oklahoma, but it can also access and process various light and medium Canadian grades.
Crude oil is supplied to the Coffeyville and Wynnewood refineries through the wholly-owned gathering system and by pipeline.owned, leased and joint venture pipelines. The petroleum business has continued to increase the number of barrels of crude oil supplied through its crude oil gathering system in 20152017 and it now has the capacity of supplying over 65,00080,000 bpd of crude oil to the refineries. For the year ended December 31, 2015,2017, the gathering system supplied approximately 39% of both44% and 49% of the Coffeyville and Wynnewood refineries' crude oil demand.demand, respectively. Locally produced crude oils are delivered to the refineries at a discount to WTI, and although sometimes slightly heavier and more sour, offer good economics to the refineries. These crude oils are light and sweet enough to allow the refineries to blend higher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining their target medium sour blend with an API gravity of between 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of 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 PlainsMidway joint venture pipeline. In May 2015 and November 2015, theThe petroleum business' current contracted capacity includedincludes the Pony Express and White Cliffs pipelines, respectively. From the Broome Station facility, crude oil is delivered to the Coffeyville refinery via the petroleum business' 170,000 bpd proprietary pipeline system. Crude oils are delivered to the Wynnewood refinery by three separatethrough third-party pipelines, the pipeline acquired from Plains and, beginning in April 2017, through the VPP joint venture pipeline, and received into storage tanks at terminals located on or near the refinery.
For the year ended December 31, 2015,2017, the Coffeyville refinery's crude oil supply blend was comprised of approximately 85.4%92% light sweet crude oil 12.8%and 8% heavy sour crude oil and 1.8% light/medium sour crude oil. For the year ended December 31, 2015,2017, the Wynnewood refinery's crude oil supply blend was comprised of approximately 99.5%entirely of light sweet crude oil and 0.5% light/medium sour crude oil. The light sweet crude oil supply blend includes its locally gathered crude oil.
The Coffeyville refinery is connected to the mid-continent natural gas liquids commercial hub of Conway, Kansas by the inbound Enterprise Pipeline Blue Line. Natural gas liquids feedstock supplies such as butanes and natural gasoline are sourced and delivered directly into the refinery. In addition, Coffeyville's proximity to Conway provides access to the natural gas liquid and liquid petroleum gas fractionation and storage capabilities as well as the commercial markets available at Conway.
Crude Oil Supply Agreement
On AugustRefer to Part II, Item 8, Note 15 ("Commitments and Contingencies") of this Report for information on the crude oil supply agreement.
Refining Process
Coffeyville Refinery
The Coffeyville refinery is a 115,000 bpcd rated capacity facility with operations including fractionation, catalytic cracking, hydrotreating, reforming, coking, isomerization, alkylation, sulfur recovery and propane and butane recovery. The Coffeyville refinery benefits from significant refining unit redundancies, which include two crude oil distillation and vacuum towers, three sulfur recovery units and four hydrotreating units. These redundancies allow the Refining Partnership to continue to receive and process crude oil even if one tower requires unplanned maintenance without having to shut down the entire refinery in the case of a major unit turnaround. In addition, the Coffeyville refinery has a redundant supply of hydrogen pursuant to its feedstock and shared services agreement with a subsidiary of CVR Partners. During the year ended December 31, 2012,2017, the Coffeyville Resources Refiningrefinery processed approximately 132,000 bpd and Marketing, LLC ("CRRM") and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with9,000 bpd of crude oil and intermediation logistics, which helpsfeedstocks and blendstocks, respectively.
Wynnewood Refinery
The Wynnewood refinery is a 70,000 bpcd rated capacity facility with operations including fractionation, cracking, hydrotreating, hydrocracking, reforming, solvent deasphalting, alkylation, sulfur recovery and propane and butane recovery. Similar to the petroleum business to reduce its inventory position and mitigateCoffeyville refinery, the Wynnewood refinery benefits from unit redundancies, including two crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party providesdistillation and vacuum towers and four hydrotreating units. During the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends throughyear ended December 31, 2016.2017, our Wynnewood refinery processed approximately 73,000 bpd and 3,000 bpd of crude oil and feedstocks and blendstocks, respectively. These throughput rates for 2017 reflect the first phase of the major scheduled turnaround completed in the fourth quarter of 2017.
Marketing and Distribution
The petroleum business focuses its Coffeyville petroleum product marketing efforts in the central mid-continent area, because of its relative proximity to the refinery and pipeline access. Coffeyville also has access to the Rocky Mountain area. Coffeyville engages in rack marketing, which is the supply of product through tanker trucks and railcars directly to customers located in close geographic proximity to the refinery and to customers at throughput terminals on the refined products distribution systems of Magellan and NuStar. Coffeyville also makes bulk sales (sales into third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. The outbound Enterprise Pipeline Red Line provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ULSD product sales from Kansas up into North Dakota.
The Wynnewood refinery ships its finished product via pipeline, railcar, and truck. It focuses its efforts in the southern portion of the Magellan system which covers all of Oklahoma, parts of Arkansas as well as eastern Missouri, and all other Magellan terminals. The pipeline system is also able to flow in the opposite direction, providing access to Texas markets as well as some adjoining states with pipeline connections. Wynnewood also sells jet fuel to the U.S. Department of Defense via its segregated truck rack and can offer asphalts, solvents and other specialty products via both truck and rail.
Customers
Customers for the refined petroleum products primarily include retailers, railroads, and farm cooperatives and other refiners/marketers in Group 3 of the PADD II region because of their relative proximity to the refineries and pipeline access. The petroleum business sells bulk products to long-standing customers at spot market prices based on a Group 3 basis differential to prices quoted on the New York Mercantile Exchange ("NYMEX"), which are reported by industry market-related indices such as Platts and Oil Price Information Service.
The petroleum business also has a rack marketing business supplying product through tanker trucks directly to customers located in proximity to the Coffeyville and Wynnewood refineries, as well as to customers located at throughput terminals on refined products distribution systems run by Magellan and NuStar. Rack sales are at posted prices that are influenced by competitor pricing and Group 3 spot market differentials. Additionally, the Wynnewood refinery supplies jet fuel to the U.S. Department of Defense. In addition, the Coffeyville refinery sells hydrogen and by-products of its refining operations, such as petroleum coke, to an affiliate, CVR Partners, pursuant to separate multi-year agreements. For the year ended December 31, 2015,2017, only one customer accounted for 10% or more of the twopetroleum business' consolidated revenues. Its largest customerscustomer accounted for approximately 14% and 9%19% of the petroleum businessits net sales and approximately 53%52% of the petroleum business net sales were made to its ten largest customers. While the petroleum business does have a high concentration of customers, it does not believe that the loss of any single customer would have a material adverse impact on its results of operations, financial condition and cash flows. Refer to Part I, Item 1A, Risk Factors, Both the petroleum and nitrogen fertilizer businesses depend on significant customers and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and cash flows.
Competition
The petroleum business competes primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting its refining operations are cost of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refinery product mix and product distribution and transportation costs. The location of the refineries provides the petroleum business with a reliable supply of crude oil and a transportation cost advantage over its competitors. The petroleum business primarily competes against five refineries operated in the mid-continent region. In addition to these refineries, the refineries compete against trading companies, as well as other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the Gulf Coast and the Texas panhandle region. The petroleum business refinery competition also includes branded, integrated and independent oil refining companies, such as Phillips 66, HollyFrontier Corporation, CHS Inc., Valero Energy Corporation and Flint Hills Resources.
Seasonality
The petroleum business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel is higher during the planting and harvesting seasons. As a result, the petroleum business' results of operations for the first and fourth calendar quarters are generally lower compared to its results for the second and third calendar quarters. In addition, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which the petroleum business sells its petroleum products can impact the demand for gasoline and diesel fuel. The demand for asphalt is also seasonal and is generally higher during the months of March through October.
Nitrogen Fertilizer Business
The nitrogen fertilizer business, operated by the Nitrogen Fertilizer Partnership, is the onlyconsists of two nitrogen fertilizer plantmanufacturing facilities which are located in North America that utilizes a pet coke gasification process to produceCoffeyville, Kansas and East Dubuque, Illinois. The nitrogen fertilizer business produces and distributes nitrogen fertilizer products, which are used primarily by farmers to improve the yield and quality of their crops. The nitrogen fertilizer facilityprincipal products are UAN and ammonia, and all products are sold on a wholesale basis. The Coffeyville Fertilizer Facility includes a 1,300 ton-per-day capacity ammonia unit, a 3,000 ton-per-day capacity UAN unit and a gasifier complex having a capacity of 89 million standard cubic feet per day of hydrogen. The Coffeyville Fertilizer Facility is the only nitrogen fertilizer business' principal products areplant in North America that utilizes a pet coke gasification process to produce nitrogen fertilizer. The East Dubuque Facility, which includes a 1,075 ton-per-day capacity ammonia unit and a 1,100 ton-per-day capacity UAN unit, has the flexibility to vary its product mix enabling the East Dubuque Facility to upgrade a portion of its ammonia production into varying amounts of UAN, nitric acid and ammonia. These products are manufactured at its facility in Coffeyville, Kansas.liquid and granulated urea each season, depending on market demand, pricing and storage availability. The nitrogen fertilizer business'East Dubuque Facility's product sales are heavily weighted toward UANsales of ammonia and all of its products are sold on a wholesale basis.UAN.
Raw Material Supply
Coffeyville Fertilizer Facility
The nitrogen fertilizer facility's primary input is pet coke. In contrast, substantially all of the nitrogen fertilizer business' competitors use natural gas as their primary raw material feedstock. Historically,Coffeyville Fertilizer Facility was built in 2000 and uses a gasification process to convert pet coke has been less expensive than natural gas on a per ton of fertilizer produced basis.to high purity hydrogen for subsequent conversion to ammonia. The Coffeyville nitrogen fertilizer 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 Coffeyville nitrogen fertilizer business'facility's pet coke requirements on average were supplied by CVR Refining's adjacent crude oil refinery pursuant to a renewable long-term agreement. Historically the Coffeyville nitrogen fertilizer businessplant has obtained the remainder of its pet coke requirements from third parties such as other Midwestern refineries or pet coke brokers at spot-prices. The Nitrogen Fertilizer Partnership is party to a pet coke supply agreement with HollyFrontier Corporation. The term ofCorporation that ends December 2018, and has historically renewed this agreement expires in December 2016.annually. If necessary, thethere are other pet coke suppliers. The Nitrogen Fertilizer Partnership also purchased some of its hydrogen from CVR Refining's adjacent crude oil refinery pursuant to a long-term agreement.
The pet coke gasification process can be modifiedis licensed from an affiliate of General Electric Company. The license grants the Coffeyville Fertilizer Facility perpetual rights to operateuse the pet coke gasification process on coal as an alternative, which provides an additional raw material source. There are significant supplies of coal within a 60-mile radius ofspecified terms and conditions, and the nitrogen fertilizer plant.license is fully paid.
Linde LLC ("Linde") owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry air to the facility for a monthly fee. The nitrogen fertilizer business provides and pays for all utilities required for operation of the air separation plant. The agreement with Linde expires in 2020.Coffeyville Fertilizer Facility gasifiers.
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 the nitrogen fertilizer plant from the adjacent Coffeyville crude oil refinery and then export steam back to the crude oil refinery once all units in the nitrogen fertilizer plant are in service. Monthly charges and credits are recorded with the steam valued at the natural gas price for the month.
Nitrogen Production ProcessEast Dubuque Facility
The East Dubuque Facility uses natural gas to produce nitrogen fertilizer plant was built in 2000 with two separate gasifiersfertilizer. The East Dubuque Facility is able to provide redundancy and reliability. The plant uses a gasification processpurchase natural gas at competitive prices due to convert pet cokethe plant’s connection to high purity hydrogen for subsequent conversion to ammonia. The nitrogen fertilizer plantthe Northern Natural Gas interstate pipeline system, which is capable of producing approximately 1,300 tons per day of ammonia. Substantially allwithin one mile of the ammonia produced is convertedfacility, and the ANR Pipeline Company pipeline. The pipelines are connected to approximately 3,000 tons per day of UAN, which has historically commanded a premium price over ammonia. Typically, approximately 0.41 tons of ammonia is required to produce one ton of UAN. The nitrogen fertilizer business completed a significant two-year plant expansion in February 2013, which increased UAN production capacity by 400,000 tons or approximately 50%, per year. The expanded facility was operating at full ratesNicor Inc.’s distribution system at the endChicago Citygate receipt point and at the Hampshire interconnect from which natural gas is transported to the East Dubuque Facility.
Changes in the levels of natural gas prices and market prices of nitrogen-based products can materially affect the first quarterEast Dubuque Facility's financial position and results of 2013. In 2015,operations. Natural gas prices in the United States have experienced significant fluctuations over the last decade, increasing substantially in 2008 and subsequently declining to the current lower levels. From time to time, the nitrogen fertilizer business produced 928,600 tonsenters into forward contracts with fixed delivery prices to purchase portions of UAN and 385,400 tonsits natural gas requirements. As of ammonia. Approximately 96% of the produced ammonia tons and the majority of the purchased ammonia were upgraded into UAN.
The nitrogen fertilizer business schedules and provides routine maintenance to its critical equipment using its own maintenance technicians. Pursuant to a Technical Services Agreement with an affiliate of the General Electric Company ("General Electric"), which licenses the gasification technology toDecember 31, 2017, the nitrogen fertilizer business General Electric provides technical advicesegment had commitments to purchase approximately 1.8 million MMBtus of natural gas supply for planned use in its East Dubuque Facility in January 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 toFebruary 2018 at a perpetual license agreement that is fully paid. The license grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions.weighted average rate per MMBtu of approximately $3.20, exclusive of transportation cost.
Distribution, Sales and Marketing
The primary geographic markets for the nitrogen fertilizer business' fertilizer products are Illinois, Iowa, Kansas, Missouri, Nebraska Iowa, Illinois, Colorado and Texas. The nitrogen fertilizer business marketsbusiness' primarily market the UAN products to agricultural customers and the ammonia products to agricultural and industrial customers. UAN and agricultural customers.ammonia accounted for approximately 67% and 25%, respectively, of its total net sales for the year ended December 31, 2017.
UAN and ammonia are primarily distributed by truck or by railcar. If delivered by truck, products are most commonly sold on a freight-on-board ("FOB") shipping point basis, and freight is normally arranged by the customer. The nitrogen fertilizer business leases and owns a fleet of railcars for use in product delivery. delivery, and, if delivered by railcar, the products are most commonly sold on a FOB destination point basis and the nitrogen fertilizer business typically arranges the freight.
The nitrogen fertilizer business incurs costsbusiness's fertilizer products leave the Coffeyville Fertilizer Facility either in railcars for destinations located principally on the Union Pacific Railroad or in trucks for direct shipment to maintain and repaircustomers. The East Dubuque Facility primarily sells its railcar fleet that include expenses relatedproduct to regulatory inspections and repairs. For example, manycustomers located within 200 miles of the facility. In most instances, customers take delivery of nitrogen fertilizer business' railcars require specific regulatory inspectionsproducts at the East Dubuque Facility and repairs due on ten-year intervals. The extentarrange and frequency of railcar fleet maintenance and repair costs are generally expectedpay to change based partially on when regulatory inspections and repairs are due for its railcars under the relevant regulations. The nitrogen fertilizer business operates eight rail loading and two truck loading racks for UAN. It also operates four rail loading and two truck loading racks for ammonia.transport them to their final destinations by truck.
The nitrogen fertilizer business owns all of the truck and rail loading equipment at the nitrogen fertilizer facility. The nitrogen fertilizer business also utilizes 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 was constructed on is owned by a subsidiary of CVR Refining, which operates the terminal. The Dartmouth terminal is located on leased property owned by the Pawnee County Cooperative Association, which operates the terminal. The purpose of the UAN terminals is to collectively distribute approximately 40,000 tons of UAN fertilizer annually.
The nitrogen fertilizer business markets agricultural productshas the capacity to destinations that produce strong margins.store approximately 160,000 tons of UAN and 80,000 tons of ammonia. The UAN marketnitrogen fertilizer's business storage tanks are located primarily at its two production facilities. Inventories are often allowed to accumulate to allow customers to take delivery to meet the seasonal demand. While the nitrogen fertilizer business does experience higher sales volumes due to seasonality during the fall and spring application periods, product is primarily located nearsold to customers throughout the Union Pacific Railroad lines or destinations that can be supplied by truck. The ammonia market is primarily located near the Burlington Northern Santa Fe or Kansas City Southern Railroad lines or destinations that can be supplied by truck.year.
The nitrogen fertilizer business offers agricultural products on a spot, forward or prepay basis and often uses forward sales of fertilizer products to optimize its asset utilization, planning process and production scheduling. 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 the nitrogen fertilizer business view of market conditions and has the flexibility to increase or decrease forward sales depending on management's view as to whether price environments will be increasing or decreasing.conditions. Fixing the selling prices of nitrogen fertilizer products months in advance of their ultimate delivery to customers typically causes the nitrogen fertilizer business reported 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 is recognized as deferred revenue on the Consolidated Balance Sheet upon receipt, and revenue and resultant net income and EBITDA are recorded as the product is delivered to the customer.
Customers
The 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 contracts with most of its UAN and ammoniaagricultural customers. Some of our industrial sales include long-term purchase contracts.
For the year ended December 31, 2015,2017, the top five customers in the aggregate represented 39%31% of the nitrogen fertilizer business' net sales. The nitrogen fertilizer business' top two customerscustomer on a consolidated basis accounted for approximately 14% and 10%, respectively,11% of its net sales. While the nitrogen fertilizer business' net sales.business does have high concentration of customers, it does not believe that the loss of any single customer would have a material adverse effect on its results of operations, financial condition and cash flows. Refer to Part I, Item 1A, Risk Factors, Both the petroleum and nitrogen fertilizer businesses depend on significant customers and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and cash flows.
Competition
The nitrogen fertilizer business has experienced and expects to continue to meet significant levels of competition from current and potential competitors, many of whom have significantly greater financial and other resources. Refer to Part I, Item 1A, Risk Factors, Nitrogen fertilizer products are global commodities, and the nitrogen fertilizer business faces intense competition from other nitrogen fertilizer producers.
Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. The nitrogen fertilizer business maintains a large fleet of leased and owned railcars and seasonally adjusts inventory to enhance its manufacturing and distribution operations.
The nitrogen fertilizer business' major competitors include Agrium,CF Industries Holdings, Inc., including its majority owned subsidiary Terra Nitrogen Company, L.P.; Koch NitrogenFertilizer Company, LLC; and Nutrien Ltd. (formerly known as Agrium, Inc. and Potash Corporation of Saskatchewan, Inc.; CF Industries Holdings, Inc. and Terra Nitrogen Company, LP.). Domestic competition is intense due to customers' sophisticated buying tendencies and competitor strategies that focus on cost and service. The nitrogen fertilizer business also encounters competition from producers of fertilizer products manufactured in foreign countries. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments.
Based on third-party expert data regarding total United States demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant's UAN capacity in 2015 represented approximately 7% of total U.S. UAN demand and that the net ammonia produced and marketed at its facility represented less than 1% of total U.S. ammonia demand.
Seasonality
Because the nitrogen fertilizer business primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. AsIn addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers who make planting decisions based largely on the prospective profitability of a result,harvest. The specific varieties and amounts of fertilizer they apply depend on factors like crop prices, farmers' current liquidity, soil conditions, weather patterns and the types of crops planted. The nitrogen fertilizer business typically generates greaterexperiences higher net sales in the first half of eachthe calendar 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 as the fill season.
Environmental Matters
The petroleum and nitrogen fertilizer businesses are subject to extensive and frequently changing federal, state and local, environmental, and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, and the storage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact the petroleum business and operations and the nitrogen fertilizer 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;
requirementsliability for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability for off-site waste disposal locations; and
specifications for the products marketed by the petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN and ammonia.
Our operations require numerous permits, licenses and authorizations. Failure to comply with these permits or environmental laws and regulations could result in fines, penalties or other sanctions or a revocation of our permits. In addition, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. The ultimate impact on our business of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.
The principal environmental risks associated with our businesses are outlined below, with additional details included in Part I, Item 1A, Risk Factors and Part II, Item 8, Note 1315 ("Commitments and Contingencies") of this Report.
The Federal Clean Air Act
The federal Clean Air Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect the petroleum business and the nitrogen fertilizer business both directly and indirectly. Direct impacts may occur through the federal Clean Air Act's permitting requirements and/or emission control requirements relating to specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. The federal Clean Air Act indirectly affects the petroleum business and the nitrogen fertilizer business by extensively regulating the air emissions of sulfur dioxide ("SO2"), volatile organic compounds, nitrogen oxides and other substances, including those emitted by mobile sources, which are direct or indirect users of our products.
Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation of controls or changes to the petroleum business or the nitrogen fertilizer facilities in order to comply. If new controls or changes to operations are needed, the costs could be material. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations, could cause us to expend substantial amountsresources to comply and/or permit our facilities to produce products that meet applicable requirements.
The regulation of air emissions under the federal Clean Air Act requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at the petroleum and nitrogen fertilizer operations when regulations change or we add new equipment or modify existing equipment. Various regulations specific to our operations have been implemented, such as National Emission Standard for Hazardous Air Pollutants ("NESHAP"), New Source Performance Standards ("NSPS") and New Source Review/Prevention of Significant Deterioration ("PSD"). We have incurred, and expect to continue to have to make, substantial capital expenditures to attain or maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future.
On September 12, 2012, the U.S. Environmental Protection Agency (the "EPA") published in the Federal Register final revisions to its NSPS for process heaters and flares at petroleum refineries. The EPA originally issued final standards in June 2008, but the portions of the rule relating to process heaters and flares were stayed pending reconsideration of certain provisions. The final standards regulate emissions of nitrogen oxide from process heaters and emissions of SO2 from flares, as well as require certain work practice and monitoring standards for flares. We do not believe that the costs of complying with the rule will beare material.
On August 14, 2012,December 1, 2015, the EPA sent bothpublished in the Wynnewood and Coffeyville refineries letters regardingFederal Register the EPA's 2012 enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations signaling the agency's intention to begin a national enforcement program to conduct compliance evaluations and take enforcement actions against petroleum refining companiessector risk rule. The rule places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. CVR Refining Partnership does not believe that operate flares thatthe costs of complying with the rule are not in compliance with standards articulated in the Enforcement Alert. The Enforcement Alert identified new standards that refiners are required to meet for flaring combustion efficiency. The EPA entered into consent decrees with several refining companies. Because the EPA has not specifically told us that our operations are not in compliance, we cannot say with certainty whether or when we may become an enforcement target under this initiative.material.
Refer to Part II, Item 8, Note 1315 ("Commitments and Contingencies") of this Report for further discussion of recent environmental matters related to the Clean Air Act including the "Flood, Crude Oil Discharge and Insurance" and certain "Environmental, Health and Safety ("EHS") Matters,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 submitted an application for renewal, and therefore is authorized under the regulations to operate under the current permit until the permit is re-issued. The permit renewal 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 Act
The federal Clean Water Act ("CWA") and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants into the water, affect the petroleum business and the nitrogen fertilizer business. Direct impacts occur through the CWA's permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load of pollutants that may be released to a particular water body based on its use. In addition, water resources are becoming and in the future may become scarcer, and many refiners, including CRRM and Wynnewood Refining Company, LLC ("WRC"), are subject to restrictions on their ability to use water in the event of low availability conditions. Both CRRM and WRC have contracts in place to receive additional water during low-flowcertain water shortage conditions, but these conditions could 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 is authorized to continue discharging under the expired permit until the Oklahoma Department
Release Reporting
The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws. Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. For example, the nitrogen fertilizer facility periodically experiences minor releases of hazardous and extremely hazardous substances from its equipment. Our facilities periodically have excess emission events from flaring and other planned and unplanned start-up, shutdown and malfunction events. Such releases are reported to the EPA and relevant state and local agencies. From time to time, the EPA has conducted inspections and issued information requests to us with respect 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 the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third-party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.
Fuel Regulations
Tier 2, Low Sulfur Fuels. In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. 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 more than ten parts per million of sulfur on an annual average basis. Refineries mustwere required to be in compliance with the more stringent emission standards byas of January 1, 2017; however, compliance with the rule ishas been extended until January 1, 2020 for approved small volume refineries and small refiners. In March 2015,June 2016, because it exceeded the EPA approvedEPA’s specified throughput limit for a “small volume refinery,” the Wynnewood refinery's application requesting "smallrefinery became disqualified as a “small volume refinery" status; therefore, it'srefinery.” Therefore, the Wynnewood refinery’s compliance deadline is January 1, 2020.was accelerated to December 21, 2018. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.
Mobile Source Air Toxic II Emissions
In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requiresrequired the reduction of benzene in gasoline by 2011. The MSAT II projects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. The projects were completed at a total cost of approximately $48.3 million and $89.0 million, excluding capitalized interest, by CRRM and WRC, respectively.refineries are in compliance with the EPA's MSAT II rule.
Renewable Fuel Standards
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 for RINs or if the petroleum business is otherwise unable to meet the EPA's Renewable Fuels Standard (RFS)RFS mandates, the petroleum business' financial condition and results of operations could be materially adversely affected, and Part II, Item 8, Note 1315 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" of this Report for further discussion of the "Renewable Fuel Standards."
Greenhouse Gas Emissions
Refer to Part I, Item 1A, Risk Factors, Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows, of this Report for further discussion of the Greenhouse Gas ("GHG") Emissions regulations.
RCRAResource Conservation and Recovery Act ("RCRA")
Our operations are subject to the Resource Conservation and Recovery Act ("RCRA")RCRA requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulated substances. Refer to Part II, Item 8, Note 1315 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" for further discussion of "RCRA Compliance Matters."
Waste Management. There are two closed hazardous waste units at the Coffeyville refinery and eightfourteen other hazardoussolid waste management units in the process of being closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewood refinery. In addition, one closed interim status hazardous waste land farm located at the now-closed Phillipsburg terminal is under long-term post closure care.
Impacts of Past Manufacturing. The In March 2004, CRRM and Coffeyville Resources Terminal, LLC ("CRT") entered into a Consent Decree ("2004 Consent Decree that CRRM signedDecree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") which required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the Coffeyville refinery. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and groundwater conditions, which requirerequired investigation orand interim remediation projects. In June 2017, the Coffeyville refinery submitted an amended post-closure permit application to KDHE to complete closure of former hazardous waste management units at the Coffeyville refinery and to perform corrective action at the site. The now-closed Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. Remediation at both sites,The Phillipsburg terminal continues to implement interim measures to address the investigation’s findings. Further remediation, if ordered necessary by the EPA or the state, will be based on the results of the investigations.investigation. The Wynnewood refinery operates under a RCRA permit. A RCRA facility
investigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, ODEQthe Oklahoma Department of Environmental Quality ("ODEQ") and WRC have entered into a Consent Orderconsent order requiring further investigations of groundwater conditions and enhancements of existing remediation systems. Additional remediation, if necessary, will be based uponThe Wynnewood refinery has completed the results of the further investigation.groundwater investigation and ODEQ has approved our corrective action recommendations.
The anticipated investigation and remediation costs through 20192021 were estimated, as of December 31, 2015,2017, to be as follows:
| | | Facility | Site Investigation Costs | | Capital Costs | | Total Operation & Maintenance Costs Through 2019 | | Total Estimated Costs Through 2019 | Site Investigation Costs | | Capital Costs | | Total Operation & Maintenance Costs Through 2021 | | Total Estimated Costs Through 2021 |
| | (in millions) | (in millions) |
| Coffeyville Refinery | $ | 0.3 |
| | $ | — |
| | $ | 0.9 |
| | $ | 1.2 |
| $ | 0.1 |
| | $ | — |
| | $ | — |
| | $ | 0.1 |
|
| Phillipsburg Terminal | 0.4 |
| | — |
| | 1.1 |
| | 1.5 |
| 0.3 |
| | — |
| | — |
| | 0.3 |
|
| Wynnewood Refinery | 0.3 |
| | — |
| | 1.8 |
| | 2.1 |
| — |
| | 2.7 |
| | 0.9 |
| | 3.6 |
|
| Total Estimated Costs | $ | 1.0 |
| | $ | — |
| | $ | 3.8 |
| | $ | 4.8 |
| $ | 0.4 |
| | $ | 2.7 |
| | $ | 0.9 |
| | $ | 4.0 |
|
These estimates are based on current information and could increase or decrease as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2016,2018, we will spend approximately $7.3$7.2 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closed Phillipsburg terminal and at the Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately $2.1$2.0 million in 20152017 associated with related remediation.
Financial Assurance. We are required under the 2004 Consent Decree to establish financial assurance to secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decree as modified by a 2010 agreement between CRRM, Coffeyville Resources Terminal, LLC,CRT, the EPA and the KDHE, this financial assurance is currently provided by a bond in the amount of $4.3$3.0 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of $0.2$0.3 million for estimated costs to close regulated hazardous waste management units at the Coffeyville refinery. Additional self-funded financial assurance of approximately $4.9$5.6 million and $2.4$2.5 million is required by our post-closure care obligations and the 2004 Consent Decree for clean-up costs at the Coffeyville refinery and Phillipsburg terminal, respectively. The $4.3$3.0 million bond amount is reduced each year based on actual expenditures for corrective actions and the letter of credit and the self-funded mechanisms are re-evaluated and adjusted on an annual basis. Current RCRA financial assurance requirements for the Wynnewood refinery total $0.2 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.
Environmental Remediation
Under the CERCLA, RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the Oil Pollution Act of 1990 generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.Environmental Remediation
As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure youThere is no assurance that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material. Refer to Part II, Item 8, Note 1315 ("Commitments and Contingencies"), "Flood, Crude Oil Discharge and Insurance" of this Report for discussion of the environmental remediation associated with the discharge of crude oil on July 1, 2007 at the Coffeyville refinery.
Environmental Insurance
We 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.policy. The policy includes business interruption coverage, subject to a 5-day waiting period deductible. This insurance expires on March 1, 2016 and is expected to be renewed without any material changes in terms.coverage. The policy insures any location owned, leased or rented or operated by the Company, including the Coffeyville refinery, theand Wynnewood refineryrefineries and the nitrogen fertilizer facility. The policy insures certain pollution conditions at or migrating from a covered location, certain waste transportation and disposal activities and business interruption.
In addition to the site pollution legal liability insurance policy, we maintain umbrella and excess casualty insurance policies having an aggregatewhich include sudden and occurrence limit of $200.0 million, subject to a self-insured retention of $2.0 million.accidental pollution coverage. This insurance provides coverage due to named perils for claims involving pollutants where the discharge is sudden and accidental and first commencedcommences at a specific day and time during the policy period. The casualty insurance policies, including umbrella and excess policies, expire on March 1, 2016 and are expected to be renewed or replaced by insurance policies containing materially equivalent sudden and accidental pollution coverage with no reduction in limits.
The site pollution legal liability policy and the pollution coverage provided in the casualty insurance policies are subject to retentions and deductibles and contain discovery requirements, reporting requirements, exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.
Safety, Health and Security Matters
We are subject to a number of federal and state laws and regulations related to safety, including the Occupational Safety and Health Act ("OSHA") and comparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
We operate a comprehensive safety, health and security program, with participation by employees at all levels of the organization. We have developed comprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely audit our programs and consider improvements in our management systems.
The Wynnewood refinery has been the subject of a number of OSHA inspections since 2006. As a result of these inspections, the Wynnewood refinery has entered into four OSHA settlement agreements in 2008, pursuant to which it has agreed to undertake certain studies, conduct abatement activities, and revise and enhance certain OSHA compliance programs. The remaining costs associated with implementing these studies, abatement activities and program revisions are not expected to exceed $1.0 million.
Refer to Part II, Item 8, Note 1315 ("Commitments and Contingencies"), "Wynnewood Refinery Incident" of this Report for further discussion of OSHA matters 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 OSHA guidelines for developing and maintaining a comprehensive PSM program. We will continue to audit our programs and consider improvements in our management systems as well as our operations.
Emergency Planning and Response. We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in our facilities. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.
Employees
As of December 31, 2015, 9682017, 959 employees were employed by the petroleum business, 149308 employees were employed by the nitrogen fertilizer business and 215173 employees were employed by the Company at our offices in Sugar Land, Texas and Kansas City, Kansas. The Nitrogen Fertilizer Partnership and the Refining Partnership each relies on the services of employees of CVR Energy and its subsidiaries pursuant to services agreements between each partnership, its general partner and CVR Energy. As of December 31, 2015,2017, all these employees are 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, 2015,2017, (i) the Coffeyville refinery employed 610353 of the petroleum business' employees, about 54%66% of whom wereare covered by a collective bargaining agreement. These employees are affiliatedagreement with five unions of the Metal Trades Department of the AFL-CIO ("Metal Trade Unions") and, which expires in March 2019, (ii) the petroleum business had 259 employees who work in crude transportation, about 32% of whom are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC ("United Steelworkers"). The petroleum business is a party to a collective bargaining agreement with the Metal Trade Unions covering union members who work directly at the Coffeyville refinery. The agreement, which expires in March 2019. In addition, a collective bargaining agreement with the United Steelworkers, which covers the balance of the petroleum business' unionized employees who work in crude transportation, expires in March 20172019 and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date.
As of December 31, 2015,date, and (iii) the Wynnewood refinery employed 317300 of the petroleum business' employees, about 59% of whom were representedare covered by the International Union of Operating Engineers. Thea collective bargaining agreement with the International Union of Operating Engineers, with respect to the Wynnewood refinerywhich expires in June 2017.2021.
As of December 31, 2017, the Coffeyville Fertilizer Facility employed 151 of our employees, of whom none were unionized.
As of December 31, 2017, the East Dubuque Facility employed 148 of our employees, about 64% of whom were represented by the International Union of United Automobile, Aerospace, and Agricultural Implement Workers under a three-year collective bargaining agreement that expires in October 2019.
Available Information
Our 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 all amendments to those reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), are available free of charge through our website under "Investor Relations," as soon as reasonably practicable after the electronic filing or furnishing of these reports is made with the Securities and Exchange Commission (the "SEC"). In addition, our Corporate Governance Guidelines, Codes of Ethics and Business Conduct and Charters of the Audit Committee, the Nominating and Corporate Governance Committee and the Compensation Committee of the Board of Directors are available on our website. These guidelines, policies and charters are also available in print without charge to any stockholder requesting them. We do not intend for information contained in our website to be part of this Report.
Trademarks, Trade Names and Service Marks
This Report may include our and our affiliates' trademarks, including the CVR Energy logo, Coffeyville Resources, the Coffeyville Resources logo, the CVR 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 States Patent and Trademark Office. This Report may also contain trademarks, service marks, copyrights and trade names of other companies.
Item 1A. Risk Factors
You should carefully consider each of the following risks together with the other information contained in this Report and all of the information set forth in our filings with the SEC. If any of the following risks and uncertainties develops into actual events, our business, financial condition or results of operations could be materially adversely affected.
Risks Related to the Petroleum Business
The 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 oil and 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 a variety of factors including fluctuations in prices of crude oil, other feedstocks and refined products. Continued future volatility in refining industry margins may cause a decline in the petroleum business' results of operations, since the margin between refined product prices and crude oil and other feedstock prices may 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 prices on 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 in refined 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 not produce any crude oil and must purchase all of the crude oil it refines. Crude oil differentials can fluctuate significantly based upon overall economic and crude oil market conditions. Adverse changes in crude oil differentials can adversely impact refining margins, earnings and cash flows. In addition, the petroleum business' purchases of crude oil, although based on WTI prices, have historically been at a discount to WTI because of the proximity of the refineries to the sources, existing logistics infrastructure and quality differences. Any change in the sources of crude oil, infrastructure or logistical improvements or quality differences could result in a reduction of the petroleum business' historical discount to WTI and may result in a reduction of the petroleum 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, in turn, generate excess capacity. In addition, the expansion and construction of refineries domestically and globally can increase refined fuel production capacity. Excess capacity can adversely impact refining margins, earnings and cash flows. The Arabian Gulf and Far East regions have added refining capacity 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 2014 expanded 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 prices have 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 associated with 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 crude oil it gathers, through the Vitol Agreement. The Vitol Agreement was amended and restated on August 31, 2012 to include the provision of crude oil intermediation services to the Wynnewood refinery. The agreement, which currently extends through December 31, 2016,2018, minimizes the amount of in-transit inventory and mitigates crude oil pricing risk by ensuring pricing takes place close to the time the crude oil is refined and the yielded products are sold. If the petroleum business were required to obtain its crude oil supply without the benefit of a supply intermediation agreement, its exposure to crude oil pricing risk may increase, despite any hedging activity in which it may engage, and its liquidity could be negatively impacted due to increased inventory, potential need to post letters of credit and negative impacts of market volatility. There is no assurance that the petroleum business will be able to renew or extend the Vitol Agreement beyond December 31, 2016.2018.
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 purchased additional crude oil to be refined into liquid fuels in 2015.2017. In 2015,2017, the Coffeyville refinery purchased an additional 65,000approximately 75,000 to 70,00080,000 bpd of crude oil while the Wynnewood refinery purchased approximately 45,00035,000 to 50,00040,000 bpd of crude oil. The Wynnewood refinery has historically acquired most of its crude oil from Texas and Oklahoma with smaller amounts purchased from other regions. TheIn 2017, the Coffeyville refinery and Wynnewood refinery obtained a portion of its non-gathered crude oil, approximately 23% and 1%12%, respectively, in 2015, from Canada. The actual amount of Canadian crude oil the petroleum business purchases is dependent on market conditions and will vary from year to year. The petroleum business is subject to the political, geographic, and economic risks attendant to doing business with Canada. Disruption of production for any reason could have a material impact on the petroleum business. In the event that 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 may only 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 of operations 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, its inventory 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 petroleum business would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase its costs and result in lower production levels and profitability. Similarly, if a major refined fuels pipeline becomes inoperative, the petroleum business would be required to keep refined fuels in inventory or supply refined fuels to its customers through an alternative pipeline or by additional tanker trucks, which could increase the petroleum 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 we operate and other local adverse conditions. The location of its refineries also creates the risk of increased transportation costs should the supply/demand balance 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 markets its refined products in a relatively limited geographic area. As a result, it is more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect its operating area could also materially adversely affect its revenues and cash flows. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil.
Should the supply/demand balance shift in 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 thus incur considerably higher transportation costs, resulting in lower refining margins, if any.
If sufficient RINs are unavailable for purchase or if the petroleum business has to pay a significantly higher price for RINs, or if the petroleum business is otherwise unable to meet the EPA's Renewable Fuels Standard (RFS)RFS mandates, the petroleum business' financial condition and results of operations could be materially adversely affected.
Pursuant to the Energy Independence and Security Act of 2007, theThe EPA has promulgated the Renewable Fuel StandardsStandard ("RFS"), which requires refiners to either blend "renewable fuels," such as ethanol and biodiesel, into their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels that refineries like Coffeyville and Wynnewood are obligated to blend into their finished petroleum products is adjusted annually.annually by the EPA. The petroleum business is not able to blend the substantial majority of its transportation fuels, andso it has to purchase RINs on the open market as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. The price of RINs has been extremely volatile as the EPA's proposed renewable fuel volume mandates approached and exceeded the "blend wall." The blend wall refers to the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.
OnIn December 14, 2015, 2016, and 2017, the EPA published in the Federal Register a final rulerules establishing the renewable fuel volume mandates for 2014, 20152016, 2017, and 2016,2018, and the biomass-based diesel mandatevolume mandates for 2017.2017, 2018, and 2019, respectively. The volumes included in the EPA's final rule increaserules increased each year, but arewere lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authorityauthorities to lower the volumes, but its decision to do so has beenfor the 2014-2016 compliance years was challenged in the U.S. Court of Appeals for the District of Columbia Circuit.Circuit ("D.C. Circuit"). In addition, inJuly 2017, the final rule establishingD.C. Circuit vacated the EPA’s decision to reduce the renewable volume obligationsobligation for 2014-20162016 under one of its waiver authorities, and bio-mass based dieselremanded the rule to the EPA for 2017,further reconsideration. The EPA has not yet re-proposed the 2016 renewable volume obligations. The EPA also has articulated a policy tothat high RINs prices incentivize additional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs.infrastructure.
The petroleum business cannot predict the future prices of RINs or waiver credits. The price of RINs has been extremely volatile and has increased over the last year. Additionally, the cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed at the refineries and downstream terminals, all of which can vary significantly from period to period. However, the costs to obtain the necessary number of RINs and waiver credits could be material, if the price for RINs continues to increase.increases. Additionally, because the petroleum business does not produce renewable fuels, 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 economy standards, 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 a significantly higher price for RINs or if the petroleum business is otherwise unable to meet the EPA's RFS mandates, its business, financial condition and results 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 or other 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 petroleum business may be unable to compete effectively with competitors within and outside of the industry, which could result in reduced profitability. The petroleum 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 oil feedstocks. It does not have a retail business and therefore is dependent upon others for outlets for its refined products. It does not have long-term arrangements (those exceeding more than a twelve-month period) for much of its output. Many of its competitors obtain significant portions of their crude oil and other feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.
A number of the petroleum business' competitors also have materially greater financial and other resources than it does. These competitors may have a greater ability to bear the economic risks inherent in all aspects of the refining industry. An expansion or upgrade of 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 may add additional competitive pressure.pressure on the petroleum business.
In addition, the petroleum business competes with other industries that provide alternative means to satisfy the energy and fuel requirements of its industrial, commercial and individual customers. There are presently significant governmental incentives and consumer pressures to increase the use of alternative fuels in the United States. The more successful these alternatives become as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the negative impact on pricing and demand for the petroleum business' products and profitability.
Changes in the petroleum business' credit profile may affect its relationship with its suppliers, which could have a material adverse effect on its liquidity and 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 to shorten 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 and its ability to make payments to its
suppliers. 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 adversely affect 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 entersmay enter into commodity derivatives contracts to mitigate crack spread risk with respect to a portion of its expected refined products production. However, its hedging arrangements may fail to fully achieve this objective for a variety of reasons, including its failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of its hedging arrangements to produce the anticipated results. The petroleum business may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit its ability to benefit from favorable changes in margins. In addition, the petroleum business' hedging activities may expose it to the risk of financial loss in certain circumstances, 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 hedging arrangement;
accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect its refinery 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' financial results 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 associated with its business.
The U.S. Congress has adopted the Dodd-Frank Act, comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the petroleum business, that participate in that market, and requires the Commodities Futures Trading Commission ("CFTC") to, among other things, institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The Dodd-Frank Act and implementing rules and regulations also require certain swap participants to comply with, among other things, certain margin requirements and clearing and trade-execution requirements in connection with certain derivative activities. The rulemaking process is still ongoing, and the petroleum business cannot predict the ultimate outcome of the rulemakings. New regulations in this area may result in increased costs and cash collateral requirements for derivative instruments the petroleum 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 may become 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 fund capital expenditures. Increased volatility may make the petroleum business less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices. If the Dodd-Frank Act and any new regulations result in lower commodity prices, the petroleum business' revenues could be adversely affected. Any of these consequences could adversely affect the petroleum business' financial condition and results 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 charged to 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 in periods that differ from when the underlying hedged items (i.e., gross margins) are reflected in its income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of the petroleum business' operational performance.
Existing design, operational, and maintenance issues associated with acquisitions may not be identified immediately and may require unanticipated capital expenditures that could adversely impact our financial condition, results of operations or cash flows.
Our due diligence associated with acquisitions or joint ventures may result in our assuming liabilities associated with unknown conditions or deficiencies, as well as known but undisclosed conditions and deficiencies, where we may have limited, if any, recourse for cost recovery. Such conditions and deficiencies may not become evident until sometime after cost recovery provisions, if any, have expired.
The petroleum business must make substantial capital expenditures on its refineries and other facilities to maintain their reliability and efficiency. If the petroleum business is unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in project 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 petroleum business' existing facilities and equipment, could have a material adverse effect on the petroleum business' financial condition, results of operations or cash flows. 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 the petroleum 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
nonperformancenon-performance 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 significant capital expenditures and expenses to keep it operating at optimum efficiency. For example,These refineries generally require facility turnaround every four to five years. The length of the petroleum business incurred approximately $101.5 million withturnaround is contingent upon the scope of work to be completed. The first phase of the Coffeyville refineryrefinery's most recent turnaround was completed in mid-NovemberNovember 2015 and incurredat a total cost of approximately $102.5 million associated with$102.2 million. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016 at a total cost of approximately $31.5 million. The next turnaround scheduled for the Wynnewood refinery is being performed as a two phase turnaround. The first phase of its current turnaround was completed in December 2012. During the outageNovember 2017 at the Coffeyville refinery as a resulttotal cost of approximately $67.4 million. The second phase of the isomerization unit fireWynnewood turnaround is expected to occur in 2019. In addition to the third quarter of 2014, the petroleum business accelerated certain planned 2015two phase turnaround, activities and incurred approximately $5.5 million in turnaround expenses. During the fluid catalytic cracking unit ("FCCU") outage at the Wynnewood refinery in the fourth quarter of 2014, the petroleum business accelerated certain planned turnaround activities andin the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. The petroleum business incurred approximately $1.3$13.0 million inof major scheduled turnaround expenses. These costs do not result in increases in unit capacities, but rather are focused on trying to maintain safe, reliable operations. The second phase of the Coffeyville refinery turnaround is scheduled 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 was incurred in the fourth quarter of 2015). The next turnaroundexpenses for the Wynnewood refinery is scheduled to occur in the spring of 2017.hydrocracker.
Any one or more of these occurrences noted above could have a significant impact on the petroleum business. If the petroleum business was unable to make 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, may expose 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 sourcing advantage through additional investments in gathering and logistics assets. If it is able to successfully increase the effectiveness of the supporting gathering and logistics assets, including the crude oil gathering
operations, the petroleum business believes it will be able to enhance crude oil sourcing flexibility and reduce related crude oil purchasing and delivery costs. However, the acquisition of infrastructure assets to expand crude oil gathering may expose the petroleum business to risks in the future that are different than or incremental to the risks it faces with respect to its refineries and existing gathering and logistics assets. The storage and transportation of liquid hydrocarbons, including crude oil and refined products, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment, operational safety and related matters. Compliance with these laws and regulations could adversely affect the petroleum business' operating results, financial condition and cash flows. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibit the 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 of releasing 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, if the 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 is subject to regulation by the U.S. Department of Transportationfederal and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent fuel-economy environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder or electronic logging devices or limits on vehicle weight and size.
To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Furthermore, from time to time, various legislative proposals are introduced, such as proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase the petroleum business' costs or adversely impact the recruitment 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 they will apply to the petroleum business and its operations.
Risks Related to the Nitrogen Fertilizer Business
The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile, and the nitrogen fertilizer business has experienced substantial downturns in the past. Cycles in demand and pricing could potentially expose the nitrogen fertilizer business to significant fluctuations in its operating and financial results and have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
The nitrogen fertilizer business is exposed to fluctuations in nitrogen fertilizer demand in the agricultural industry. These fluctuations historically have had and could in the future have significant effects on prices across all nitrogen fertilizer products and, in turn, our results of operations, financial condition and 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 of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, governmental policies and weather conditions, which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which the nitrogen fertilizer business bases production, customers may acquire nitrogen fertilizer products from competitors, and the profitability of the nitrogen fertilizer business will be negatively impacted. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory that will have to be stored or liquidated.
Demand for nitrogen fertilizer products is dependent on demand for crop nutrients by the global agricultural industry. The international market for nitrogen 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, foreign agricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign markets, changes in the hard currency demands of certain countries and other regulatory policies of foreign governments, as well as the laws and policies of the United States affecting foreign trade and investment. Nitrogen-based fertilizers remain solidly in demand, driven by a growing world population, changes in dietary habits and an expanded use of corn for the production of ethanol. Supply is affected by available capacity and operating rates, raw material costs, government policies and global trade. A decrease in nitrogen fertilizer prices would have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
The costs associated with operating the nitrogen fertilizer plant are largely fixed.plants include significant fixed costs. If nitrogen fertilizer prices fall below a certain level, the nitrogen fertilizer business may not generate sufficient revenue to operate profitably or cover its costs.costs and ability to make distributions will be adversely impacted.
Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose costs are therefore largely variable, the nitrogen fertilizer businessCoffeyville Fertilizer Facility has largely fixed costs. In addition, while less than the Coffeyville Fertilizer Facility, the East Dubuque Facility has a significant amount of fixed costs. As a result of the fixed cost nature of its operations, downtime, interruptions or low productivity due to reduced demand, adverse weather conditions, equipment failure, a decrease in nitrogen fertilizer prices or other causes can result in significant operating losses, which couldwould have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and ability to make cash flows.distributions.
Continued low natural gas prices could impact the nitrogen fertilizer business'Coffeyville Fertilizer Facility's relative competitive position when compared to other nitrogen fertilizer producers.
Most nitrogen fertilizer manufacturers rely on natural gas as their primary feedstock, and the cost of natural gas is a large component of the total production cost for natural gas-based nitrogen fertilizer manufacturers. Low natural gas prices benefit the nitrogen fertilizer business' competitors and disproportionately impact our operations by making the nitrogen fertilizer business less competitive with natural gas-based nitrogen fertilizer manufacturers. ContinuedAlthough our nitrogen fertilizer business diversified its operations in connection with the acquisition of the East Dubuque Facility, which primarily relies on natural gas feedstock, continued low natural gas prices could impair the nitrogen fertilizer business' ability of the Coffeyville Fertilizer Facility to compete with other nitrogen fertilizer producers who utilize natural gas 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 nitrogen fertilizer business' results of operations, financial condition and ability to make cash flowsdistributions.
The market for natural gas has been volatile. Natural gas prices are currently at a relative low point. An increase in natural gas prices could impact the East Dubuque Facility's relative competitive position when compared to other foreign and domestic nitrogen fertilizer producers, and if prices for natural gas increase significantly, our nitrogen fertilizer business may not be able to economically operate the East Dubuque Facility.
The operation of the East Dubuque Facility with natural gas as the primary feedstock exposes the nitrogen fertilizer business.business to market risk due to increases in natural gas prices, particularly if the price of natural gas in the United States were to become higher than the price of natural gas outside the United States. An increase in natural gas prices would impact the East Dubuque Facility's operations by making it less competitive with competitors who do not use natural gas as their primary feedstock, and could therefore have a material adverse impact on the nitrogen fertilizer business' results of operations, financial condition and cash flows. In addition, if natural gas prices in the United States were to increase relative to prices of natural gas paid by foreign nitrogen fertilizer producers, this may negatively affect the nitrogen fertilizer business' competitive position in the corn belt and thus have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
The profitability of operating the East Dubuque Facility is significantly dependent on the cost of natural gas, and the East Dubuque Facility operated at certain times, and could operate in the future, at a net loss. Local factors may affect the price of natural gas available to the nitrogen fertilizer business, in addition to factors that determine the benchmark prices of natural gas. Since the nitrogen fertilizer business expects to purchase natural gas on the spot market and to enter into forward purchase contracts. Since we expect to purchase a portion of our natural gas for use in the East Dubuque Facility on the spot market, the Nitrogen Fertilizer business remains susceptible to fluctuations in the price of natural gas in general and in local markets in particular. The nitrogen fertilizer business also expect to use short-term, fixed supply, fixed price forward purchase contracts to lock in pricing for a portion of our natural gas requirements. The nitrogen fertilizer business' ability to enter into forward purchase contracts is dependent upon creditworthiness and, in the event of a deterioration in the nitrogen fertilizer business' credit, counterparties could refuse to enter into forward purchase contracts on acceptable terms. If the nitrogen fertilizer business is unable to enter into forward purchase contracts for the supply of natural gas, the nitrogen fertilizer business would need to purchase natural gas on the spot market, which would impair its ability to hedge exposure to risk from fluctuations in natural gas prices. If the nitrogen fertilizer business enters into forward purchase contracts for natural gas, and natural gas prices decrease, then its cost of sales could be higher than it would have been in the absence of the forward purchase contracts.
Any interruption in the supply of natural gas to the nitrogen fertilizer business' East Dubuque Facility through Nicor Inc. ("Nicor") could have a material adverse effect on the nitrogen fertilizer business' results of operations and financial condition.
Our nitrogen fertilizer business' East Dubuque operations depend on the availability of natural gas. East Dubuque has an agreement with Nicor pursuant to which it accesses natural gas from the ANR Pipeline Company and Northern Natural Gas pipelines. East Dubuque's access to satisfactory supplies of natural gas through Nicor could be disrupted due to a number of causes, including volume limitations under the agreement, pipeline malfunctions, service interruptions, mechanical failures or other reasons. The agreement extends through October 31, 2019. Upon expiration of the agreement, East Dubuque may be unable to extend the service under the terms of the existing agreement or renew the agreement on satisfactory terms, or at all. Any disruption in the supply of natural gas to our East Dubuque Facility could restrict our ability to continue to make products at the facility. In the event it need to obtain natural gas from another source, it would need to build a new connection from that source to the East Dubuque Facility and negotiate related easement rights, which would be costly, disruptive and/or may be unfeasible. As a result, any interruption in the supply of natural gas through Nicor could have a material adverse effect on our nitrogen fertilizer business' results of operations and financial condition.
Any decline in U.S. agricultural production or limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effect on 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 industry can be affected by a number of factors, including weather patterns and field conditions, current and projected grain inventories and prices, domestic and international 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 insurance program in its place. As part of the conservation title of the 2014 Farm Bill, agricultural producers must meet a minimum standard of environmental protection in order to receive federal crop insurance on sensitive lands. The 2014 Farm Bill also discourages producers from converting native grasslands to farmland by limiting crop insurance subsidies for the first few years for newly converted lands. These changes may have a negative impact on fertilizer sales and 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 fertilizer products, may also directly or indirectly influence the number of acres planted, the mix of crops planted and the use of fertilizers for particular agricultural applications. Developments in crop technology, such as nitrogen fixation (the conversion of atmospheric nitrogen into compounds that plants can assimilate), could also reduce the use of chemical fertilizers and adversely affect the demand for nitrogen fertilizer. In addition,s from time to time various state legislatures have considered limitations on the use and application of chemical fertilizers due to concerns about the impact of these products on the environment. Unfavorable state and federal governmental policies could negatively affect nitrogen fertilizer prices and therefore have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
A major factor underlying the current high level of demand for nitrogen-based fertilizer products is the production of ethanol. A decrease in ethanol production, an increase in ethanol imports or a shift away from corn as a principal raw material used to produce ethanol could have a material adverse effect 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 production of 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 of federal statutes and regulations, and is made significantly more competitive by various federal and state incentives and mandated usage of renewable fuels pursuant to the RFS. To date, the RFS has been satisfied primarily with fuel ethanol blended into gasoline. However, a number of factors, including the continuing "food versus fuel" debate and studies showing that expanded ethanol usage may increase the level of greenhouse gases in the environment as well as 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 whole or 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 producers than current incentive programs.
Recently,In late 2013, the volume of ethanol required byEPA recognized that the RFS standards to be blended into transportation fuel has approachedfuels market had reached the "blend wall."“blend wall” for ethanol. The blend wall isrefers to the maximum amount ofaggregate limit to which ethanol that can be blended into the transportation fuel supply because of limitations like the ability of cars to use higher ethanol blended fuelsgasoline, and limitations on the blending and distribution infrastructure. The blend wall is generally considered to be reached when more thana gallon of transportation fuel contains 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.On December 14, 2015,volume. As a result, since 2013, 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 EPA's final rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPAhas used its waiver authorityauthorities to set lower renewable volume obligations than those mandated by the RFS, though those volumes but its decisionstill generally increase year-over-year as demand for transportation fuel also increases. Even so, the most recent volume mandates have resulted in or are expected to do so has been challengedresult in the U.S. Court of Appeals for the District of Columbia Circuit by corn growers and renewable fuels producers. The renewable fuel volume mandate for 2016 is expected to breachbeing blended in volumes that exceed the ethanol blend wall, forcing the use of higher ethanol 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 the final rule establishing the renewable volume obligations for 2014-2016 and bio-mass based diesel for 2017, thefuel. The EPA articulatedcontinues to articulate a policy to incentivize additional investments in renewable fuel blending and distribution infrastructure by increasing the price of RINs.infrastructure. Any substantial decrease in future renewable volume obligations under the RFS could have a material adverse effect on ethanol production in the United States, which could have a material adverse effect on the nitrogen fertilizer business'our 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 that a portion of the overall RFS renewable fuel mandate to comecomes from advanced biofuels, including cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, and energy crops (plants grown for use to make biofuels or directly exploited for their energy content) and biomass-based diesel. In addition, there is a continuing 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 may decrease significantly, which could reduce demand for nitrogen fertilizer products and have an adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. This potential impact on the demand for nitrogen fertilizer products, however, could be slightly offset by the potential 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 fertilizer producers.
The nitrogen fertilizer business is subject to intense price competition from both U.S. and foreign sources, including competitors operating in the Middle East, the Asia-Pacific region, the Caribbean, Russia and the Ukraine. Fertilizers are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. Increased global supply may put downward pressure on fertilizer prices. Furthermore, in recent years the price of nitrogen fertilizer in the United States has been substantially driven by pricing in the global fertilizer market. The nitrogen fertilizer business competes with a number of U.S. producers and producers in other countries, including state-owned and government-subsidized entities. Some competitors have greater total resources and are less dependent on earnings from fertilizer sales, which makesmake them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. Increased domestic supply may put downward pressure on fertilizer prices. Additionally, the nitrogen fertilizer business' competitors utilizing different corporate structures may be better able to withstand lower cash flows than the nitrogen fertilizer business can as a limited partnership. The nitrogen fertilizer business'
competitive position could suffer to the extent it is not able to expand its resources either through investments in new or existing operations or through acquisitions, 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 of operations, 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 other in the fall. The strongest demand for nitrogen fertilizer products typically occurs during the spring planting season. In contrast, the nitrogen fertilizer business and other nitrogen fertilizer producers generally produce products throughout the year. As a result, the nitrogen fertilizer business and its customers generally build inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. The seasonality of nitrogen fertilizer demand results in sales volumes and net sales being highest during the North American spring season and working capital requirements typically 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 its competitors, which would negatively impact profitability. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory 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 and other factors. As a consequence of such seasonality, it is expected that the distributions we receive from the nitrogen fertilizer business will be volatile and will vary quarterly and annually.
Adverse weather conditions during peak fertilizer application periods may have a material adverse effect on the nitrogen fertilizer business' results of operations, 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. The nitrogen fertilizer business' quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. For example, the nitrogen fertilizer business generates greater net sales and operating income in the first half of the year, which is referred to herein as the planting season, compared to the second half of the year. Accordingly, an adverse weather pattern affecting agriculture in these regions or during the planting season could have a negative effect on fertilizer demand, which could, in turn, result in a material decline in the nitrogen fertilizer business' net sales and margins and otherwise have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. The nitrogen fertilizer business' quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. As a result, it is expected that the nitrogen fertilizer business' distributions to holders of its common units (including us) will be volatile and will vary quarterly and annually.
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.
Our nitrogen fertilizer business is seasonal. Farmers tend to apply nitrogen fertilizer during two short application periods, one in the spring and the other in the fall. In contrast, the nitrogen fertilizer business and other nitrogen fertilizer producers generally produce products throughout the year. As a result, our nitrogen fertilizer business and our customers generally build inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. Variations in the proportion of product sold through prepaid sales contracts and variations in the terms of such contracts can increase the seasonal volatility of our nitrogen fertilizer business' cash flows and cause changes in the patterns of seasonal volatility from year-to-year.
In most instances, our nitrogen fertilizer business’ East Dubuque customers take delivery of nitrogen products at the East Dubuque Facility. Customers arrange and pay to transport our nitrogen products to their final destinations. At our nitrogen fertilizer business’ East Dubuque Facility, inventories are accumulated to allow for customer to take delivery to meet the seasonal demand, which require significant storage capacity. The accumulation of inventory to be available for seasonal sales creates significant seasonal working capital requirements.
Most of our nitrogen fertilizer business’ Coffeyville Fertilizer Facility nitrogen products are delivered by railcar to its customer’s storage facilities. Therefore, our nitrogen fertilizer business is less dependent on storage capacity at the Coffeyville Fertilizer Facility and, as a result, experiences lower seasonal fluctuations as compared to the East Dubuque Facility. The seasonality of nitrogen fertilizer demand results in our nitrogen fertilizer business’ sales volumes and net sales being highest during the North American spring season and its working capital requirements typically being highest just prior to the start of the spring season.
The degree of seasonality of our nitrogen fertilizer business can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of this seasonality, it is expected that distributions we receive from our nitrogen fertilizer business will be volatile and will vary quarterly and annually.
The nitrogen fertilizer business' operations are dependent on third-party suppliers, including the following: Linde, which owns an air separation plant that provides oxygen, nitrogen and compressed dry air to its facility, andthe Coffeyville Fertilizer Facility; the City of Coffeyville, which supplies the nitrogen fertilizer businessCoffeyville Fertilizer Facility with electricity; and Jo-Carroll Energy, Inc. ("Jo-Carroll Energy") which supplies the East Dubuque Facility with electricity. A deterioration in the financial condition of a third- party supplier, a mechanical problem with the air separation plant supplying the Coffeyville Fertilizer Facility, or the inability of a third-party supplier to perform in accordance with its contractual obligations could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
The operationsOperations of the nitrogen fertilizer businessbusiness' Coffeyville Fertilizer Facility depend in large part on the performance of third-party suppliers, including Linde for the supply of oxygen, nitrogen and compressed dry air, and the City of Coffeyville for the supply of electricity. With respect to Linde, the operations of the Coffeyville Fertilizer Facility could be adversely affected if there were a deterioration in Linde's financial condition such that the operation of the air separation plant located adjacent to the nitrogen fertilizer plantCoffeyville Fertilizer Facility was disrupted. Additionally, this air separation plant in the past has experienced numerous short-term interruptions, causing interruptions in our gasifier operations. With respect to electricity, in 2010, theour nitrogen fertilizer business entered intois party to an amended and restated electric services agreement with the City of Coffeyville, Kansas, which gives the nitrogen fertilizer businessallows for an option to extend the term of such agreement through June 30, 2024.
Our nitrogen fertilizer business' East Dubuque Facility operations also depend in large part on the performance of third-party suppliers, including, Jo-Carroll Energy for the purchase of electricity. We entered into a utility service agreement with Jo-Carroll Energy, which terminates on May 31, 2019 and will continue year-to-year thereafter unless either party provides 12-month advance written notice of termination.
Should Linde, the City of Coffeyville, Jo-Carroll Energy or any of itsour other third-party suppliers fail to perform in accordance with existing contractual arrangements, or should our nitrogen fertilizer business otherwise lose the service of any third-party suppliers, our nitrogen fertilizer business' operations (or a portion of our operations) could be forced to halt. Alternative
sources of supply could be difficult to obtain. Any shutdown of operations at theour nitrogen fertilizer plant,business' operations (or a portion of our operations), even for a limited period, could have a material adverse effect on theour nitrogen fertilizer business' results of operations, financial condition and ability to make cash flows.distributions.
The nitrogen fertilizer business' results of operations, financial condition and ability to make cash flowsdistributions may be adversely affected by the supply and price levels of pet coke. Failure by the Refining Business to continue to supply the Coffeyville Fertilizer Facility with pet coke (to the extent third-party pet coke is unavailable only at higher prices), or the Refining Business imposition of an obligation to provide it with security for the Nitrogen Fertilizer business' payment obligations, could negatively impact results of operations
The profitability of the nitrogen fertilizer businessbusiness' Coffeyville Fertilizer Facility is directly affected by the price and availability of pet coke obtained from the Refining Business' Coffeyville, Kansas crude oil refinery pursuant 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 used by the nitrogen fertilizer businessCoffeyville Fertilizer Facility in the manufacture of nitrogen fertilizer products. If pet coke costs increase, the nitrogen fertilizer business may not be able to increase its prices to recover these increased costs, because market prices for nitrogen fertilizer products are not correlated with pet coke prices.
TheBased on nitrogen fertilizer business current output, it obtains most (over 70% on average during the last five years) of the pet coke needed for the Coffeyville Fertilizer Facility from the Refining Business' adjacent crude oil refinery, and procure the remainder on the open market. The price that is paid to the Refining Business for pet coke is based on the lesser of a pet coke price derived from the price received for UAN (subject to a UAN-based price ceiling and floor) and a pet coke index price. In most cases, the price paid to the Refining Business will be lower than the price which would be otherwise paid to third parties. Pet coke prices could significantly increase in the future. Should the Refining Business fail to perform in accordance with the existing agreement, the fertilizer business would need to purchase pet coke from third parties on the open market, which could negatively impact its results of operations to the extent third-party pet coke is unavailable or available only at higher prices.
The Coffeyville Fertilizer Facility may not be able to maintain an adequate supply of pet coke. In addition, it could experience production delays or cost increases if alternative sources of supply prove to be more expensive or difficult to obtain. The nitrogen fertilizer business currently purchases 100% of the pet coke the Coffeyville refinery produces. Accordingly, if the nitrogen fertilizer business increases production, it will be more dependent on pet coke purchases from third-party suppliers at open market prices. The nitrogen fertilizer business is party to a pet coke supply agreement with HollyFrontier Corporation. The term of this agreement ends in December 2016.2018. There is no assurance that the nitrogen fertilizer business would be able to purchase pet coke 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 uncertainties beyond its control that may have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.ability to make distributions.
The nitrogen fertilizer business relies on railroad and trucking companies to ship finished products to its customers.customers of the Coffeyville Fertilizer Facility. The nitrogen fertilizer business also leases railcars from railcar owners in order to ship its finished products. Additionally, although customers of the East Dubuque Facility generally pick up products at the facility, the facility occasionally rely on barge, truck and railroad companies to ship products to customers. These transportation operations, equipment and services are subject to various hazards, including extreme weather conditions, work stoppages, delays, spills, derailments and other accidents and other operating hazards. For example, barge transport can be impacted by lock closures resulting from inclement weather or surface conditions, including fog, rain, snow, wind, ice, strong currents, floods, droughts and other unplanned natural phenomena, lock malfunction, tow conditions and other conditions. Further, the limited number of towing companies and barges available for ammonia transport may also impact the availability of transportation for our nitrogen fertilizer business' products.
These transportation operations, equipment and services are also subject to environmental, safety and other regulatory oversight. Due to concerns related to 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 of these services or equipment could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and ability to make cash flows.distributions.
Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving ammonia or other products the nitrogen fertilizer business produces or transports that cause severe damage to property or injury to the environment and human health could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and ability to make cash flows.distributions. In addition, the costs of transporting ammonia could increase significantly in the future.
The nitrogen fertilizer business manufactures, processes, stores, handles, distributes and transports ammonia, which can be very volatile and extremely hazardous. Major accidents or releases involving ammonia could cause severe damage or injury to property, the environment and human health, as well as a possible disruption of supplies and markets. Such an event could result in civil lawsuits, fines, penalties and regulatory enforcement proceedings, all of which could lead to significant liabilities. Any damage or injury to persons, equipment or property or other disruption of the ability of the nitrogen fertilizer business to produce or distribute its products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure its assets, which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and ability to make cash flows.distributions. The nitrogen fertilizer facilityCoffeyville Fertilizer Facility and East Dubuque Facility periodically experiences minor releases of ammonia related to leaks from its equipment. Similar events may occur in the future and could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.future.
In addition, the nitrogen fertilizer business may incur significant losses or costs relating to the operation of railcars used for the purpose of carrying various products, including ammonia. Due to the dangerous and potentially toxichazardous nature of the cargo, in particular ammonia, on board railcars, a railcar accident may result in fires, explosions and pollution. These circumstances may
result in sudden, severe damage or injury to property, the environment and human health. In the event of pollution, the nitrogen fertilizer business may be held 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 accidents involving ammonia and other products the nitrogen fertilizer business produces or transports may result in the nitrogen fertilizer business or us being named as a defendant in lawsuits asserting claims for large amounts of damages, which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and ability to make cash flows.distributions.
Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. Ammonia is most typically transported by pipeline and railcar. A number of initiatives are underway in the railroad and chemical industries that may result in changes to railcar design in order to minimize railway accidents involving hazardous materials. In addition, in the future, laws may more severely restrict or eliminate the ability of the nitrogen fertilizer business to transport ammonia via railcar. If any railcar design changes are implemented, or if accidents involving hazardous freight 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 adverse impact 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 fertilizer business' products. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit the ability of the nitrogen fertilizer business to market and sell its products to end users. From time to time, various state legislatures have proposed bans or other limitations on fertilizer products. The EPA is encouraging states to adopt state-wide numeric water quality criteria for total nitrogen and total phosphorus, which are present in the nitrogen fertilizer business' fertilizer products. A number of states have adopted or proposed numeric nutrient water quality criteria for nitrogen and 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 fertilizer business' marketing areas, it could result in decreased demand for its products and have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
New regulations concerning the transportation, storage and handling of hazardous chemicals, risks of terrorism and the security of chemical manufacturing 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 with our operations may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. Targets such as chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. The chemical industry has responded to the issues that arose in response to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of chemical industry facilities and the transportation of hazardous chemicals in the United States. For example, in May 2015, the U.S. Department of Transportation promulgated a regulation setting standings for rail tanks carrying transporting flammable liquids. Future terrorist attacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition and ability to make cash distributions. The 2013 fertilizer plant explosion in West, Texas has generated consideration of more restrictive measures in the storage, handling and transportation of crop production materials.
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 of third parties for use in its business. In particular, the gasification process it usesused at the Coffeyville Fertilizer Facility to convert pet coke to high purity hydrogen for subsequent conversion to ammonia is licensed from an affiliate of General Electric.Electric Company. The license, which is fully paid, grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions and is integral to the operations of the nitrogen fertilizer facility.Coffeyville Fertilizer Facility. If this license or any other license agreementsagreement on which the nitrogen fertilizer business' operations rely, were to be terminated, licenses to alternative technology may not be available, or may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently-licensed technology may require substantial changes to manufacturing processes or equipment and may have a material adverse effect on the nitrogen fertilizer business' 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 theThe nitrogen fertilizer business may face claims of infringement that could interfere with its ability to use technology that is material to its business operations. Any litigation of this type whether successful or unsuccessful,related to third-party intellectual property rights could result in substantial costs and diversions of resources, either of which could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows. In the event a claim of infringement against the nitrogen 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 be prohibited 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 to obtain licenses to alternative technology adequate to substitute for the technology it can no longer use, or licenses for such alternative technology may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently licensed technology may require the nitrogen fertilizer business to make substantial changes to its manufacturing processes or equipment or to its products, and could have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
There can be no assurance that the transportation costs of the nitrogen fertilizer business' competitors will not decline.
TheOur nitrogen fertilizer plant isbusiness' nitrogen fertilizer plants are located within the U.S. farm belt, where the majority of the end users of its nitrogen fertilizer products grow their crops. Many of itsour nitrogen fertilizer business' competitors produce fertilizer outside of this region and incur greater costs in transporting their products over longer distances via rail, ships and pipelines. There can be no assurance that competitors' transportation costs will not decline or that additional pipelines will not be built, lowering the price at which competitors can sell their products, which would have a material adverse effect on the nitrogen fertilizer business' results of operations, financial condition and cash flows.
Risks Related to Our Entire Business
Instability and volatility in the capital, credit and commodity markets in the global economy could negatively impact our business, financial condition, results of operations and cash flows.
Our business, financial condition and results of operations could be negatively impacted by difficult conditions and volatility in the capital, credit and commodities markets and in the global economy. For example:
Although we believe the petroleum business has sufficient liquidity under its Amended and Restated ABL credit facility and the intercompany credit facility to operate both the Coffeyville and Wynnewood refineries, and that the nitrogen fertilizer business has sufficient liquidity under its revolvingABL credit facility to run the nitrogen fertilizer business, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all. Furthermore, the nitrogen fertilizer business' credit facility matures in April 2016 and there can be no assurance that it will be able to refinance its $125.0 million of 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 turn cause our stock price to drop.
The petroleum business' and nitrogen fertilizer business' credit facilities contain various covenants that must be complied with, and if either business 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 may enter 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 could result in decreased sales and earnings for us.
The refineries and nitrogen fertilizer facilityfacilities face significant risks due to physical damage hazards, environmental liability risk exposure, and unplanned or emergency partial or total plant shutdowns resulting in business interruptions. We could incur potentially significant costs to the extent there are unforeseen events which cause property damage and a material decline in production which are not fully insured. The commercial insurance industry engaged in underwriting energy industry risk is specialized and there is finite capacity; therefore, the industry may limit or curtail coverage, may modify the coverage provided or may substantially increase premiums in the future.
If any of our production plants, logistics assets, key pipeline operations serving our plants, or key suppliers sustains a catastrophic loss and operations are shutdown or significantly impaired, it would have a material adverse impact on our operations, financial condition and cash flows. In addition, the risk exposures we have at the Coffeyville, Kansas plant complex are greater due to production facilities for refinery and fertilizer production, distribution and storage 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 for an extended period of time as the result of one or more unforeseen events and circumstances, which may not be within our control, including:
major unplanned maintenance requirements
catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire, or natural disasters, including, floods, windstorms and other similar events;
labor supply shortages, or labor 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 of demolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition.
We have sustained losses over the past ten-year period at our plants,facilities, which are illustrative of the types of risks and hazards that exist. These losses or events resulted in costs assumed by us that were not fully insured due to policy retentions or applicable exclusions. These events 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, weWe are insured under casualty, environmental, property and business interruption insurance policies. The property and business interruption coverage has a combined policy limit of $1.25 billion. Thepolicies insure real and personal property, including property located at our Coffeyville and business interruption insurance policies contain limitsWynnewood refineries and sub-limits which insure all CVR Energyour related crude gathering and logistics assets. There is potential for a common occurrence to impact both the CVR Partners' nitrogen fertilizer plant in Coffeyville, Kansas and the Coffeyville refinery in which case the insurance limitations limits and applicable sub-limits would apply to all damages combined. Under this insurance program, there is a $10.0 million property damageThese policies are subject to limits, sub-limits, retention for all properties ($2.5 million in respect(financial and time-based) and deductibles. The application of the nitrogen fertilizer plant). For business interruption losses, the insurance program has a 45-day waiting period retention for any one occurrence. In addition, the insurance policies contain a schedule of sub-limits which apply to certain specific perils or areas of coverage. Sub-limits which may be of importance depending on the naturethese and extent of a particular insured occurrence are: flood, earthquake, contingent business interruption insuring key suppliers, pipelines and customers, debris removal, decontamination, demolition and increased cost of construction due to law and ordinance, and others. Suchother policy conditions limits and sub-limits could materially impact insurance recoveries and potentially cause us to assume losses which could impair earnings.
There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and there are risks associated with the commercial insurance industry reducing capacity, changing the scope of insurance coverage offered, and substantially increasing premiums due toresulting from highly adverse loss experience or other financial circumstances. Factors that impact insurance cost and availability include, but are not limited to: industry wide losses, natural disasters, specific losses incurred by us and thelow or inadequate investment returns earned by the insurance industry. If the supply of commercial insurance is curtailed due to highly adverse financial results, we may not be able to continue our present limits of insurance coverage or obtain sufficient insurance capacity to adequately insure our risks for property damage or business interruption.
Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.
Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous wastes. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns.
In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmental compliance could have a material adverse effect on our 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 of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approvals, limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval, limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due to the nature of our manufacturing and refining processes,process, there may be times when we are unable to meet the standards and terms and conditions of our permits, licenses and approvals due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities and accordingly our financial performance. For a discussion of environmental laws and regulations and their impact on our business and operations, please see "Business — Environmental Matters."
We could incur significant cost in cleaning up contamination at our refineries, terminals, fertilizer plantplants 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 plantplants or transportation of products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential clean-upcleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under CERCLA, and similar state statutes for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with facilities we currently own or operate (whether or not such contamination occurred prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal.
The potential penalties and clean-upcleanup costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we may incur liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability for personal injury, property damage, natural resource damage or for clean-upcleanup costs for the alleged migration of contamination or other hazardous substances from 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 Wynnewood refinery and the Coffeyville nitrogen fertilizer plant, have environmental contamination. We have assumed Farmland's responsibilities under certain administrative orders under the RCRA related to contamination at or that originated from the Coffeyville refinery and the Phillipsburg terminal. The Coffeyville refinery has agreed to assume liability for contamination that migrated from the refinery onto the nitrogen fertilizer plant property while Farmland owned and operated the properties. At the Wynnewood refinery, known areas of contamination have been partially addressed but corrective action has not been completed (refer to "RCRA Compliance Matters" in Part II, Item 8, Note 1315 ("Commitments and Contingencies") of this Report), and some portions of the Wynnewood refinery have not yet been investigated to determine whether corrective action is necessary.. If significant unknown liabilities are identified at or migrating from any of our facilities, that liability could have a material adverse effect on our results of operations, financial condition and cash flows and may not be covered by insurance.
We may incur future liability relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the treatment, transportation or disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation of contamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposal and the damages or costs in any such proceedings could be material.
We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
Our businesses hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Future expansion of our operations is predicated upon securing the necessary environmental or other permits or approvals. A decision by a government agency to deny or delay issuing a new or renewed material permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows. For example, WRC's OPDES permit has expired and is in the renewal process. The refinery timely submitted their renewal application; and therefore, the refinery is authorized to operate under expired permit terms and conditions until the state regulatory agency renews the permit. The renewal permit may contain different terms and conditions that would require unplanned or unanticipated costs.
Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows.
The EPA regulates GHG emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our GHG emissions to the EPA. In May 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new GHG emissions thresholds that determine when stationary sources, such as 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 review and 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 to regulate GHG emissions from petroleum refineries and electric utilities by November 2012. In September 2014, the EPA indicated that the petroleum refining sector risk rule, proposed in June 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for the EPA to regulate GHG emissions from petroleum refineries at this time. The final rule, which was published in the Federal Register on December 1, 2015, places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. In 2015, the EPA promulgated NSPS for carbon dioxide emissions from electric utilities, although the EPA announced in April 2017 that those NSPS were under review and may be suspended, revised or rescinded. Therefore, we expect that the EPA will not be issuing NSPS standards to regulate GHG from thepetroleum refineries at this time but that it may do so in the future.
DuringThe current administration has sought to implement a new or modified policy with respect to climate change. For example, the State of the Union address in each of the last three years, President Obama indicated thatadministration announced its intention to withdraw the United States should take actionfrom the Paris Climate Agreement, though the earliest possible effective date of withdrawal for the United States is November 2020. If efforts to address climate change. Atchange resume, at the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory GHG emission reduction, such as a nationwide cap-and-trade program. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.
In addition to potential federal legislation, a number of states have adopted regional greenhouse gasGHG initiatives to reduce carbon dioxide and other GHG emissions. In 2007, a group of Midwest states, including Kansas (where the Coffeyville refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementingthat implement the trading scheme before it becomes effective. To date, Kansas has taken no meaningful action to implement the accord, and it'sit is unclear whether Kansas intends to do so in the future.
Alternatively, the EPA may take further steps to regulate GHG emissions.emissions, although at this time it is unclear to what extent the EPA will pursue climate change regulation. The implementation of EPA regulations and/or the passage of federal or state climate change legislation may result in increased costs to (i)��operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any current or future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows.
In addition, climate change legislation and regulations may result in increased costs not only for our business but also users of our refined and fertilizer products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.
We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the proper design, operation and maintenance of our equipment. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to cybersecurity risks and other cyber incidents resulting in disruption.
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. We depend on information technology systems. In addition, we collect, process, and retain sensitive and confidential customer information in the normal course of business. Despite the security measures we have in place and any additional measures we may implement in the future, our facilities and systems, and those of our third-party service providers, could be vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, human errors, acts of vandalism or other events. Any disruption of our systems or security breach or event resulting in the misappropriation, loss or other unauthorized disclosure of confidential information, whether by us directly or our third-party service providers, could damage our reputation, expose us to the risks of litigation and liability, disrupt our business or otherwise affect our results of operations.
Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or the public and result in liability to us.
Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results, financial condition and cash flows.
Both the petroleum and nitrogen fertilizer businesses depend on significant customers and the loss of several significant customers may have a material adverse 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 business represented 39% of its petroleum net sales for the year ended December 31, 2015.2017. The five largest customers of the nitrogen fertilizer business also represented approximately 39%31% of its net sales for the year ended December 31, 2015. One significant2017. The top petroleum customer accounts for approximately 19% of petroleum net sales and two significantthe top nitrogen fertilizer customers each accountcustomer accounts for more than 10%approximately 11% of petroleum and nitrogen fertilizer net sales.sales for this same period. Given the nature of our businesses, and consistent with industry practice, we do not have long-term minimum purchase contracts with our customers. The loss of several of these significant customers, or a significant reduction in purchase volume by several of them, could have a material adverse effect on our results of operations, financial condition and cash flows.
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 grow and increase profitability. However, we may not be able to consummate such acquisitions or expansions, due to intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions and expansions, difficulties in identifying suitable acquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms and the failure to obtain requisite regulatory or other governmental approvals. In addition, any future acquisitions and expansions may entail significant transaction costs and risks associated with entry into new markets and lines of business.
In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:
unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business;
failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition;
strain on the operational and managerial controls and procedures of the petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources;
difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;
assumption of unknown material liabilities or regulatory non-compliance issues;
amortization of acquired assets, which would reduce future reported earnings;
possible adverse short-term effects on our cash flows or operating results; and
diversion of management's attention from the ongoing operations of our business.
In addition, in connection with any potential acquisition or expansion project, 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 a partnership for federal income tax purposes. If the petroleum business or the nitrogen fertilizer business is otherwise unable to conclude that the activities of the 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 a ruling from the Internal Revenue Service ("IRS"). Seeking such a ruling could be costly or, in the case of competitive acquisitions, place the business in a competitive disadvantage compared to other potential acquirers who do not seek such a ruling. If the petroleum business or the nitrogen fertilizer business is unable 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 IRS ruling, the petroleum business or the nitrogen fertilizer business may choose to acquire such business or develop such expansion project in a corporate subsidiary, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of cash available for distribution to its common unitholders and wouldcould 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 and cash flows. Our joint ventures involve similar risks. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.
We are a holding company and depend upon our subsidiaries for our cash flow.
Our two principal subsidiaries are publicly traded partnerships, and a portion of their common units trade on the NYSE. We are a holding company, and these subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay 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 to us in the form of distributions on their common units. The ability of the Refining Partnership and the Nitrogen Fertilizer Partnership to make any payments to us will depend on, among other things, their earnings, the terms of their indebtedness (including the terms of any debt facilities and instruments), 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) if any default or event of default (as defined in the indenture) exists. In addition, the indenture governing the Refining Partnership's 6.5% senior notes contains covenants limiting the Refining Partnership's ability to pay distributions to unitholders. The covenants will apply differently dependingfuture debt facilities and instruments incurred at our subsidiaries may impose significant limitations on the Refining Partnership's fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5ability of our subsidiaries to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, 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. In addition, the Refining Partnership's Amended and Restated ABL Credit Facility requires it to maintain a minimum excess availability under the facility as a condition to the payment of distributions to its unitholders. The Nitrogen Fertilizer Partnership's credit facility requires that, before the Nitrogen Fertilizer
Partnership can make distributions to us it must be in compliance with leverage ratio and interest coverage ratio tests. Any new indebtedness could have similar or greater restrictions.consequently our ability to issue dividends to our stockholders.
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 price volatility can significantly impact working capital on a week-to-week and month-to-month basis. If we cannot generate adequate cash flow or otherwise secure sufficient liquidity to meet our working capital needs or support our short-term and long-term capital requirements, we may be unable to meet our debt obligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business and results of operations.
A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disrupt our business and increase our costs.
As of December 31, 2015,2017, approximately 54%66% of the employees at the Coffeyville refinery, and 59% of the employees at the Wynnewood refinery and 32% of the employees who work in crude transportation were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with five Metal Trades Unions (which covers union represented employees who work directly at the Coffeyville refinery) expires in March 2019. The collective bargaining agreement with the United Steelworkers (which covers the balance of the petroleum business' unionized employees who work in crude transportation) expires in March 2017,2019 and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2017.2021. Approximately 64% of the employees at the East Dubuque Facility were represented by the International Union of United Automobile, Aerospace, and Agricultural Implement Workers under a collective bargaining agreement that expires in October 2019. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations, financial condition and cash flows.
Our business may suffer if any of our key senior executives or other key employees unexpectedly discontinues employment with us. Furthermore, a shortage 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 our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. In particular, the nitrogen fertilizer facility relies on gasification technology that requires special expertise to operate efficiently and effectively. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign unexpectedly or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially 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 chemical manufacturing 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 with the refining and nitrogen fertilizer facilities may have a material adverse effect on our results of operations, financial condition and cash flows. Targets such as refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, the petroleum and chemical industries have responded to the issues that arose due to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition and cash flows. The 2013 fertilizer plant explosion in West, Texas has generated consideration of more restrictive measures in storage, handling and transportation 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 tax liabilities in the future.
The Refining Partnership's and the Nitrogen Fertilizer Partnership's level of indebtedness may increase, which would reduceaffect their ability to operate their businesses, and may have a material adverse effect on their financial flexibilitycondition and the distributions they make on their common units.results of operations.
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 "2022 Notes") outstanding, (ii) availability under the Amended and Restated ABL Credit Facility of $262.1 million, with letters of credit outstanding of approximately $27.8 million and (iii) $31.5 million borrowed under an intercompany credit facility with availability under the intercompany credit facility of $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 credit facility. In the future, theThe Refining Partnership and the Nitrogen Fertilizer Partnership have incurred indebtedness and they may be able to incur significant additional significant indebtedness in orderthe future. If new indebtedness is added to make future acquisitions, expand their businesses or develop their properties.current indebtedness, the risks described below could increase. Their level of indebtedness could affect their operations in several ways, including the following:have important consequences, such as:
limiting their ability to obtain additional financing to fund their working capital needs, capital expenditures, debt service requirements, acquisitions or other purposes;
requiring them to utilize a significant portion of their cash flows could be used to service their indebtedness, thereby reducing available cash and their ability to make distributions on their common units (including distributions to us);
limiting their ability to use operating cash flow in other areas of their business because they must dedicate a high levelsubstantial portion of debt would increasethese funds to service debt;
limiting their vulnerabilityability to generalcompete with other companies who are not as highly leveraged, as they may be less capable of responding to adverse economic and industry conditions;
restricting them from making strategic acquisitions or investments, introducing new technologies or exploiting business opportunities;
restricting the way in which they conduct their business because of financial and operating covenants in the agreements governing their and their respective subsidiaries' existing and future indebtedness, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to them;
exposing them to potential events of default (if not cured or waived) under financial and operating covenants contained in their or their respective subsidiaries' debt agreements will limitinstruments that could have a material adverse effect on their business, financial condition and operating results;
increasing their vulnerability to a downturn in general economic conditions or in pricing of their products; and
limiting their ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;
a high level of debt may place them at a competitive disadvantage comparedreact to competitors that are less leveraged and who therefore may be able to take advantage of opportunities thatchanging market conditions in their indebtedness would prevent them from pursuing;
their debt covenants may also affect flexibility in planning for, and reacting to, changes in the economyrespective industries 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 redetermination could 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 service requirements, 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 variable rates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect their ability to make distributions to common unitholders (including us).customers' industries.
In addition to their debt service obligations, theirthe operations of the Refining Partnership and the Nitrogen Fertilizer Partnership require substantial investments on a continuing basis. Their ability to make scheduled debt payments, to refinance debttheir obligations with respect to their indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of their operating assets, properties and systems software, as well as to provide capacity for the growth of their businesses,business, depends on their respective financial and operating performance. Generalperformance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors affect their operations and their future performance. Manyfactors.
In addition, the bank borrowing base underRefining Partnership and the Refining Partnership's AmendedNitrogen Fertilizer Partnership are and Restated ABL Credit Facility will be subject to periodic redeterminations. 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 not have sufficient funds to make such repayments. If the Refining Partnership does not have sufficient fundscovenants contained in agreements governing their present and is otherwise unable to negotiate renewals of its borrowings or arrange new financing, it may have to sell significant assets. Any such sale could have a material adverse effectfuture indebtedness. These covenants include, and will likely include, restrictions on the Refining Partnership's business and financial condition and, as a result, its ability to makecertain payments (including restrictions on distributions to common unitholders (including us).their unitholders), the granting of liens, the incurrence of additional indebtedness, dividend restrictions affecting subsidiaries, asset sales, transactions with affiliates and mergers and consolidations. Any failure to comply with these covenants could result in a default under their current credit agreements or debt instruments or future credit agreements.
The Refining Partnership and the Nitrogen Fertilizer Partnership may not be able to generate sufficient cash to service all of their indebtedness and may be 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, regulatory and other factors, many of which are beyond ourtheir control; and
the Refining Partnership'stheir future ability to borrow under its Amended and Restated ABL Credit Facility and the intercompany credit facility between the Refining Partnership and us, and the Nitrogen Fertilizer Partnership's ability to borrow under its revolving credit facility, the availability of which depends on, amongobtain other things, compliance with their respective covenants.financing.
We cannot offer any assurance that our businesses will generate sufficient cash flow from operations, or that the Refining Partnership will be able to draw under its Amended and Restated ABL Credit Facility, or the intercompany credit facility or otherwise, or that the Nitrogen Fertilizer Partnership will be able to draw under its revolvingABL credit facility or otherwise, 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 be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance their indebtedness.indebtedness or seek bankruptcy protection. These alternative measures may not be successful and may not permit them to meet their scheduled debt service obligations. Their ability to restructure or refinance debt will depend on the 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 require them to comply with more onerous covenants, which could further restrict their business operations, and the terms of existing or future debt agreements may restrict us from adopting some of these alternatives. In addition, in the absence of adequate cash flows or capital resources, they could face substantial liquidity problems and might be required to dispose of material assets or operations, or sell equity, and/or negotiate with lenders to restructure the applicable debt 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 Facility and the indenture governing its 6.5% senior notes and the Nitrogen Fertilizer Partnership's credit facility may restrict, or marketMarket or business conditions may limit their ability to avail themselves of some or all of these options. Furthermore, any proceeds that wethey realize from any such dispositions may not be adequate to meet their debt service obligations when due. None of the Company's stockholders or any of their respective affiliates has any continuing obligation 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 Fertilizer Partnership's revolvingABL credit facility bear interest at variable rates and other debt we or they incur could likewise be variable-rate debt. If market interest rates increase, variable-rate debt will create higher debt service requirements, which could adversely affect their respective distributions to us. The Refining Partnership or the Nitrogen Fertilizer Partnership may enter into agreements limiting their exposure to higher interest rates, but any such agreements may not offer complete protection from this risk.
Covenants in our subsidiaries'The debt instruments could limit their ability to incur additional indebtedness and engage in certain transactions, which could adversely affect our liquidity and our ability to pursue our business strategies.
The indenture governingagreements of the Refining Partnership's 2022 Notes and the Amended and Restated ABL Credit FacilityPartnership and the Nitrogen Fertilizer Partnership's credit facilityPartnership contain restrictions that limit their flexibility in operating their respective businesses and their ability to make distributions to their unitholders.
The debt facilities and instruments of the Refining Partnership and the Nitrogen Fertilizer Partnership contain, and any instruments governing their future indebtedness would likely contain, a number of restrictive covenants that will impose significant operating and financial restrictions on them, and their subsidiaries and may limit their ability to engage in acts that may be in their long-term best interest, including restrictions on their and their respective subsidiaries' ability to, among other things, to:things:
incur additional indebtedness or issue certain preferred units;
pay distributions in respect of our units or make other restricted payments;
make certain payments on debt that is subordinated or secured on a junior basis;
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;
make certain investments;
sell certain assets;
create liens on certain assets;
consolidate, merge, sell or otherwise dispose of assets, including capital stockall or substantially all of subsidiaries;
our assets;
enter into certain transactions with our affiliates; and
merge, consolidate or sell substantially all of their assets.designate our subsidiaries as unrestricted subsidiaries.
In particular, the indenture governing the Refining Partnership's 2022 Notes prohibits it from making distributions to unitholders (including us) if any default or eventAny of default (as defined in the indenture) exists. In addition, the indenture governing the Refining Partnership's 2022 Notes contains covenants limiting the Refining Partnership'sthese restrictions could limit their ability to pay distributionsplan for or react to unitholders. Themarket conditions and could otherwise restrict partnership activities. Any failure to comply with these covenants will apply differently depending on the Refining Partnership'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 Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, 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. In addition, the Refining Partnership's Amended and Restated ABL Credit Facility requires it to maintain a minimum excess availability under the facility as a condition to the payment of distributions to its unitholders. The Nitrogen Fertilizer Partnership's credit facility requires that, before the Nitrogen Fertilizer Partnership can make distributions to us, it must be in compliance with leverage ratio and interest coverage ratio tests. Any new indebtedness could have similar or greater restrictions.
A breach of the covenants under the foregoing debt instruments could result in an event of default.a default under their debt facilities and instruments. Upon a default, unless waived, the holders of the Refining Partnership's 2022 Notes and lenders under the Refining Partnership's Amendedsuch debt facilities and Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership's credit facilityinstruments 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'their assets, and force it and its subsidiariesthem into bankruptcy or liquidation, subject to any applicable intercreditor agreements. In addition, any defaultsa default under their debt facilities and instruments would trigger a cross default under their other agreements and could trigger a cross defaultsdefault under other orthe agreements governing their future credit agreements or indentures.indebtedness. The Refining Partnership's or Nitrogen Fertilizer Partnership's operating results may not be sufficient to service their indebtedness or to fund ourtheir other expenditures and they may not be able to obtain financing to meet these requirements. As a result of these restrictions, they may be limited in how they conduct their respective businesses, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities.
Despite their indebtedness, the Refining Partnership and the Nitrogen Fertilizer Partnership may still be able to incur significantly more debt, including secured 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 secured indebtedness. Although the Refining Partnership's Amended and Restated ABL Credit Facility and its 2022 Notes and the Nitrogen Fertilizer Partnership's ABL credit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions may not prevent them 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, is able 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;
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 Nitrogen Fertilizer 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 acquire a 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 and entities controlled by him may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that any additional business opportunities be presented to us. We also have and may in the future enter into transactions to purchase goods or services with affiliates of Mr. Icahn. To the extent that conflicts of interest may arise between the Company and Mr. Icahn and his affiliates, those conflicts may be resolved in a manner 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 be deemed to have occurred under the terms of the indentures governing the Refining Partnership's 6.5% senior notes, which would require it to offer to repurchase 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 to have occurred under the Refining Partnership's Amended and Restated ABL Credit Facility, which would allow lenders to accelerate indebtedness owed to them. 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 repurchase of 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 the Company'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 to request 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 of shares 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 certain corporate 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 the meaning 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 of companies that are subject to all of the corporate governance requirements of the NYSE. In addition, both the Refining Partnership and the Nitrogen Fertilizer Partnership 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 for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability 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 may result 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 the controlled group.
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 of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of December 31, 2015.2017. If the ACF and Federal-Mogul plans were voluntarily terminated, they would be collectively underfunded by approximately $589.2$423.7 million and $473.8$613.4 million as of December 31, 20152017 and 2014,2016, respectively.
These results are based on the most recent information provided to us by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate the liability. 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 pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes 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 ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension 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 we make certain extraordinary dividends or stock redemptions. The obligation to report could cause us to seek to delay or reconsider the occurrence of such reportable events.
Risks Related to Our Common Stock
We have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders' ability to sell their shares for a premium 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 or takeover 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 its stockholders. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions 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 party from 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 upon by 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 equity ownership 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 provide us with the flexibility to issue common stock or preferred stock for business purposes that may arise as deemed advisable by our board of directors. These purposes 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 to obtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt if needed; (iii) for use in additional stock incentive programs and (iv) for other bona fide purposes. Our board of directors may authorize the Company to issue the available authorized shares of common stock or preferred stock without notice to, or further action by, our stockholders, unless stockholder approval is required by law or the rules of the NYSE. The issuance of additional shares of common stock or preferred stock may significantly dilute the equity ownership of the current holders of our common stock.
Our 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 is subject 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 into in the future, covenants contained in the debt agreements of CVR Partners and CVR Refining, and the amount of distributions we receive from CVR Partners and 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 dividends decreases, the trading price of our common stock could be materially adversely affected as a result.
Risks Inherent In the Limited Partnership Structures Through Which
We Currently Hold Our Interests in the Refinery Business and the Nitrogen Fertilizer Business
Both the Refining Partnership and the Nitrogen Fertilizer Partnership have in place policies to distribute an amount equal to the "available cash" each generates 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 is to distribute an amount equal to the available cash generated by each partnership each quarter to their respective unitholders. As a result of their respective cash distribution policies, the Refining Partnership and the Nitrogen Fertilizer Partnership will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures. As such, to the extent they are unable to finance growth externally, their respective cash distribution policies will significantly impair their ability to grow. The board of directors of the general partner of either the Refining Partnership or the Nitrogen Fertilizer Partnership may modify or revoke its cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash 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 available cash to expand ongoing operations. To the extent either issues additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount each distributes in respect of each of its outstanding units. There are no limitations in their respective partnership agreements on either the Refining Partnership's or the Nitrogen Fertilizer Partnership's ability to issue additional units, including units ranking senior to the outstanding common units. The incurrence of additional commercial borrowings or other debt to finance their growth strategy would result in increased interest expense, which, in turn, would reduce the available 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 on their 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 the payment of distributions to common unitholders. The Refining Partnership and the Nitrogen Fertilizer Partnership are separate public companies, and available cash generated by one of them will not be used to make distributions to common unitholders of the other. Furthermore, their respective partnership agreements do not require either to pay distributions on a quarterly basis or otherwise. The board of directors of the general partner of either the Refining Partnership 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 of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on our profitability and our ability to pay distributions to unitholders" and "— Risks Related to the Nitrogen Fertilizer Business — The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile, and the nitrogen fertilizer business has experienced substantial downturns in the past. Cycles in demand and pricing could potentially expose the nitrogen fertilizer business to significant fluctuations in its operating and financial results and have a material adverse effect on our results of operations, financial condition and cash flows."
If either the Refining Partnership or the Nitrogen Fertilizer Partnership were to be treated as a corporation rather than as a partnership, for U.S. federal income tax purposes or if either partnership were otherwisethey become subject to entity-level taxation for state tax purposes, such entity's cash available for distribution to its common unitholders, including to us, would be substantially reduced, likely causing a substantial reduction in the value of such entity's common units, including the common units held by us.
Current law requiresThe anticipated after-tax economic benefit of an investment in common units of the Refining Partnership andor the Nitrogen Fertilizer Partnership to derive at least 90% of their respective annual gross income from certain specified activities in order to continue to bedepends largely on each being treated as a partnership rather thanfor U.S. federal income tax purposes. Despite the fact that the Refining Partnership or the Nitrogen Fertilizer Partnership are each organized as a limited partnership under Delaware law, each would be treated as a corporation for U.S. federal income tax purposes.purposes unless it satisfies a “qualifying income” requirement. One or both of them may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect the Refining Partnership and the Nitrogen Fertilizer Partnership's ability to be treated as a partnership for U.S. federal income tax purposes. However, there are no assurances that the Final Regulations will not be revised to take a position that is contrary to our interpretation of the current law.
If either the Refining 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 and local income taxes at varying rates, and distributionsrate. Distributions to their common unitholders including to us,(including us) would generally be taxed again as corporate distributions.
If the Refining Partnershipdistributions, and the Nitrogen Fertilizer Partnership wereno income, gains, losses or deductions would flow through to such common unitholders. Because a tax would be treatedimposed upon them as corporations, rather than as partnerships, for U.S. federal income tax purposes or if they were otherwise subject to entity-level taxation,a corporation, their cash available for distribution to common unitholders would be substantially reduced. Therefore, treatment of the Refining Partnership or the Nitrogen Fertilizer Partnership as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to their common unitholders including to us, and(including us), likely causing a substantial reduction in the value of theirsuch common units, including the common units held by us, could be substantially reduced.units.
Increases in interest rates could adversely impact the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units and the Refining 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 Refining Partnership's or the Nitrogen Fertilizer Partnership's quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units, and a rising interest rate environment could have a material adverse impact on the price of the Refining Partnership's or the Nitrogen Fertilizer Partnership's common units (and therefore the value of our investment in the Refining Partnership and/or the Nitrogen Fertilizer Partnership) as well as the Refining Partnership's or the Nitrogen 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 repay amounts wrongfully returned or distributed to us. Under the Delaware Revised Uniform Limited Partnership Act, a partnership may not make distributions to its 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 the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the company for the distribution amount.
Public investors own approximately 47%66% of the nitrogen fertilizer business through the Nitrogen Fertilizer Partnership and approximately 34% of the petroleum business through the Refining Partnership. Although we own the majority of the common units and the general partner of both the Refining Partnership and the Nitrogen Fertilizer Partnership, the general partners owe a duty of good faith to public unitholders, which could cause them to manage their respective businesses differently than if there were no public unitholders.
Public investors own approximately 47%66% of the Nitrogen Fertilizer Partnership's common units and approximately 34% of the Refining Partnership's common units. We are not entitled to receive all of the cash generated by the nitrogen fertilizer business or the petroleum business or freely transfer money from the nitrogen fertilizer business to finance operations at the petroleum business or vice versa. Furthermore, although we continue to own the majority of the common units and the general partner of both the Refining Partnership and the Nitrogen Fertilizer Partnership, the general partners are subject to certain fiduciary duties, which may require the general partners to manage their respective businesses in a way that may differ from our best interests.
The general partners of the Refining Partnership and the Nitrogen Fertilizer Partnership have limited their liability, replaced default fiduciary duties and restricted the remedies available to common unitholders, including us, for actions that, without these limitations and reductions might otherwise constitute breaches of fiduciary duty.
The respective partnership agreements of the Refining Partnership and the Nitrogen Fertilizer Partnership limit the liability and replace the fiduciary duties of their respective general partner, while also restricting the remedies available to each partnership's common unitholders, including us, for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. The partnership agreements contain provisions that replace the standards to which each general partner would otherwise be held by state fiduciary 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 its capacity as general partner. This entitles its general partner to consider only the interests and factors that it desires, and means that it has no duty or 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 its capacity as general partner so long as (i) in the case of the Nitrogen Fertilizer Partnership, it acted in good faith, meaning it believed that the decision was in the best interest of the Nitrogen Fertilizer Partnership and (ii) in the case of the Refining Partnership, it did not make such decisions 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 liable for monetary damages to common unitholders, including us, for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that (i) in the case of the Nitrogen Fertilizer Partnership, the general partner or 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 knowledge that the conduct was criminal and (ii) in the case of the Refining Partnership, such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or with respect to any criminal conduct, with the knowledge that its conduct was unlawful.
In addition, the Refining Partnership's partnership agreement provides that its general partner will not be in breach of its obligations thereunder or its duties 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 the conflicts 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 the vote of a majority of the outstanding units, excluding any units owned by the general partner and its affiliates. In addition, the Nitrogen Fertilizer Partnership's partnership agreement (i) generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee 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 Fertilizer Partnership 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 partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to 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 or its 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 prosecuting such 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 the provisions described above.
The Refining Partnership and the Nitrogen Fertilizer Partnership are managed by the executive officers of their general partners, some of whom are employed 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 are employed by and serve as part of the senior management team of the Company. Furthermore, although both the Refining Partnership and the Nitrogen Fertilizer Partnership have entered into services agreements with the Company under which they compensate the Company for the services of its management, the Company's management is not required to devote any specific amount of time to the petroleum business or the nitrogen fertilizer business and may devote a
substantial majority of their time to the business of the Company. Moreover the Company may terminate the services agreement with the Refining Partnership 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 the Company, including its president and chief executive officer, chief financial officer and general counsel, will face conflicts of interest if decisions arise in which the Refining Partnership or the Nitrogen Fertilizer Partnership and the Company have conflicting points of view or interests.
Item 1B. Unresolved Staff Comments
None.There are no material unresolved written comments that were received from the SEC staff 180 days or more before the end of our fiscal year relating to our periodic or current reports under the Exchange Act.
Item 2. Properties
The following table contains certain information regarding our principal properties:
|
| | | | | | | |
| Location | | Acres | | Own/Lease | | Use |
| Coffeyville, KS | | 440 |
| | Own | | Refining Partnership: oil refinery and office buildings |
| | | |
| | | | Nitrogen Fertilizer Partnership: fertilizer plant |
| Wynnewood, OK | | 400 |
| | Own | | OilRefining Partnership: oil refinery, office buildings, refined oil storage |
| East Dubuque, IL | | 210 |
| | Own | | Nitrogen Fertilizer Partnership: fertilizer plant and fertilizer storage |
| Montgomery County, KS (Coffeyville Station) | | 2030 |
| | Own | | CrudeRefining Partnership: crude oil storage |
| Montgomery County, KS (Broome Station) | | 20 |
| | Own | | CrudeRefining Partnership: crude oil storage |
| Cowley County, KS (Hooser Station) | | 8070 |
| | Own | | CrudeRefining Partnership: crude oil storage |
| Cushing, OK | | 138 |
| | Own | | CrudeRefining Partnership: crude oil storage |
We also lease property for our executive office which is located at 2277 Plaza Drive in Sugar Land, Texas. Additionally, other corporateadministrative office space is leased in Kansas City, Kansas.
As of December 31, 2015,2017, the petroleum business owns crude oil storage capacity of approximately (i) 1.5 million barrels that supports the gathering system and the Coffeyville refinery, (ii) 0.9 million barrels at the Wynnewood refinery and (iii) 1.5 million barrels in Cushing, Oklahoma.Cushing. The petroleum business leases additional crude oil storage capacity of approximately (iv) 2.82.3 million barrels in Cushing, (v)and 0.2 million barrels in Duncan, Oklahoma and (vi) 0.1 million barrels at the Wynnewood refinery.Oklahoma. In addition to crude oil storage, the petroleum business owns over 4.54.6 million barrels of combined refined products and feedstocks storage capacity. The nitrogen fertilizer business has the capacity to store approximately 160,000 tons of UAN and 80,000 tons of ammonia. We believe that our owned and leased facilities are sufficient for our operating needs.
Item 3. Legal Proceedings
We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described under "Business — Environmental Matters." We also incorporate by reference into this Part I, Item 3 of this Report, the information regarding the lawsuits and proceedings described and referenced in Note 1315 ("Commitments and Contingencies") to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Report. In accordance with Generally Accepted Accounting Principlesaccounting principles generally accepted in the United States of America ("GAAP"), we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock, which is listed on the NYSE under the symbol "CVI" commenced trading on October 23, 2007. The table below sets forth, for the quarter indicated, the high and low sales prices per share of our common stock for our most recent fiscal years:
| | | 2015 | High | | Low | |
| 2017 | | High | | Low |
| First Quarter | $ | 43.21 |
| | $ | 33.02 |
| $ | 25.91 |
| | $ | 18.88 |
|
| Second Quarter | 43.46 |
| | 36.43 |
| 23.20 |
| | 17.53 |
|
| Third Quarter | 43.63 |
| | 36.02 |
| 26.35 |
| | 16.75 |
|
| Fourth Quarter | 48.37 |
| | 38.45 |
| 38.25 |
| | 25.35 |
|
| | | 2014 | High | | Low | |
| 2016 | | High | | Low |
| First Quarter | $ | 43.96 |
| | $ | 34.89 |
| $ | 38.98 |
| | $ | 22.05 |
|
| Second Quarter | 51.44 |
| | 41.06 |
| 26.57 |
| | 14.87 |
|
| Third Quarter | 50.99 |
| | 44.25 |
| 16.39 |
| | 13.01 |
|
| Fourth Quarter | 49.64 |
| | 36.70 |
| 25.41 |
| | 12.03 |
|
Holders of Record
As of February 16, 2016,20, 2018, there were 127124 holders of record of our common stock. Because many of our shares of common stock are held by brokers and other 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 Policy
On January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Dividends are subject to change at the discretion of the board of directors. The Company began paying regular quarterly dividends in the second quarter of 2013. Additionally, the Company declared and paid 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, 20152017 and 2014:2016:
| | | | December 31, 2014 | | March 31, 2015 | | June 30, 2015 | | September 30, 2015 | | Total Dividends Paid in 2015 | December 31, 2016 | | March 31, 2017 | | June 30, 2017 | | September 30, 2017 | | Total Dividends Paid in 2017 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Dividend type | Quarterly |
| | Quarterly |
| | Quarterly |
| | Quarterly |
| | | Quarterly |
| | Quarterly |
| | Quarterly |
| | Quarterly |
| | |
| Amount paid to IEP | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 142.4 |
| $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 142.4 |
|
| Amounts paid to public stockholders | 7.8 |
| | 7.8 |
| | 7.8 |
| | 7.8 |
| | 31.3 |
| 7.8 |
| | 7.8 |
| | 7.8 |
| | 7.8 |
| | 31.3 |
|
| Total amount paid | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 173.7 |
| $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 173.7 |
|
| Per common share | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 2.00 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 2.00 |
|
| Shares outstanding | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | |
| | | | December 31, 2013 | | March 31, 2014 | | June 30, 2014 | | July 17, 2014 | | September 30, 2014 | | Total Dividends
Paid in 2014 | December 31, 2015 | | March 31, 2016 | | June 30, 2016 | | September 30, 2016 | | Total Dividends
Paid in 2016 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Dividend type | Quarterly |
| | Quarterly |
| | Quarterly |
| | Special |
| | Quarterly |
| | | Quarterly |
| | Quarterly |
| | Quarterly |
| | Quarterly |
| | |
| Amount paid to IEP | $ | 53.4 |
| | $ | 53.4 |
| | $ | 53.4 |
| | $ | 142.4 |
| | $ | 53.4 |
| | $ | 356.0 |
| $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 142.4 |
|
| Amounts paid to public stockholders | 11.7 |
| | 11.7 |
| | 11.7 |
| | 31.3 |
| | 11.7 |
| | 78.2 |
| 7.8 |
| | 7.8 |
| | 7.8 |
| | 7.8 |
| | 31.2 |
|
| Total amount paid | $ | 65.1 |
| | $ | 65.1 |
| | $ | 65.1 |
| | $ | 173.7 |
| | $ | 65.1 |
| | $ | 434.2 |
| $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 173.6 |
|
| Per common share | $ | 0.75 |
| | $ | 0.75 |
| | $ | 0.75 |
| | $ | 2.00 |
| | $ | 0.75 |
| | $ | 5.00 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 2.00 |
|
| Shares outstanding | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | |
On February 17, 2016,21, 2018, the board of directors of the Company declared a cash dividend for the fourth quarter of 20152017 to the Company's stockholders of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on March 7, 201612, 2018 to stockholders of record at the close of business on February 29, 2016.March 5, 2018.
Our ability to pay cash dividends is dependent on the ability of our subsidiaries to make distributions to us. The cash distribution policies of the Nitrogen Fertilizer Partnership and the Refining Partnership are described below. Furthermore, the ability of the Nitrogen Fertilizer Partnership and the Refining Partnership to make distributions to us is limited by the Refining Partnership's Amended and Restated ABL Credit Facility and the indenture governing the 2022 Notes.Notes and the Nitrogen Fertilizer Partnership's indenture governing the 2023 Notes and the ABL Credit Facility. See Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for a discussion of those limitations.
CVR Partners, LP Cash Distribution Policy
The current policy of the board of directors of the Nitrogen Fertilizer Partnership's general partner is to distribute all available cash the Nitrogen Fertilizer Partnership generatesgenerated on a quarterly basis. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter iswill be determined by the board of directors of the Nitrogen Fertilizer Partnership's general partner following the end of such quarter, subject to the limitations discussed below. The board of directors of the Nitrogen Fertilizer Partnership's general partner calculates availablequarter. Available cash for distribution starting witheach quarter is calculated as 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, and (iii) to the extent applicable, major scheduled turnaround expenses, and reserves for future operating or capital needs that the board of directors of the Nitrogen Fertilizer Partnership's general partner deems necessary or appropriate, and (iv) expenses associated with the Rentech Nitrogen mergers,East Dubuque Merger, if any. Available cash for distribution may be increased by the release of previously established cash reserves, if any, at the discretion of the board of directors of the Nitrogen Fertilizer Partnership's general partner. The Nitrogen Fertilizer Partnership does not intend to maintain excess distribution coverage forpartner and available cash is increased by the purposebusiness interruption insurance proceeds and the impact of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash forpurchase accounting. Actual distributions nor does the Nitrogen Fertilizer Partnership intend to incur debt to pay quarterly distributions. As of the date of this Report, we own approximately 53% ofare set by the Nitrogen Fertilizer Partnership's common units, and are entitled to a pro rata percentage of the Nitrogen Fertilizer Partnership's distributions in respect of its common units.general partner. The board of directors of the Nitrogen Fertilizer Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Nitrogen Fertilizer Partnership to make distributions at all.
The Merger Agreement with Rentech Nitrogen Adjusted EBITDA is defined as EBITDA (net income before interest expense, net, income tax expense, depreciation and Rentech Nitrogen GP includes customary restrictionsamortization) further adjusted for the impact of non-cash share-based compensation, and, where applicable, major scheduled turnaround expenses, gain or loss on the conductextinguishment of the Nitrogen Fertilizer Partnership's business prior to the completiondebt, loss on disposition of the mergers, generally requiring the Nitrogen Fertilizer Partnership to conduct its business in the ordinary course and subjecting the Nitrogen Fertilizer Partnership to a variety of specified limitations. In accordanceassets, expenses associated with the terms of theEast Dubuque 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 declare distributions 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.business interruption insurance recovery.
The following is a summary of cash distributions paid by the Nitrogen Fertilizer Partnership to unitholders during the years ended December 31, 20152017 and 20142016 for the respective quarters to which the distributions relate:
| | | | December 31, 2014 | | March 31, 2015 | | June 30, 2015 | | September 30, 2015 | | Total Cash Distributions Paid in 2015 | December 31, 2016 | | March 31, 2017 | | June 30, 2017 | | September 30, 2017 | | Total Dividends Paid in 2017 |
| | (in millions, except per common unit data) | (in millions, except per common unit data) |
| Amount paid to CRLLC | $ | 16.0 |
| | $ | 17.5 |
| | $ | 15.2 |
| | $ | — |
| | $ | 48.6 |
| $ | — |
| | $ | 0.8 |
| | $ | — |
| | $ | — |
| | $ | 0.8 |
|
| Amounts paid to public unitholders | 14.0 |
| | 15.4 |
| | 13.3 |
| | — |
| | 42.8 |
| — |
| | 1.5 |
| | — |
| | — |
| | 1.5 |
|
| Total amount paid | $ | 30.0 |
| | $ | 32.9 |
| | $ | 28.5 |
| | $ | — |
| | $ | 91.4 |
| $ | — |
| | $ | 2.3 |
| | $ | — |
| | $ | — |
| | $ | 2.3 |
|
| Per common unit | $ | 0.41 |
| | $ | 0.45 |
| | $ | 0.39 |
| | $ | — |
| | $ | 1.25 |
| $ | — |
| | $ | 0.02 |
| | $ | — |
| | $ | — |
| | $ | 0.02 |
|
| Common units outstanding | 73.1 |
| | 73.1 |
| | 73.1 |
| | 73.1 |
| | | 113.3 |
| | 113.3 |
| | 113.3 |
| | 113.3 |
| | |
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2013 | | March 31, 2014 | | June 30, 2014 | | September 30, 2014 | | Total Cash
Distributions
Paid in 2014 |
| | (in millions, except per common unit data) |
| Amount paid to CRLLC | $ | 16.7 |
| | $ | 14.8 |
| | $ | 12.8 |
| | $ | 10.5 |
| | $ | 54.9 |
|
| Amounts paid to public unitholders | 14.7 |
| | 13.0 |
| | 11.3 |
| | 9.2 |
| | 48.2 |
|
| Total amount paid | $ | 31.4 |
| | $ | 27.8 |
| | $ | 24.1 |
| | $ | 19.7 |
| | $ | 103.1 |
|
| Per common unit | $ | 0.43 |
| | $ | 0.38 |
| | $ | 0.33 |
| | $ | 0.27 |
| | $ | 1.41 |
|
| Common units outstanding | 73.1 |
| | 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 of 2015 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, 2016 to 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. |
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2015 | | March 31, 2016 | | June 30, 2016 | | September 30, 2016 | | Total Cash
Distributions
Paid in 2016 |
| | (in millions, except per common unit data) |
| Amount paid to CRLLC | $ | 10.5 |
| | $ | 10.5 |
| | $ | 6.6 |
| | $ | — |
| | $ | 27.6 |
|
| Amounts paid to public unitholders | 9.2 |
| | 20.1 |
| | 12.6 |
| | — |
| | 41.9 |
|
| Total amount paid | $ | 19.7 |
| | $ | 30.6 |
| | $ | 19.2 |
| | $ | — |
| | $ | 69.5 |
|
| Per common unit | $ | 0.27 |
| | $ | 0.27 |
| | $ | 0.17 |
| | $ | — |
| | $ | 0.71 |
|
| Common units outstanding | 73.1 |
| | 113.3 |
| | 113.3 |
| | 113.3 |
| | |
CVR Refining, LP Cash Distribution Policy
The current policy of the board of directors of the Refining Partnership's general partner is to distribute all of the available cash the Refining Partnership generates each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the Refining Partnership's general partner following the end of such quarter and will generally equal Adjusted Petroleum EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for future major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of the Refining Partnership's general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of the Refining Partnership's general partner. The board of directors of the Refining Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in itsthe Refining Partnership's quarterly distribution or to otherwise to reserve cash for distributions, nor do they intend to incur debt to pay quarterly distributions. Further, it is the intent of the board of directors of the Refining Partnership's intent,Partnership, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified 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 a pro rata percentage of the Refining Partnership's distributions in respect of its common units. The board of directors of the Refining Partnership's general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the Refining Partnership to make distributions at all.
directors of the Refining Partnership's general partner declared a cash distribution to the Refining Partnership's unitholders of $0.94 per common unit. The following is a summarydistribution included amounts paid to CVR Refining Holdings, LLC and affiliates of $96.9 million and amounts paid to non-affiliates of $41.8 million, respectively, or $138.7 million in aggregate. The distributions were paid on November 17, 2017. No cash distributions were paid by the Refining Partnership to unitholders during the years ended December 31, 2015 and 2014 for the respective quarters to which the distributions relate:
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2014 | | March 31, 2015 | | June 30, 2015 | | September 30, 2015 | | Total Cash Distributions Paid in 2015 |
| | (in millions, except per common unit data) |
| Amount paid to CVR Refining Holdings, LLC | $ | 36.0 |
| | $ | 74.0 |
| | $ | 95.4 |
| | $ | 98.3 |
| | $ | 303.6 |
|
| Amounts paid to public unitholders | 18.6 |
| | 38.2 |
| | 49.2 |
| | 50.8 |
| | 156.9 |
|
| Total amount paid | $ | 54.6 |
| | $ | 112.2 |
| | $ | 144.6 |
| | $ | 149.1 |
| | $ | 460.5 |
|
| Per common unit | $ | 0.37 |
| | $ | 0.76 |
| | $ | 0.98 |
| | $ | 1.01 |
| | $ | 3.12 |
|
| Common units outstanding | 147.6 |
| | 147.6 |
| | 147.6 |
| | 147.6 |
| | |
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, 2013 | | March 31, 2014 | | June 30, 2014 | | September 30, 2014 | | Total Cash Distributions Paid in 2014 |
| | (in millions, except per common unit data) |
| Amount paid to CVR Refining Holdings, LLC | $ | 47.1 |
| | $ | 102.8 |
| | $ | 93.4 |
| | $ | 52.5 |
| | $ | 295.8 |
|
| Amounts paid to public unitholders | 19.3 |
| | 41.9 |
| | 48.3 |
| | 27.2 |
| | 136.7 |
|
| Total amount paid | $ | 66.4 |
| | $ | 144.7 |
| | $ | 141.7 |
| | $ | 79.7 |
| | $ | 432.5 |
|
| Per common unit | $ | 0.45 |
| | $ | 0.98 |
| | $ | 0.96 |
| | $ | 0.54 |
| | $ | 2.93 |
|
| Common units outstanding | 147.6 |
| | 147.6 |
| | 147.6 |
| | 147.6 |
| | |
Total cash distributions paid based upon available cash for 2015 were $2.75 per common unit.2016.
Stock Performance Graph
The following graph sets forth the cumulative return on our common stock between January 1, 2011 and December 31, 2015,2017, as compared to the cumulative return of the Russell 2000 Index and an industry peer group consisting of Alon USA Energy,CHS Inc., Delek US Holdings, Inc., HollyFrontier Corporation, Tesoro Corporation,Phillips 66, and Valero Energy Corporation and Western Refining, Inc.Corporation. The graph assumes an investment of $100 on January 1,December 30, 2011 in our common stock, the Russell 2000 Index and the industry peer group, and assumes the reinvestment of dividends where applicable. The closing market price for our common stock on the last trading day of the year ended December 31, 20152017 was $39.35.$37.24. The stock price performance shown on the graph is not intended to forecast and does not necessarily indicate future price performance.
COMPARISON OF CUMULATIVE TOTAL RETURN
BETWEEN JANUARY 1, 20112012 AND DECEMBER 31, 20152017
among CVR Energy, Inc., Russell 2000 Index and a peer group
This performance graph shall not be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Jan '11 | | Mar '11 | | Jun '11 | | Sep '11 | | Dec '11 | | Mar '12 | | Jun '12 | | Sep '12 | | Dec '12 | | Mar '13 | | Jun '13 |
| CVR Energy, Inc. | 100.00 |
| | 149.32 |
| | 158.74 |
| | 136.30 |
| | 120.76 |
| | 172.47 |
| | 171.37 |
| | 236.94 |
| | 314.57 |
| | 367.19 |
| | 376.65 |
|
| Russell 2000 Index | 100.00 |
| | 105.63 |
| | 103.62 |
| | 80.67 |
| | 92.78 |
| | 103.97 |
| | 99.99 |
| | 104.87 |
| | 106.36 |
| | 119.16 |
| | 122.41 |
|
| Peer Group | 100.00 |
| | 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 '15 | Dec '12 | | Dec '13 | | Dec '14 | | Dec '15 | | Dec '16 | | Dec '17 | |
| CVR Energy, Inc. | 311.10 |
| | 358.04 |
| | 354.65 |
| | 410.78 |
| | 403.40 |
| | 354.60 |
| | 394.66 |
| | 353.48 |
| | 390.39 |
| | 378.31 |
| 314.57 |
| | 358.04 |
| | 354.60 |
| | 378.31 |
| | 244.10 |
| | 439.48 |
| |
| Russell 2000 Index | 134.47 |
| | 145.72 |
| | 146.89 |
| | 149.39 |
| | 137.96 |
| | 150.86 |
| | 156.88 |
| | 157.03 |
| | 137.83 |
| | 142.24 |
| 106.36 |
| | 145.72 |
| | 150.86 |
| | 142.24 |
| | 169.95 |
| | 192.28 |
| |
| Peer Group | 238.60 |
| | 346.24 |
| | 317.43 |
| | 309.92 |
| | 336.54 |
| | 324.45 |
| | 421.99 |
| | 408.97 |
| | 402.89 |
| | 378.74 |
| 264.52 |
| | 346.24 |
| | 324.45 |
| | 378.74 |
| | 343.43 |
| | 390.83 |
| |
Purchases of Equity Securities by the Issuer
We did not repurchase any of our common stock during the fiscal quarter ended December 31, 2015.2017.
Item 6. Selected Financial Data
You should read the selected historical consolidated financial data presented below in conjunction with, and the selected historical consolidated and combined financial data presented below is qualified in its entirety by reference to, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes included elsewhere in this Report.
The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the years ended December 31, 2015, 20142017, 2016 and 20132015 and the selected consolidated financial information presented below under the caption "Balance Sheet Data" as of December 31, 20152017 and 20142016 has been derived from our audited consolidated financial statements included elsewhere in this Report, which financial statements have been audited by Grant Thornton LLP, our independent registered public accounting firm. The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the years ended December 31, 20122014 and 20112013 and the selected consolidated financial information presented below under the caption "Balance Sheet Data" at December 31, 2013, 20122015, 2014 and 20112013 is derived from our audited consolidated financial statements that are not included in this Report.
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011(1) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Statements of Operations Data | | | | | | | | | | | | | | | | | | |
| Net sales | $ | 5,432.5 |
| | $ | 9,109.5 |
| | $ | 8,985.8 |
| | $ | 8,567.3 |
| | $ | 5,029.1 |
| $ | 5,988.4 |
| | $ | 4,782.4 |
| | $ | 5,432.5 |
| | $ | 9,109.5 |
| | $ | 8,985.8 |
|
| Cost of product sold(2) | 4,190.4 |
| | 8,066.0 |
| | 7,563.2 |
| | 6,696.9 |
| | 3,943.5 |
| |
| Direct operating expenses(2) | 584.7 |
| | 515.1 |
| | 455.8 |
| | 522.1 |
| | 334.1 |
| |
| Operating costs and expenses: | | | | | | | | | | |
| Cost of materials and other | | 4,882.9 |
| | 3,847.5 |
| | 4,190.4 |
| | 8,066.0 |
| | 7,563.2 |
|
| Direct operating expenses(1) | | 599.5 |
| | 541.8 |
| | 584.7 |
| | 515.1 |
| | 455.8 |
|
| Depreciation and amortization | | 203.3 |
| | 184.5 |
| | 156.4 |
| | 148.1 |
| | 139.5 |
|
| Cost of sales | | 5,685.7 |
| | 4,573.8 |
| | 4,931.5 |
| | 8,729.2 |
| | 8,158.5 |
|
| Flood insurance recovery | (27.3 | ) | | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | (27.3 | ) | | — |
| | — |
|
| Insurance recovery-business interruption | — |
| | — |
| | — |
| | — |
| | (3.4 | ) | |
| Selling, general and administrative expenses(2) | 99.0 |
| | 109.7 |
| | 113.5 |
| | 183.4 |
| | 98.0 |
| |
| Selling, general and administrative expenses(1) | | 114.2 |
| | 109.1 |
| | 99.0 |
| | 109.7 |
| | 113.5 |
|
| Depreciation and amortization | 164.1 |
| | 154.4 |
| | 142.8 |
| | 130.0 |
| | 90.3 |
| 10.7 |
| | 8.6 |
| | 7.7 |
| | 6.3 |
| | 3.3 |
|
| Operating income | $ | 421.6 |
| | $ | 264.3 |
| | $ | 710.5 |
| | $ | 1,034.9 |
| | $ | 566.6 |
| 177.8 |
| | 90.9 |
| | 421.6 |
| | 264.3 |
| | 710.5 |
|
| Interest expense and other financing costs | (48.4 | ) | | (40.0 | ) | | (50.5 | ) | | (75.4 | ) | | (55.8 | ) | (110.1 | ) | | (83.9 | ) | | (48.4 | ) | | (40.0 | ) | | (50.5 | ) |
| Interest income | 1.0 |
| | 0.9 |
| | 1.2 |
| | 0.9 |
| | 0.5 |
| 1.1 |
| | 0.7 |
| | 1.0 |
| | 0.9 |
| | 1.2 |
|
| Gain (loss) on derivatives, net | (28.6 | ) | | 185.6 |
| | 57.1 |
| | (285.6 | ) | | 78.1 |
| (69.8 | ) | | (19.4 | ) | | (28.6 | ) | | 185.6 |
| | 57.1 |
|
| Loss on extinguishment of debt | — |
| | — |
| | (26.1 | ) | | (37.5 | ) | | (2.1 | ) | — |
| | (4.9 | ) | | — |
| | — |
| | (26.1 | ) |
| Other income (expense), net | 36.7 |
| | (3.7 | ) | | 13.5 |
| | 0.9 |
| | 0.8 |
| 1.0 |
| | 5.7 |
| | 36.7 |
| | (3.7 | ) | | 13.5 |
|
| Income before income tax expense | $ | 382.3 |
| | $ | 407.1 |
| | $ | 705.7 |
| | $ | 638.2 |
| | $ | 588.1 |
| |
| Income tax expense | 84.5 |
| | 97.7 |
| | 183.7 |
| | 225.6 |
| | 209.5 |
| |
| Income (loss) before income tax expense | | — |
| | (10.9 | ) | | 382.3 |
| | 407.1 |
| | 705.7 |
|
| Income tax expense (benefit) | | (216.9 | ) | | (19.8 | ) | | 84.5 |
| | 97.7 |
| | 183.7 |
|
| Net income | 297.8 |
| | 309.4 |
| | 522.0 |
| | 412.6 |
| | 378.6 |
| 216.9 |
| | 8.9 |
| | 297.8 |
| | 309.4 |
| | 522.0 |
|
| Less: Net income attributable to noncontrolling interest | 128.2 |
| | 135.5 |
| | 151.3 |
| | 34.0 |
| | 32.8 |
| |
| Less: Net income (loss) attributable to noncontrolling interest | | (17.5 | ) | | (15.8 | ) | | 128.2 |
| | 135.5 |
| | 151.3 |
|
| Net income attributable to CVR Energy stockholders | $ | 169.6 |
| | $ | 173.9 |
| | $ | 370.7 |
| | $ | 378.6 |
| | $ | 345.8 |
| $ | 234.4 |
| | $ | 24.7 |
| | $ | 169.6 |
| | $ | 173.9 |
| | $ | 370.7 |
|
| | | | | | | | | | | | | | | | | | | |
| Basic earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
| | $ | 4.36 |
| | $ | 4.00 |
| |
| Diluted earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
| | $ | 4.33 |
| | $ | 3.94 |
| |
| Basic and Diluted earnings per share | | $ | 2.70 |
| | $ | 0.28 |
| | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
|
| Dividends declared per share | $ | 2.00 |
| | $ | 5.00 |
| | $ | 14.25 |
| | $ | — |
| | $ | — |
| $ | 2.00 |
| | $ | 2.00 |
| | $ | 2.00 |
| | $ | 5.00 |
| | $ | 14.25 |
|
| | | | | | | | | | | | | | | | | | | |
| Weighted-average common shares outstanding: | | | | | | | | | | | | | | | | | | |
| Basic | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.5 |
| |
| Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
| | 87.4 |
| | 87.8 |
| |
| Basic and Diluted | | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
|
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011(1) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (in millions) | (in millions) |
| Balance Sheet Data | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | $ | 765.1 |
| | $ | 753.7 |
| | $ | 842.1 |
| | $ | 896.0 |
| | $ | 388.3 |
| $ | 481.8 |
| | $ | 735.8 |
| | $ | 765.1 |
| | $ | 753.7 |
| | $ | 842.1 |
|
| Working capital | 789.9 |
| | 1,033.0 |
| | 1,230.2 |
| | 1,135.4 |
| | 769.2 |
| 550.5 |
| | 749.6 |
| | 789.0 |
| | 1,031.3 |
| | 1,228.5 |
|
| Total assets | 3,305.8 |
| | 3,462.5 |
| | 3,665.8 |
| | 3,610.9 |
| | 3,119.3 |
| 3,806.7 |
| | 4,050.2 |
| | 3,299.4 |
| | 3,454.3 |
| | 3,655.9 |
|
| Total debt, including current portion | 673.5 |
| | 674.9 |
| | 676.2 |
| | 898.2 |
| | 863.8 |
| 1,166.5 |
| | 1,164.6 |
| | 667.1 |
| | 666.7 |
| | 666.3 |
|
| Total CVR stockholders' equity | 984.1 |
| | 988.1 |
| | 1,188.6 |
| | 1,525.1 |
| | 1,151.6 |
| 918.8 |
| | 858.1 |
| | 984.1 |
| | 988.1 |
| | 1,188.6 |
|
| Cash Flow Data | | | | | | | | | | | | | | | | | | |
| Net cash flow provided by (used in): | | | | | | | | | | | | | | | | | | |
| Operating activities | $ | 536.8 |
| | $ | 640.3 |
| | $ | 440.1 |
| | $ | 762.6 |
| | $ | 278.6 |
| $ | 166.9 |
| | $ | 267.5 |
| | $ | 536.8 |
| | $ | 640.3 |
| | $ | 440.1 |
|
| Investing activities | (150.6 | ) | | (296.6 | ) | | (250.3 | ) | | (210.7 | ) | | (674.4 | ) | (195.0 | ) | | (201.4 | ) | | (150.6 | ) | | (296.6 | ) | | (250.3 | ) |
| Financing activities | (374.8 | ) | | (432.1 | ) | | (243.7 | ) | | (44.2 | ) | | 584.1 |
| (225.9 | ) | | (95.4 | ) | | (374.8 | ) | | (432.1 | ) | | (243.7 | ) |
| Net cash flow | $ | 11.4 |
| | $ | (88.4 | ) | | $ | (53.9 | ) | | $ | 507.7 |
| | $ | 188.3 |
| |
| Net increase (decrease) in cash and cash equivalents | | $ | (254.0 | ) | | $ | (29.3 | ) | | $ | 11.4 |
| | $ | (88.4 | ) | | $ | (53.9 | ) |
| | | | | | | | | | | | | | | | | | | |
| Capital expenditures for property, plant and equipment | $ | 218.7 |
| | $ | 218.4 |
| | $ | 256.5 |
| | $ | 212.2 |
| | $ | 91.2 |
| $ | 118.6 |
| | $ | 132.7 |
| | $ | 218.7 |
| | $ | 218.4 |
| | $ | 256.5 |
|
| |
| (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. |
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our consolidated financial statements and related notes included elsewhere in this Report.
Forward-Looking Statements
This Report, including, without limitation, the sections captioned "Business" and "Management's Discussion and Analysis of Financial Condition and Results of Operations," contains "forward-looking statements" as defined by the SEC,Securities and Exchange Commission ("SEC"), including statements concerning contemplated transactions and strategic plans, expectations and objectives for future operations. Forward-looking statements include, without limitation:
statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;
statements relating to future financial or operational performance, future 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 such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under the section captioned "Risk Factors" and contained elsewhere in this Report. Such factors include, among others:
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;plants;
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, severe damage 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 existing and future regulations related to the end-use and application of fertilizers;
refinery and nitrogen fertilizer facilityfacilities' operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate 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 revise any forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events, except to the extent required by law.
Overview and Executive Summary
We are a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through our holdings in the Refining Partnership and the Nitrogen Fertilizer Partnership. The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the form of UAN and ammonia. We own the general partner and approximately 66% and 53%34%, respectively, of the outstanding common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership.
We operate under two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2015, 20142017, 2016 and 2013,2015, we generated consolidated net sales of $5.4$6.0 billion, $9.1$4.8 billion and $9.0$5.4 billion, respectively, and operating income of $421.6$177.8 million, $264.3$90.9 million and $710.5$421.6 million, respectively. The petroleum business generated net sales of $5.2
$5.7 billion, $8.8$4.4 billion and $8.7$5.2 billion, and the nitrogen fertilizer business generated net sales of $289.2$330.8 million, $298.7$356.3 million and $323.7$289.2 million, in each case, for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively. The petroleum business generated operating income of $361.7$203.8 million, $207.2$77.8 million and $603.0$361.7 million for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively. The nitrogen fertilizer business generated operating (loss) income of $68.7$(9.2) million, $82.8$26.8 million and $124.9$68.7 million for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, 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 MergersEast Dubuque Merger
On August 9, 2015,April 1, 2016, the Nitrogen Fertilizer Partnership completed the East Dubuque Merger as contemplated by the Merger Agreement, whereby the Nitrogen Fertilizer Partnership acquired 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 and RentechCVR Nitrogen GP by merging two newly-created direct wholly-owned subsidiaries of CVR Partners withGP. Pursuant to the East Dubuque Merger, the Nitrogen Fertilizer Partnership acquired the East Dubuque Facility. The primary reasons for the East Dubuque Merger were to expand the Nitrogen Fertilizer Partnership's geographical footprint, diversify its raw material feedstocks, widen its customer reach and into those entities with Rentech Nitrogen and Rentech Nitrogen GP continuing as surviving entities and wholly-owned subsidiaries of CVR Partners (together, the "mergers").increase its potential for cash-flow generation. In accordance with accounting principles generally accepted in the United States of America ("GAAP") and in accordance with the Financial Accounting Standards Board's Accounting Standards Codification Topic 805 - Business Combinations, the Nitrogen Fertilizer Partnership anticipates accountingaccounted for the mergersEast Dubuque Merger as an acquisition of a business with CVR Partnersthe Nitrogen Fertilizer Partnership as the acquirer.
Immediately following the closing of the East Dubuque Merger and as of December 31, 2017, public security holders held approximately 66% of total Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 34% of total Nitrogen Fertilizer Partnership common units in addition to owning 100% of the Nitrogen Fertilizer Partnership's general partner.
Refer to Part II, Item 8, Note 13 ("Organization and History of the Company"Acquisition") of this Report for further discussion of the mergers.East Dubuque Merger.
Refining Partnership Initial Public Offering
On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units at a price of $25.00 per unit, resulting in gross proceeds of $600.0 million.unit. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises L.P. ("IEP"). Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per unit resulting in gross proceeds of $90.0 million.unit. 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.
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. Immediately following the Refining Partnership IPO and through May 19, 2013, CVR Energy indirectly owned approximately 81% of the Refining Partnership's outstanding common units and 100% of the Refining Partnership's general partner, which holds a non-economic general partner interest.
Refining Partnership Underwritten Offering
On May 20, 2013, the Refining Partnership completed the Underwritten Offering by selling 12,000,000 common units to the public at a priceAs of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection 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 the exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the "Transactions."
The Refining Partnership utilized net proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings, LLC ("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 Refining Partnership 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,December 31, 2017, public security holders held approximately 29%34% of totalall outstanding limited partner interests
of the Refining Partnership (including common units (including units owned by affiliates of IEP, representing approximately 4%3.9% of total Refining Partnership common units), and CVR Refining Holdings held approximately 71% of total Refining Partnership common units.
Refining Partnership Second Underwritten Offering
On June 30, 2014, the Refining Partnership completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. 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 to redeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately 67% 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 the underwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.
Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2015, public security holders held approximately 34% of total Refining Partnership common units (including units held by affiliates of IEP, representing approximately 4% of total Refining Partnership common units)all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of totalall outstanding limited partner interests of the Refining Partnership common units inPartnership. In addition, to owningCVR Refining Holdings owns 100% of the Refining Partnership's general partner.partner, CVR Refining GP, which holds a non-economic general partner interest.
Nitrogen Fertilizer Partnership Secondary Offering
On May 28, 2013, Coffeyville Resources, LLC ("CRLLC"), a wholly-owned subsidiary of CVR Energy, completed the Secondary Offering in which it sold 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 Secondary Offering were approximately $292.6 million, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership 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 total Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of total Nitrogen Fertilizer Partnership common units in addition to owning 100% of the Nitrogen Fertilizer Partnership's general partner.
Major Influences on Results of Operations
Petroleum Business
The earnings and cash flows of the petroleum business are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond the petroleum business' control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because the petroleum business applies first-in first-out ("FIFO") accounting to value its inventory, crude oil price movements may impact net income 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 ourthe petroleum business results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.
The prices of crude oil and other feedstocks and refined product pricesproducts are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. Widespread expansion or upgrades of competitors' facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving
season and for home heating oil duringvolatile seasonal exports of diesel from the winter, primarily in the Northeast.United States Gulf Coast markets. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. The petroleum business is also subject to the Renewable Fuel Standard ("RFS") of the United States Environmental Protection Agency (the "EPA"),RFS, which requires it to either blend "renewable fuels" in with its transportation fuels or purchase renewable fuel credits, known as renewable identification numbers ("RINs"),RINs, in lieu of blending.blending, by March 31, 2018 or otherwise be subject to penalties.
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 for RINs or if the petroleum business is otherwise unable to meet the EPA's Renewable Fuels Standard (RFS)RFS mandates, the petroleum business' financial condition and results of operations could be materially adversely affected, and Part II, Item 8, Note 1315 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" of this Report for further discussion of the 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 difficult to 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 RINs can be purchased, transportation fuel production levels, the mix of the petroleum business’business' petroleum products, as well as the fuel blending performed at its refineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimates related to the other variable factors, the petroleum business currently estimates that the total cost of RINs will be approximately $140.0 million to $190.0$200.0 million for the year ending December 31, 2016.2018.
In order to assess theits operating performance, of the petroleum business we comparecompares net sales, less cost of product sold (exclusive of depreciationmaterials and amortization),other, or the refining margin, against an industry refining margin benchmark. The industry refining margin benchmark is calculated by assuming that two barrels of benchmark light sweet crude oil are converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.
Although the 2-1-1 crack spread is a benchmark for the refineryrefining margin, because the refineries have certain feedstock costs and logistical advantages as compared 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 affect refineryrefining margin. The Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutene,isobutane, gasoline components, and normal butane are also typically used. We measure the cost advantage of the crude oil slate by calculating 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. The refineryrefining margin can be impacted significantly by the consumed crude oil differential. The consumed crude oil differential will move directionally with changes in the WTS price differential to WTI and the WCS price differential to WTI as both these differentials indicate the relative price of heavier, more sour, crude oil slate to WTI. The correlation between the consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil 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 published differentials the heavier and more sour the crude oil slate. The consumed crude oil cost discount to WTI for 20152017 was $1.12$0.29 per barrel compared to consumed crude oil cost discounts of $0.54$1.58 per barrel in 20142016 and $2.57$1.12 per barrel in 2013.2015.
The petroleum business produces a high volume of high value products, such as gasoline and distillates. The fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in its refineries is because the prices the petroleum business realizes are 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 is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in its marketing area exceed those used in the 2-1-1 crack spread.
The petroleum business is significantly affected by developments in the markets in which it operates. For example, numerous pipeline projectsexpansions in 2014 expandedrecent years expanding the connectivity of the Cushing and Permian Basin markets to the gulf coast, resultingalong with lifting the crude oil export ban has resulted in a decrease in the domestic crude advantage. The refining industry is directly impacted by these events and could seehas seen a downward movement in refining margins as a result.
Table The stabilization of Contentsoil prices led by Organization of the Petroleum Exporting Countries ("OPEC") decision to lower production volumes and the resurgent shale drilling in the Permian and other tight oil plays are expected to cause price spread volatility as the industry attempts to match infrastructure to supply.
The 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 of electrical cost and natural gas. The petroleum business is therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the year ended December 31, 2015,2017, a $1.00 change in natural gas prices would have increased or decreased the petroleum business' natural gas costs by approximately $11.1$12.3 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 inventory position 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 activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of its titled inventory is valued under the FIFO costing method, price fluctuations on its target level of titled inventory have a major effect on the petroleum business' financial results.results from period to period.
Safe and reliable operations at the refineries are key to the petroleum business' financial performance and results of operations. UnplannedUnscheduled downtime at the refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The petroleum business seeks to mitigate the financial impact of plannedscheduled downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. During the outage atThe first phase of the Coffeyville refineryrefinery's most recent turnaround was completed in November 2015 at a total cost of approximately $102.2 million. The second phase of the thirdCoffeyville turnaround was completed during the first quarter of 2014 as discussed further below, the petroleum business accelerated certain planned 20152016 at a total cost of approximately $31.5 million. The next turnaround activities and incurred approximately $5.5 million of turnaround expensesscheduled for the year ended December 31, 2014.Wynnewood refinery is being performed as a two phase turnaround. The first phase of its current turnaround was completed in mid-November 2015November 2017 at a total cost of approximately $101.5$67.4 million. The second phase is scheduled 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 was incurred in the fourth quarter of 2015). The Wynnewood Refinery completed a turnaround in December 2012. During the outage at the Wynnewood refineryturnaround is expected to occur in 2019. Turnaround expenses associated with the fourth quartersecond phase of 2014 as discussed further below,the Wynnewood turnaround are estimated to be approximately $25.0 million. In addition to the two phase turnaround, the petroleum business accelerated certain planned turnaround activities andin the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. The petroleum business incurred approximately $1.3$13.0 million of major scheduled turnaround expenses for the year ended December 31, 2014. The next turnaround for the Wynnewood refinery is scheduled to occur in the spring of 2017.hydrocracker.
During the third quarter of 2013, the fluid catalytic cracking unit ("FCCU") at the Coffeyville refinery was offline for approximately 55 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at the Coffeyville refinery was significantly reduced during the third quarter 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 employee who was fatally injured. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System, which was directly caused by the fire. The Coffeyville refinery returned to operations in mid-August, with all units except the isomerization unit in operation by August 23, 2014. The isomerization unit started operating on October 12, 2014. This interruption adversely impacted production of refined products for the 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, 2014 were 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 $5.0 million for the Coffeyville refinery. The Refining Partnership anticipates amounts in excess of the $5.0 million deductible related to the isomerization unit fire incident will be recoverable under the property insurance policies. As of December 31, 2015 and 2014, the Refining Partnership had an insurance receivable related to the incident of approximately $1.2 million and $1.3 million, respectively, which is included in prepaid expenses and other current assets in the Consolidated Balance Sheets. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).
During the fourth quarter of 2014, the FCCU at the Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at the Wynnewood refinery was significantly reduced during the fourth quarter of 2014. Additionally, the Refining Partnership incurred approximately $8.5
million in costs to repair the FCCU for the year ended December 31, 2014. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
Nitrogen Fertilizer Business
In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Natural gas is the most significant raw material required in its competitors' production of nitrogen fertilizer. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstockcosts and uses a minimal amount of natural gas as an energy source in its operations. Instead, the adjacent Coffeyville refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needs pursuant to a 20-year pet coke supply agreement entered into in October 2007. expenses.
The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability 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. An expansion or upgrade of competitors' facilities, new facility development, political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the 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 production in the region. The combination of higher nitrogen fertilizer prices globally and a feedstock cost advantage led to high margins for North American nitrogen fertilizer producers. This resulted in numerous announcements for expansion plans for existing plants as well as new facility development in the corn belt and the gulf coast. The substantial majority of the additional supply from this expansion phase in North America is expected to comecame online in 2016.2017. The nitrogen fertilizer business expects product pricing may experience volatility as the new supply displaces imports into the gulf coast and corn belt.U.S.. 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 more challenging worldwide economic considerations. During 2015, there were announced transactions for further consolidation in the North American nitrogen fertilizer 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-termshorter-term volatility given the inherent nature of the commodity cycle, the longer-term fundamentals for the U.S. nitrogen fertilizer industry remain intact. The nitrogen fertilizer business views the anticipated combination of (i) increasing global population, (ii) decreasing arable land per capita, (iii) continued evolution to more protein-based diets in developing countries, (iv) sustained use of corn as feedstock for the domestic production of ethanol 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 theits operating performance, of the nitrogen fertilizer business, the nitrogen fertilizer business calculates the product pricing at gate as an input to determine its operating margin. Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. The nitrogen 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)("sold gate") and delivered to the customer's designated delivery site (sold delivered)("sold delivered"). The relative percentage of sold gate versus sold delivered can change period 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 its 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 all of its products in the higher margin agricultural market. Further, the nitrogen fertilizer business believes that a significant portion of its competitors' revenues are derived from the lower margin industrial market. The nitrogen fertilizer business' products leave the plantCoffeyville Fertilizer Facility either in railcars for destinations located principally on the Union Pacific Railroad or in trucks for direct shipment to customers. The nitrogen fertilizer business does not currently incur significant intermediate transfer, storage, barge freight or pipeline freight charges; however, it does incur costs to maintain
and repair its railcar fleet. Selling productsfleet, including expenses related to regulatory inspections and repairs. For example, many of its railcars require specific regulatory inspections and repairs due on ten-year intervals. The extent and frequency of railcar fleet maintenance and repair costs are generally expected to change based partially on when regulatory inspections and repairs are due for our railcars under the relevant regulations.
The East Dubuque Facility is located in northwest Illinois, in the corn belt. The East Dubuque Facility primarily sells its product to customers located within economic rail transportation limits200 miles of the facility. In most instances, customers take delivery of nitrogen fertilizerproducts at the plant and keeping transportation costs low are keysarrange and pay to maintaining profitability.transport them to their final destinations by truck. The East Dubuque Facility has direct access to a barge dock on the Mississippi River as well as a nearby rail spur serviced by the Canadian National Railway Company.
As a result of the UAN expansion project completed in 2013, theThe nitrogen fertilizer business will continue to upgradeupgrades substantially all of its ammonia production at the Coffeyville Fertilizer Facility into UAN and will continue to do so for as long as it makes economic sense to do so. The value of nitrogen fertilizer products is also an important consideration in understanding the nitrogen fertilizer business' results.sense. For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, the nitrogen fertilizer business upgraded approximately 96%88%, 97%93% and 95%96%, respectively, of its ammonia production into UAN, a product that presently generates greater profit than ammonia. The East Dubuque Facility has the flexibility to significantly vary its product mix. This enables the nitrogen fertilizer business to upgrade its ammonia production into varying amounts of UAN, nitric acid and liquid and granulated urea each season, depending on market demand, pricing and storage availability. Product sales at the East Dubuque Facility are heavily weighted toward sales of ammonia and UAN. For both the year ended December 31, 2017 and post-acquisition period ended December 31, 2016, approximately 44%, of the East Dubuque Facility ammonia production tons were upgraded to other products.
The high fixed cost of the nitrogen fertilizer business'Coffeyville Fertilizer Facility's direct operating expense structure also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business hasCoffeyville Fertilizer Facility results in a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant.plant, such as the East Dubuque Facility. In addition, while less than the Coffeyville Fertilizer Facility, the East Dubuque Facility has a significant amount of fixed costs. Major fixed operating expenses include a large portion of electrical energy, employee labor, and maintenance, including contract labor, and outside services. The nitrogen fertilizer 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 at its Coffeyville Fertilizer Facility is pet coke, which it purchases from the petroleum business and third parties. For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, the nitrogen fertilizer business incurred approximately $11.9$8.1 million, $13.6$7.8 million and $14.6$11.9 million, respectively, for pet coke, which equaled an average cost per ton of $25, $28$17, $15 and $30,$25, respectively.
The nitrogen fertilizer business obtains most (over 70% on average duringbusiness' largest raw material expense used in the last five years)production of the pet cokeammonia at its East Dubuque Facility is natural gas, which it needspurchases from the adjacent Coffeyville crude oil refinery pursuantthird parties. The East Dubuque Facility's natural gas process results in a higher percentage of variable costs as compared to the pet coke supply agreement,Coffeyville Fertilizer Facility. For the year ended December 31, 2017, and procures2016 the remainder on the open market. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesserEast Dubuque Facility incurred approximately $26.3 million and $13.3 million for feedstock natural gas, which equaled an average cost of a pet coke price derived from the price received for UAN (the "UAN-based price") or a pet coke price index. The UAN-based price begins with a pet coke price of $25$3.26 and $2.87 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.MMBtu.
SafeConsistent, safe and reliable operations at the nitrogen fertilizer plantplants are critical to its financial performance and results of operations. Unplanned downtime ofIn addition, consistent, safe and reliable operations at the Linde air separation unit, which supplies oxygen, nitrogen and compressed dry air to the Coffeyville Facility, is critical to the nitrogen fertilizer plantbusiness financial performance and results of operations. Unplanned downtime at either of the facilities or at the Linde air separation unit may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process 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
Historically, the Coffeyville Fertilizer Facility has undergone a full facility turnaround approximately every two to three years. Turnarounds are expected to last 14-21 days. A less involved facility shutdown was performed during the second quarter of 2014 and included both the installation of a waste heat boiler and the completion of several key tasks in order to upgrade the pressure swing adsorption ("PSA") unit. The NitrogenCoffeyville Fertilizer PartnershipFacility underwent a full facility turnaround in the third quarter of 2015 and the gasification,gasifier, ammonia and UAN units were down for between 17 to 20 days each at a cost of approximately $7.0 million, exclusive of the impacts due to the lost production during the downtime, of approximately $7.0 million for the year ended December 31, 2015, respectively.downtime. The Nitrogen Fertilizer PartnershipCoffeyville Facility is planning to undergo the next scheduled full facility turnaround in the second halfquarter of 2017.2018, which is expected to last approximately 15 days at an estimated cost of $7.0 million, exclusive of the impact of the lost production during the downtime.
Historically, the East Dubuque Facility has also undergone a full facility turnaround approximately every two to three years. The East Dubuque Facility underwent a full facility turnaround in the second quarter of 2016 and the ammonia and UAN units were down for approximately 28 days at a cost of approximately $6.6 million, exclusive of the impacts due to the lost production during the downtime. The nitrogen fertilizer business determined that there were more pressing preventative maintenance issues at the East Dubuque Facility, so it completed a scheduled turnaround at the East Dubuque Facility in the third quarter of 2017 and the ammonia and UAN units were down for approximately 14 days at a cost of approximately $2.6 million, exclusive of the impacts of the lost production during the downtime.
Subsequent to the fourth quarter of 2017, the East Dubuque Facility experienced an additional outage caused by a boiler feed water leak resulting in 12 days of downtime, and the associated repair costs were not material.
Agreements With the Refining Partnership and the Nitrogen Fertilizer Partnership
We are party to several agreements with the Nitrogen Fertilizer Partnership that govern the business relations among the Nitrogen Fertilizer Partnership and 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 of our 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 the nitrogen fertilizer business; (ii) a services agreement, pursuant to which our management operateswe provide certain services to the nitrogen fertilizer business; (iii) a feedstock and shared services agreement, which governs the provision of feedstocks, including, but not limited to, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iv) a hydrogen purchase and sale agreement, which governs the purchase of hydrogen for the Coffeyville Fertilizer Facility; (v) a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; (v)(vi) an easement agreement; (vi)(vii) an environmental agreement; and (vii)(viii) a lease agreement pursuant to which the petroleum business leases office space and laboratory space to the Nitrogen Fertilizer Partnership. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.
In connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining Partnership, including (i) a $250.0$150.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operateswe provide certain services to the petroleum business.
Simultaneously with the execution of the Merger Agreement discussed The intercompany credit facility matures in Part II, Item 8, Note 1 ("Organization and History of the Company") of this Report, the Nitrogen Fertilizer Partnership entered into a commitment letter (the "commitment letter") with CRLLC. Refer to Part II, Item 7, "Liquidity and Capital Resources" of this Report for further discussion of the commitment letter.January 2019.
On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. Simultaneously with the execution of the Merger Agreement, the Nitrogen Fertilizer Partnership entered into a commitment letter (the "commitment letter") with CRLLC and a $300.0 million senior term loan credit facility (the "CRLLC Facility") with CRLLC. Refer to Part II, Item 7, "Liquidity and Capital Resources"8, Note 18 ("Related Party Transactions") of this Report for further discussion of the guaranty terms.CRLLC Facility.
Crude Oil Supply Agreement
On August 31, 2012, Coffeyville Resources RefiningRefer to Part II, Item 8, Note 15 ("Commitments and Marketing, LLC ("CRRM"Contingencies") and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (as amended,of this Report for information on the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps the petroleum business to reduce its inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.supply agreement.
Joint Ventures
Refer to Part II, Item 8, Note 7 ("Equity Method Investments") of this Report for information on the joint ventures.
Factors Affecting Comparability
Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons presented and discussed below.
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| | | (in millions) |
| Loss on extinguishment of debt(1) | | $ | — |
| | $ | — |
| | $ | 26.1 |
|
| Share-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 | ) | | — |
| | — |
|
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | (in millions) |
| Loss on extinguishment of debt(1) | | $ | — |
| | $ | 4.9 |
| | $ | — |
|
| Loss on derivatives, net | | 69.8 |
| | 19.4 |
| | 28.6 |
|
| Major scheduled turnaround expenses(2) | | 83.0 |
| | 38.1 |
| | 109.2 |
|
| Flood insurance recovery(3) | | — |
| | — |
| | (27.3 | ) |
| |
| (1) | Represents a loss on extinguishment of debt incurred by CVR Partners in June 2016 in connection with the repurchase of senior notes assumed in the East Dubuque Merger, which includes a prepayment premium and write-off of previously deferred financing costs,the unamortized original issue discount and the premium paid related to the extinguishment of the 10.875% Second Lien Senior Secured Notes due 2017 (the "Old Second Lien Notes").purchase accounting adjustment. |
| |
| (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 $5.5 million in 2014),Wynnewood refineries, the Wynnewood refinery ($1.3 million in 2014)East Dubuque Facility and the nitrogen fertilizer plant ($7.0 million in 2015).Coffeyville Facility. |
| |
(4)(3) | Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery onin June/July 2007. Refer to Part II, Item 8, Note 1315 ("Commitments and Contingencies") of this Report for further details. |
East Dubuque Merger
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the East Dubuque Merger, whereby it acquired the East Dubuque Facility. The consolidated financial statements and key operating metrics of the nitrogen fertilizer business include the results of the East Dubuque Facility beginning on April 1, 2016, the date of the closing of the acquisition. Refer to Part II, Item 8, Note 3 ("Acquisition") of this Report for further discussion.
Noncontrolling Interest
Prior to the Refining Partnership IPO on January 23, 2013, the noncontrolling interest reflected in our consolidated financial statements represented the approximately 30% interest in the Nitrogen Fertilizer Partnership held by public common unitholders, which was adjusted each reporting period for the noncontrolling 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 an
approximately 19% interest of the Refining Partnership. Effective with the Refining Partnership's IPO, the noncontrolling interest reflected on the Consolidated Balance Sheets was impacted additionally by the noncontrolling ownership percentage of the net income of the Refining Partnership and related distributions for each future reporting period. As a result of the Refining Partnership's closing of the Underwritten Offering, the noncontrollingThe non-controlling interest related to the Refining Partnership reflected in our consolidated financial statements subsequent to the completion of the offering in the second quarter of 2013 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 the underwriters' option associated with the Second Underwritten Offering, the noncontrolling interest reflected in our consolidated financial statements is approximately 34%. Additionally, as a result
Immediately following the closing of the Nitrogen Fertilizer Partnership's Secondary Offering,East Dubuque Merger and as of December 31, 2017, the noncontrolling interest related to the Nitrogen Fertilizer Partnership reflected in our consolidated financial statements subsequentis approximately 66%. Prior to April 1, 2016, the noncontrolling interest related to the completion of the Secondary Offering on May 28, 2013 and as of December 31, 2015 isNitrogen Fertilizer Partnership reflected in our consolidated financial statements was approximately 47%.
The revenue and expenses from the Refining Partnership and Nitrogen Fertilizer Partnership are consolidated with CVR Energy's Consolidated Statements of Operations because each of the general partners is owned by CVR Refining Holdings and CRLLC, respectively, wholly-owned subsidiaries of CVR Energy. Therefore, CVR Energy has the ability to control the activities of the Refining Partnership and Nitrogen Fertilizer Partnership. However, the percentage of ownership held by the public unitholders for the Refining Partnership and the Nitrogen Fertilizer Partnership is reflected as net income attributable to noncontrolling interest in our Consolidated Statements of Operations and reduces consolidated net income to derive net income attributable to CVR Energy.
Distributions to CVR Partners Unitholders
Refer to Part II, Item 5, "CVR Partners, LP Cash Distribution Policy," of this Report for a summary of CVR Partners' distribution policy and the cash distributions paid to the Nitrogen Fertilizer Partnership unitholders during the years ended December 31, 20152017 and 2014.2016.
Distributions to CVR Refining Unitholders
Refer 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 cash distributions paid to the Refining Partnership unitholders during the years ended December 31, 20152017 and 2014.2016.
CVR Energy Dividends
Refer 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 our stockholders during the years ended December 31, 20152017 and 2014.2016.
Industry Factors
Petroleum Business
Earnings for the petroleum business depend largely on its refining margins, which have been and continue to be volatile. Refining margins are impacted primarily by the relationship or spread between crude oil and refined product prices. The petroleum business' refineries reside in the Group 3 marketing region 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 with limited export capacity provides an advantaged crude to the mid-continent refiners. As a result of an expansion project, the petroleum business increased its ability 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 its approximately 7.06.4 million barrels of crude oil storage in Cushing, Oklahoma and other locations allows it to take advantage of the contango market when such conditions exist. Contango markets are generally characterized by prices for future delivery that are higher than the current, or spot, price of a commodity. This condition provides economic incentive to hold or carry a commodity in inventory.
Nitrogen Fertilizer Business
Global demandCommodities
The nitrogen fertilizer business' products are globally traded commodities and are subject to price competition. The customers for fertilizers is driven primarily by population growth, dietaryits products make their purchasing decisions principally on the basis of delivered price and, to a lesser extent, on customer service and product quality. The selling prices of its products fluctuate in response to global market conditions and changes in the developing worldsupply 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 to increase by 45% between 2005 and 2030 to meet global food demand according to a study funded by the Food and Agricultural Organization of the United Nations. Currently, the developed world uses fertilizer more intensively than the developing world, but sustained economic growth in emerging markets is increasing food demand and fertilizer use. As an example, China's wheat and coarse grains production increased 51% between 2005 and 2015, but still failed to 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 States Department of Agriculture ("USDA").demand.
World grain demand increased 9%, from 2012 to 2015, according to the USDA, leading to a tighter grain supply environment and significant increases in grain 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. At existing 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 historically the world's first or second largest importer of nitrogen fertilizer, importing approximately 42% of its nitrogen fertilizer needs during the 2014-2015 marketing year. North American producers have a significant and sustainable cost advantage over the majority of producers that export to the U.S. market.
Agricultural
The three primary forms of nitrogen fertilizer used in the U.S.United States of America are ammonia, urea and UAN. Unlike ammonia and urea, UAN can be applied throughout the growing 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.
Nutrients are depleted in soil over time and therefore must be replenished through fertilizer use. Nitrogen is the most quickly depleted nutrient and must be replenished every year, whereas phosphate and potassium can be retained in soil for up to three years. Plants require nitrogen in the largest amounts and it accounts for approximately 57% of primary fertilizer consumption on a nutrient ton basis, per the International Fertilizer Industry Association.
Supply and Demand Factors
Global demand for fertilizers is driven primarily by grain demand and prices, which, in turn, are driven by population growth, farmland per capita, dietary changes in the developing world and increased consumption of bio-fuels. According to the International Fertilizer Industry Association, from 1974 to 2015, global fertilizer demand grew 2.0% annually. Global fertilizer use, consisting of nitrogen, phosphate and potassium, is projected to increase by 34% between 2010 and 2030 to meet global food demand according to a study funded by the Food and Agricultural Organization of the United Nations. Currently, the developed world uses fertilizer more intensively than the developing world, but sustained economic growth in emerging markets is increasing food demand and fertilizer use. In addition, populations in developing countries are shifting to more protein-rich diets as their incomes increase, with such consumption requiring more grain for animal feed. As an example, China's wheat and coarse grains production is estimated to have increased 33% between 2007 and 2017, but still failed to keep pace with increases in demand, prompting China to grow its wheat and coarse grain imports by more than 1,200% over the same period, according to the United States Department of Agriculture ("USDA").
The United States is the world's largest exporter of coarse grains, accounting for 34% of world exports and 30% of world production for the fiscal year ended September 30, 2017, according to the USDA. A substantial amount of nitrogen is consumed in production of these crops to increase yield. Based on Fertecon's 2017 estimates, the United States is the world's third largest consumer of nitrogen fertilizer and the world's largest importer of nitrogen fertilizer. Fertecon estimates indicate that the United States represented 11% of total global nitrogen fertilizer consumption for 2017, with China and India as the top consumers representing 27% and 14% of total global nitrogen fertilizer consumption, respectively.
North American nitrogen fertilizer producers predominantly use natural gas as their primary feedstocks. Over the last five years, U.S. oil and natural gas reserves have increased significantly due to, among other factors, advances in extracting shale oil and gas as well as relatively high oil and gas prices. More recently, global demand has slowed with production staying steady even as oil and gas prices have declined substantially over the past two years. This has led to significantly reduced natural gas and oil prices as compared to historical prices. As a result, North America has become a low-cost region for nitrogen fertilizer production.
The decline of natural gas prices have led to existing and new producers considering construction of new or expanding existing nitrogen fertilizer production facilities in the United States. The substantial majority of the incremental nitrogen fertilizer supply associated with the construction of confirmed new production facilities is expected to be online in 2018. Once the increased production comes on-stream, Blue, Johnson & Associates, Inc. expects the United States will still require net imports into the United States to meet domestic demand for nitrogen fertilizers.
2017 Market Conditions
The nitrogen fertilizer business' 2017 results were impacted by new U.S. domestic nitrogen production and the resulting low nitrogen fertilizer selling prices. Through most of 2017, pricing for U.S. nitrogen fertilizer often traded below parity with international pricing due to the new U.S. supply. Seasonal decreases in agricultural demand combined with delayed customer purchasing activity resulted in multi-year lows in nitrogen fertilizer selling prices during the second half of the year. The average selling price for UAN in 2017 was $152 per ton compared to $177 per ton in 2016, a decrease of 14% and the average selling price for ammonia in 2017 was $280 per ton compared to $376 per ton in 2016. In addition, during periods of declining prices, customers tend to delay purchasing fertilizer in anticipation of a continued price decline, which has also negatively impacted nitrogen fertilizer's sales volume.
Results of Operations
In this "Results of Operations" section, we first review our business on a consolidated basis, and then separately review the results of operations of each of our petroleum and nitrogen fertilizer businesses on a standalone basis.
Consolidated Results of Operations
The period to period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. This "Results of Operations" section compares the year ended December 31, 20152017 with the year ended December 31, 20142016 and the year ended December 31, 20142016 with the year ended December 31, 2013.2015.
Net sales consist principally of sales of refined fuel and nitrogen fertilizer products. For the petroleum business, net sales are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, 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 to as crack spreads. See " — Major Influences on Results of Operations." We discuss the results of the petroleum business in the context of per barrel consumed crack spreads and the relationship between net sales and cost of product sold.materials and other. Refining margin is a measurement calculated as the difference between net sales and cost of materials and other.
Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of the petroleum and nitrogen fertilizer businesses.
The following table provides an overview of our results of operations during the past three fiscal years:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Statements of Operations Data | | | | | | |
| Consolidated Statements of Operations Data | | | | | | |
| Net sales | $ | 5,432.5 |
| | $ | 9,109.5 |
| | $ | 8,985.8 |
| $ | 5,988.4 |
| | $ | 4,782.4 |
| | $ | 5,432.5 |
|
| Cost of product sold(1) | 4,190.4 |
| | 8,066.0 |
| | 7,563.2 |
| |
| Operating costs and expenses: | | | | | | |
| Cost of materials and other | | 4,882.9 |
| | 3,847.5 |
| | 4,190.4 |
|
| Direct operating expenses(1) | 584.7 |
| | 515.1 |
| | 455.8 |
| 599.5 |
| | 541.8 |
| | 584.7 |
|
| Depreciation and amortization | | 203.3 |
| | 184.5 |
| | 156.4 |
|
| Cost of sales | | 5,685.7 |
| | 4,573.8 |
| | 4,931.5 |
|
| Flood insurance recovery | (27.3 | ) | | — |
| | — |
| — |
| | — |
| | (27.3 | ) |
| Selling, general and administrative expenses(1) | 99.0 |
| | 109.7 |
| | 113.5 |
| 114.2 |
| | 109.1 |
| | 99.0 |
|
| Depreciation and amortization | 164.1 |
| | 154.4 |
| | 142.8 |
| 10.7 |
| | 8.6 |
| | 7.7 |
|
| Operating income | 421.6 |
| | 264.3 |
| | 710.5 |
| 177.8 |
| | 90.9 |
| | 421.6 |
|
| Interest expense and other financing costs | (48.4 | ) | | (40.0 | ) | | (50.5 | ) | (110.1 | ) | | (83.9 | ) | | (48.4 | ) |
| Interest income | 1.0 |
| | 0.9 |
| | 1.2 |
| 1.1 |
| | 0.7 |
| | 1.0 |
|
| Gain (loss) on derivatives, net | (28.6 | ) | | 185.6 |
| | 57.1 |
| |
| Loss on derivatives, net | | (69.8 | ) | | (19.4 | ) | | (28.6 | ) |
| Loss on extinguishment of debt | — |
| | — |
| | (26.1 | ) | — |
| | (4.9 | ) | | — |
|
| Other income (expense), net | 36.7 |
| | (3.7 | ) | | 13.5 |
| |
| Income before income tax expense | 382.3 |
| | 407.1 |
| | 705.7 |
| |
| Income tax expense | 84.5 |
| | 97.7 |
| | 183.7 |
| |
| Other income, net | | 1.0 |
| | 5.7 |
| | 36.7 |
|
| Income (loss) before income tax expense | | — |
| | (10.9 | ) | | 382.3 |
|
| Income tax expense (benefit) | | (216.9 | ) | | (19.8 | ) | | 84.5 |
|
| Net income | 297.8 |
| | 309.4 |
| | 522.0 |
| 216.9 |
| | 8.9 |
| | 297.8 |
|
| Less: Net income attributable to noncontrolling interest | 128.2 |
| | 135.5 |
| | 151.3 |
| |
| Less: Net income (loss) attributable to noncontrolling interest | | (17.5 | ) | | (15.8 | ) | | 128.2 |
|
| Net income attributable to CVR Energy stockholders | $ | 169.6 |
| | $ | 173.9 |
| | $ | 370.7 |
| $ | 234.4 |
| | $ | 24.7 |
| | $ | 169.6 |
|
| | | | | | | | | | | |
| Basic earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
| |
| Diluted earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
| |
| Basic and diluted earnings per share | | $ | 2.70 |
| | $ | 0.28 |
| | $ | 1.95 |
|
| Dividends declared per share | $ | 2.00 |
| | $ | 5.00 |
| | $ | 14.25 |
| $ | 2.00 |
| | $ | 2.00 |
| | $ | 2.00 |
|
| Adjusted EBITDA(2) | $ | 498.8 |
| | $ | 473.5 |
| | $ | 659.7 |
| $ | 258.4 |
| | $ | 181.6 |
| | $ | 498.8 |
|
| | | | | | | | | | | |
| Weighted-average common shares outstanding: | | | | | | | | | | |
| Basic | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Basic and diluted | | 86.8 |
| | 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 |
| | $ | 5.0 |
|
| Depreciation and amortization excluded from direct operating expenses | 149.7 |
| | 141.8 |
| | 134.5 |
|
| Depreciation and amortization excluded from selling, general and administrative expense | 7.7 |
| | 6.3 |
| | 3.3 |
|
| Total depreciation and amortization | $ | 164.1 |
| | $ | 154.4 |
| | $ | 142.8 |
|
| |
| (2) | EBITDA and Adjusted EBITDA. EBITDA represents net income attributable to CVR Energy stockholders before consolidated (i) interest expense and other financing costs, net of interest income,income; (ii) income tax expense (benefit); and (iii) depreciation and amortization.amortization, less the portion of these adjustments attributable to non-controlling interest. Adjusted EBITDA represents EBITDA adjusted for consolidated (i) FIFO impact (favorable) unfavorable,unfavorable; (ii) share-based compensation, (iii) loss on extinguishment of debt, (iv)debt; (iii) major scheduled turnaround expenses (v) gain (loss)(that many of our competitors capitalize and thereby exclude from their measures of EBITDA and Adjusted EBITDA); (iv) (gain) loss on derivatives, net, (vi)net; (v) current period settlements on derivative contracts, (vii)contracts; (vi) flood insurance recovery and (viii)recovery; (vii) expenses associated with the pending Rentech Nitrogen mergers.East Dubuque Merger; and (viii) business interruption insurance recovery, less the portion of these adjustments attributable to non-controlling interest. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income or cash flow from operations. Management believesWe believe that EBITDA and Adjusted EBITDA enable investors to better understand and evaluate our 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 these terms differently. Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the years ended December 31, 2015, 2014represent EBITDA and 2013:Adjusted EBITDA that is attributable to CVR Energy stockholders. |
EBITDA for the years ended December 31, 2015 was also adjusted for share-based compensation expense in calculating Adjusted EBITDA. Beginning in 2016, share-based compensation expense is no longer utilized as an adjustment to derive Adjusted EBITDA as no equity-settled awards remain outstanding for CVR Energy or any of its subsidiaries, and CVR Partners and CVR Refining are responsible for reimbursing CVR Energy for their allocated portion of all outstanding awards. We believe, based on the nature, classification and cash settlement feature of the currently outstanding awards, that it is no longer necessary to adjust EBITDA for share-based compensation expense to derive Adjusted EBITDA. For comparison purposes we have also provided Adjusted EBITDA for the year ended December 31, 2015 without adjusting for share-based compensation expense in order to provide a comparison to Adjusted EBITDA for the years ended December 31, 2017 and 2016.
Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the years ended December 31, 2017, 2016 and 2015:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| | (unaudited) | (unaudited) |
| Net income attributable to CVR Energy stockholders | $ | 169.6 |
| | $ | 173.9 |
| | $ | 370.7 |
| $ | 234.4 |
| | $ | 24.7 |
| | $ | 169.6 |
|
| Add: | | | | | | | | | | |
| Interest expense and other financing costs, net of interest income | 47.4 |
| | 39.1 |
| | 49.3 |
| 109.0 |
| | 83.2 |
| | 47.4 |
|
| Income tax expense | 84.5 |
| | 97.7 |
| | 183.7 |
| |
| Income tax expense (benefit) | | (216.9 | ) | | (19.8 | ) | | 84.5 |
|
| Depreciation and amortization | 164.1 |
| | 154.4 |
| | 142.8 |
| 214.0 |
| | 193.1 |
| | 164.1 |
|
| EBITDA adjustments included in noncontrolling interest | (75.2 | ) | | (65.2 | ) | | (50.1 | ) | |
| Adjustments attributable to noncontrolling interest | | (151.2 | ) | | (127.3 | ) | | (75.2 | ) |
| EBITDA | 390.4 |
| | 399.9 |
| | 696.4 |
| 189.3 |
| | 153.9 |
| | 390.4 |
|
| Add: | | | | | | | | | | |
| FIFO impact (favorable) unfavorable | 60.3 |
| | 160.8 |
| | (21.3 | ) | |
| FIFO impact, (favorable) unfavorable | | (29.6 | ) | | (52.1 | ) | | 60.3 |
|
Share-based compensation | 12.8 |
| | 12.3 |
| | 18.4 |
| — |
| | — |
| | 12.8 |
|
Loss on extinguishment of debt | — |
| | — |
| | 26.1 |
| — |
| | 4.9 |
| | — |
|
| Major scheduled turnaround expenses | 109.2 |
| | 6.8 |
| | — |
| 83.0 |
| | 38.1 |
| | 109.2 |
|
| (Gain) loss on derivatives, net | 28.6 |
| | (185.6 | ) | | (57.1 | ) | |
| Loss on derivatives, net | | 69.8 |
| | 19.4 |
| | 28.6 |
|
Current period settlement on derivative contracts(a)(c) | (26.0 | ) | | 122.2 |
| | 6.4 |
| (16.6 | ) | | 36.4 |
| | (26.0 | ) |
Flood insurance recovery(b)(d) | (27.3 | ) | | — |
| | — |
| — |
| | — |
| | (27.3 | ) |
| Expenses associated with the Rentech Nitrogen mergers(c) | 2.3 |
| | — |
| | — |
| |
| Adjustments included in noncontrolling interest | (51.5 | ) | | (42.9 | ) | | (9.2 | ) | |
| Expenses associated with the East Dubuque Merger(e) | | — |
| | 3.1 |
| | 2.3 |
|
| Insurance recovery - business interruption(f) | | (1.1 | ) | | (2.1 | ) | | — |
|
| Adjustments attributable to noncontrolling interest | | (36.4 | ) | | (20.0 | ) | | (51.5 | ) |
| Adjusted EBITDA | $ | 498.8 |
| | $ | 473.5 |
| | $ | 659.7 |
| $ | 258.4 |
| | $ | 181.6 |
| | $ | 498.8 |
|
| |
| (a) | Adjusted EBITDA for the year ended December 31, 2015 would have been $486.0 million without adjusting for share-based compensation expense of $12.8 million. |
| |
| (b) | Represents a loss on extinguishment of debt incurred by CVR Partners in June 2016 in connection with the repurchase of senior notes assumed in the East Dubuque Merger, which includes a prepayment premium and write-off of the unamortized purchase accounting adjustment. |
| |
| (c) | Represents the portion of gain (loss)(gain) loss on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts. |
| |
(b)(d) | Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery onin June/July 2007. Refer to Part II, Item 8, Note 1315 ("Commitments and Contingencies") of this Report for further details. |
| |
(c)(e) | Represents legal and other professional fees and other merger-relatedmerger related expenses incurred bythat are referred to herein as transaction expenses associated with the Nitrogen Fertilizer PartnershipEast Dubuque Merger, which are included in regards to the pending Rentech Nitrogen mergers. Refer to Part II, Item 8, Note 1 ("Organizationselling, general and History of the Company") of this Report for further details.administrative expenses. |
| |
| (f) | Represents business interruption insurance recovery of $1.1 million and $2.1 million received by CVR Partners during 2017 and 2016, respectively. |
Year Ended December 31, 20152017 Compared to the Year Ended December 31, 20142016 (Consolidated)
Net Sales. Consolidated net sales were $5,988.4 million for the year ended December 31, 2017, compared to $4,782.4 million for the year ended December 31, 2016. The increase of $1,206.0 million was largely the result of an increase in our petroleum segment's net sales of $1,232.9 million due to higher sales prices of its transportation fuels and by-products offset by a decrease in net sales in our nitrogen fertilizer segment. The petroleum segment's average sales price per gallon for the year ended December 31, 2017 was $1.59 for gasoline and $1.66 for distillate which increased by 18.7% and 22.1%, respectively, as compared to the year ended December 31, 2016. The nitrogen fertilizer segment's net sales decreased by $25.5 million primarily attributable to lower UAN and ammonia sales prices and lower UAN sales volumes, partially offset by higher ammonia sales volumes.
Cost of Materials and Other. Consolidated cost of materials and other was $4,882.9 million for the year ended December 31, 2017, as compared to $3,847.5 million for the year ended December 31, 2016. The increase of $1,035.4 million primarily resulted from a increase of $1,045.5 million in cost of materials and other at the petroleum segment, partially offset by a decrease of $8.8 million in cost of materials and other at the nitrogen fertilizer segment. The increase at the petroleum segment was due to an increase in the cost of consumed crude and purchased products for resale. The increase in consumed crude oil costs was due to a 17% increase in WTI crude oil prices. The decrease of $8.8 million at the nitrogen fertilizer segment was primarily due to higher costs in 2016 from inventory and deferred revenue fair value adjustments and decreased current year distribution costs due to the timing of regulatory railcar repairs and maintenance.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $599.5 million for the year ended December 31, 2017, as compared to $541.8 million for the year ended December 31, 2016. The increase of $57.7 million was primarily due to an increase of $50.4 million at the petroleum segment and an increase of $7.2 million at the nitrogen fertilizer segment. The petroleum segment increased as a result of higher costs for the first phase of major scheduled turnaround activities performed at its Wynnewood refinery in 2017 as compared to the second phase of the major scheduled turnaround activities completed in 2016, coupled with higher utilities costs. The nitrogen fertilizer segment's increase was primarily attributable to higher utility costs from increased electrical rates, partially offset by turnaround costs.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $114.2 million for the year ended December 31, 2017, as compared to $109.1 million for the year ended December 31, 2016. The increase of $5.1 million was primarily attributable to the increase in share-based compensation which resulted from an increase in the petroleum segment's unit price in 2017, partially offset by higher expenses in 2016 associated with the East Dubuque merger at the nitrogen fertilizer segment.
Operating Income. Consolidated operating income was $177.8 million for the year ended December 31, 2017, as compared to operating income of $90.9 million for the year ended December 31, 2016, a increase of $86.9 million. Petroleum segment operating income increased $126.0 million primarily as a result of an increase in the refining margin due to higher sales prices for our transportation fuels and by-products which was partially offset by increases in direct operating expense, depreciation and amortization and selling, general and administrative expenses. Nitrogen fertilizer segment operating income decreased $36.0 million primarily as a result of decreases in net sales, increases in direct operating expenses, depreciation and amortization, partially offset by decreases in cost of materials and other and selling, general and administrative expenses.
Interest Expense. Consolidated interest expense for the year ended December 31, 2017 was $110.1 million as compared to $83.9 million for the year ended December 31, 2016. The increase of $26.2 million resulted primarily from the Nitrogen fertilizer segment's increased borrowings and a full year of interest payments in 2017 on the 2023 Notes. The 2023 Notes were issued in June 2016.
Loss on Derivatives, Net. For the year ended December 31, 2017, the petroleum segment recorded a $69.8 million net loss on derivatives compared to a $19.4 million net loss for the year ended December 31, 2016. This change was primarily due to an increase in open positions from 4.0 million barrels to 14.3 million barrels, which resulted in a $38.3 million net loss. The petroleum segment enters into commodity hedging instruments in order to fix the price on a portion of its future crude oil purchases and to fix the margin on a portion of future production. In addition, the Refining Partnership had open forward purchase and sale commitments of 5.8 million barrels of Canadian crude oil which resulted in a $26.0 million unrealized net loss.
Income Tax Expense (Benefit). Income tax benefit for the year ended December 31, 2017 was $216.9 million compared to income tax benefit for the year ended December 31, 2016 of $19.8 million. The income tax benefit recognized in 2017 varies significantly from the expected federal and state benefit at the statutory rate of 39.2% primarily due to the benefits recognized from the remeasurement of the Company’s net deferred tax liabilities as a result of the enactment in December 2017 of the Tax Cuts and Jobs Act (“TCJA”) legislation, certain state income tax items and the exclusion of income associated with the noncontrolling interests in CVR Refining’s and CVR Partners’ earnings (loss). The TCJA reduces the federal income tax rate from 35% to 21% beginning in 2018. As a result, our net deferred tax liabilities at December 31, 2017 were remeasured to reflect the lower tax rate that will be in effect for the years in which the deferred tax assets and liabilities will be realized. A benefit of approximately $200.5 million was recognized as a result of the remeasurement.
Year Ended December 31, 2016 Compared to the Year Ended December 31 2015 (Consolidated)
Net Sales. Consolidated net sales were $4,782.4 million for the year ended December 31, 2016, compared to $5,432.5 million for the year ended December 31, 2015, compared to $9,109.5 million for the year ended December 31, 2014.2015. The decrease of $3,677.0$650.1 million was largely the result of a decrease in our petroleum segment's net sales of $3,667.8$730.6 million due to significantly lower sales prices.prices, partially offset by increased net sales in our nitrogen fertilizer segment. The petroleum segment's average sales price per gallon for the year ended December 31, 20152016 of $1.61$1.34 for gasoline and $1.62$1.36 for distillate decreased by 36.4%16.8% and 42.3%16.0%, respectively, as compared to the year ended December 31, 2014.2015. The nitrogen fertilizer segment net sales decreasedincreased by $9.5$67.1 million primarily attributable to increased sales volume associated with the inclusion of the nine months of the East Dubuque Facility, an increase in UAN and ammonia sales volume due to lower UAN sales prices and volumes,the major scheduled turn around at the Coffeyville Fertilizer Facility in 2015, partially offset by higherlower UAN and ammonia sales volumes.prices attributable to pricing fluctuation in the market.
Cost of Product Sold (Exclusive of DepreciationMaterials and Amortization).Other. Consolidated cost of product sold (exclusive of depreciationmaterials and amortization)other was $3,847.5 million for the year ended December 31, 2016, as compared to $4,190.4 million for the year ended December 31, 2015, as compared to $8,066.0 million for the year ended December 31, 2014.2015. The decrease of $3,875.6$342.9 million primarily resulted from a decrease of $3,869.8$384.4 million in cost of product soldmaterials and other at the petroleum segment, partially offset by an increase of $28.5 million in cost of materials and other at the nitrogen fertilizer segment. The decrease at the petroleum segment was due 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 in crude oil prices. The increase of $28.5 million at the nitrogen fertilizer segment was primarily due to the inclusion of the nine months of the East Dubuque Facility, partially offset by cost of product sold (exclusive of depreciation and amortization) also decreased by $6.8 million primarilydecreases as a result of lower freight and distribution costs andas well as lower consumption and lower pricingpet coke pricing.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) were $541.8 million for the year ended December 31, 2016, as compared to $584.7 million for the year ended December 31, 2015, as compared to $515.1 million for the year ended December 31, 2014.2015. The increasedecrease of $69.6$42.9 million was primarily due to an increasea decrease of $62.5$85.1 million at the petroleum segment, partially offset by an increase of $42.2 million at the nitrogen fertilizer segment. The petroleum segment decreased as a result of lower costs for the second phase of major scheduled turnaround activities performed at the Coffeyville refinery in 2016 as compared to the first phase completed in 2015, lower insurance expense, environmental expense and production chemicals, partially offset by decreasesan increase in repair and maintenance and energy and utilitylabor costs. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusiveincreased primarily attributable to the inclusion of depreciation and amortization), which was primarily the resultnine months of higher major scheduled turnaround expenses.the East Dubuque Facility.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $109.1 million for the year ended December 31, 2016, as compared to $99.0 million for the year ended December 31, 2015, as compared to $109.7 million for the year ended December 31, 2014.2015. The decreaseincrease of $10.7$10.1 million was primarily attributable to the resultinclusion of lower legal expenses, IT-related costs and consulting costs, partially offset by higher personnel costs.the nine months of the East Dubuque Facility.
Operating Income. Consolidated operating income was $90.9 million for the year ended December 31, 2016, as compared to operating income of $421.6 million for the year ended December 31, 2015, as compared to operating incomea decrease of $264.3 million for the year ended December 31, 2014, an increase of $157.3$330.7 million. Petroleum segment operating income increased $154.5decreased $283.9 million primarily due to higheras a result of a decrease in the refining marginsmargin in 2016 and the 2015 flood insurance recovery, partially offset by increaseddecreases in direct operating expenses, depreciation and amortization and selling, general and administrative expenses. Nitrogen fertilizer segment operating income decreased $14.1$41.9 million primarily as a result of lower net salesincreases in direct operating expenses, depreciation and higher direct operatingamortization, cost of materials and other and selling, general and administrative expenses, partially offset by lower cost of product sold.increases in net sales.
Interest Expense. Consolidated interest expense for the year ended December 31, 20152016 was $48.4$83.9 million as compared to $40.0$48.4 million for the year ended December 31, 2014.2015. The increase of $8.4$35.5 million resulted primarily from lower capitalized interest for the year ended December 31, 2015debt assumed by the Nitrogen fertilizer segment in the East Dubuque Merger, issuance of the 2023 Notes and increased LIBOR rates during 2016 as compared to the year ended December 31, 2014, following the completion of several larger capital projects in late 2014.2015.
Gain (Loss) on Derivatives, Net. For the year ended December 31, 2015,2016, the petroleum segment recorded a $28.6$19.4 million net loss on derivatives compared to a $185.6$28.6 million net gainloss on derivatives for the year ended December 31, 2014.2015. 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.
Income Tax Expense. Income tax expensebenefit for the year ended December 31, 20152016 was $84.5$19.8 million or 22.1%181.7% of incomeloss before income taxes, as compared to income tax expense for the year ended December 31, 20142015 of $97.7$84.5 million or 24.0%22.1% of income before income taxes. This is in comparison to a combined federal and state expected statutory rate of 39.3% for 2016 and 39.5% for 2015 and 39.6% for 2014.2015. Our 20152016 effective tax rate is lower thanvaries from the expected statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests in CVR Refining's and CVR Partners' earnings and(loss), the benefits related to the domestic production activities deduction (Section 199) and certain state income tax credits.items.
Net Income Attributable to Noncontrolling Interest. Net income attributable to noncontrolling interest represents the 47% interest in the Nitrogen Fertilizer Partnership held by public unitholders as of and for the years ended December 31, 2015 and 2014. Additionally, it represents the 34% interest in the Refining Partnership held by public unitholders from July 24, 2014
through December 31, 2015, the 33% interest held by public unitholders from June 30, 2014 through July 23, 2014 and the 29% interest held by public unitholders 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 ended December 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 sales volumes largely offset by lower sales prices for gasoline and distillates. The petroleum segment's average sales price per gallon for the year ended December 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 nitrogen fertilizer segment net sales decreased by $25.0 million due to lower UAN sales prices and lower ammonia sales volumes, partially offset by high UAN sales volumes.
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 $502.8 million 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 due to increases in the cost of consumed crude oil and higher refined fuels purchased for resale. The increase in consumed crude costs was due to higher consumed volumes, partially offset by lower crude oil prices. The nitrogen fertilizer segment cost of product sold (exclusive of depreciation and amortization) also increased $13.9 million primarily as a result of increased distribution costs due to increased railcar regulatory inspections and repairs and increased ammonia purchases.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Consolidated direct operating expenses (exclusive of depreciation and amortization) 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 increase of $59.3 million was primarily due to an increase at the petroleum segment for expenses related to energy and utility costs, repairs and maintenance and labor. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of higher energy and utility costs and refractory brick amortization.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $109.7 million for the year ended December 31, 2014, as compared to $113.5 million for the year ended December 31, 2013. The decrease of $3.8 million was primarily the result of lower share-based compensation and personnel costs, IT-related costs and consulting, 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 primarily due to lower refining margins and higher direct operating expenses. Nitrogen fertilizer segment operating income decreased $42.1 million primarily as a result 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 year ended December 31, 2013. The decrease of $10.5 million resulted primarily from interest expense on the outstanding 2022 Notes (as defined below) for the year 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 their extinguishment 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 to a $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 of debt. 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.
Income Tax Expense. Income tax expense for the year ended December 31, 2014 was $97.7 million or 24.0% of income before income taxes, as compared 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 a combined 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 rate primarily due to the reduction of income subject to tax associated with our noncontrolling ownership interest in CVR Refining's and CVR Partners' earnings and 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 Nitrogen Fertilizer 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 public unitholders 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 Operations
The petroleum business includes the operations of both the Coffeyville and Wynnewood refineries. The following tables below provide an overview of the petroleum business' results of operations, relevant market indicators and its key operating statistics for the years ended December 31, 2015, 20142017, 2016 and 2013:2015:
| | | | Year Ended December 31, | Year Ended December 31, |
| 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Consolidated Petroleum Business Financial Results | | | | | | | | | | |
| Net sales | $ | 5,161.9 |
| | $ | 8,829.7 |
| | $ | 8,683.5 |
| $ | 5,664.2 |
| | $ | 4,431.3 |
| | $ | 5,161.9 |
|
| Cost of product sold(1) | 4,143.6 |
| | 8,013.4 |
| | 7,526.7 |
| |
| Operating costs and expenses: | | | | | | |
| Cost of materials and other | | 4,804.7 |
| | 3,759.2 |
| | 4,143.6 |
|
| Direct operating expenses(1)(2) | 376.3 |
| | 409.2 |
| | 361.7 |
| 363.4 |
| | 361.9 |
| | 376.3 |
|
| Major scheduled turnaround expenses | 102.2 |
| | 6.8 |
| | — |
| 80.4 |
| | 31.5 |
| | 102.2 |
|
| Depreciation and amortization | | 129.3 |
| | 126.3 |
| | 128.0 |
|
| Cost of sales | | 5,377.8 |
| | 4,278.9 |
| | 4,750.1 |
|
| Flood insurance recovery | (27.3 | ) | | — |
| | — |
| — |
| | — |
| | (27.3 | ) |
| Selling, general and administrative expenses(1) | 75.2 |
| | 70.6 |
| | 77.8 |
| 78.8 |
| | 71.9 |
| | 75.2 |
|
| Depreciation and amortization | 130.2 |
| | 122.5 |
| | 114.3 |
| 3.8 |
| | 2.7 |
| | 2.2 |
|
| Operating income | 361.7 |
| | 207.2 |
| | 603.0 |
| 203.8 |
| | 77.8 |
| | 361.7 |
|
| Interest expense and other financing costs | (42.6 | ) | | (34.2 | ) | | (44.1 | ) | (47.2 | ) | | (43.4 | ) | | (42.6 | ) |
| Interest income | 0.4 |
| | 0.3 |
| | 0.4 |
| 0.5 |
| | 0.1 |
| | 0.4 |
|
| Gain (loss) on derivatives, net | (28.6 | ) | | 185.6 |
| | 57.1 |
| |
| Loss on extinguishment of debt | — |
| | — |
| | (26.1 | ) | |
| Other income (expense), net | 0.3 |
| | (0.2 | ) | | 0.1 |
| |
| Loss on derivatives, net | | (69.8 | ) | | (19.4 | ) | | (28.6 | ) |
| Other income, net | | 1.5 |
| | 0.2 |
| | 0.3 |
|
| Income before income tax expense | 291.2 |
| | 358.7 |
| | 590.4 |
| 88.8 |
| | 15.3 |
| | 291.2 |
|
| Income tax expense | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Net income | $ | 291.2 |
| | $ | 358.7 |
| | $ | 590.4 |
| $ | 88.8 |
| | $ | 15.3 |
| | $ | 291.2 |
|
| | | | | | | | | | | |
| Gross profit(3) | $ | 436.9 |
| | $ | 277.8 |
| | $ | 680.8 |
| $ | 286.4 |
| | $ | 152.4 |
| | $ | 439.1 |
|
| Refining margin(4) | $ | 1,018.3 |
| | $ | 816.3 |
| | $ | 1,156.8 |
| $ | 859.5 |
| | $ | 672.1 |
| | $ | 1,018.3 |
|
| Adjusted Petroleum EBITDA(5) | $ | 602.0 |
| | $ | 621.6 |
| | $ | 712.0 |
| $ | 372.6 |
| | $ | 222.8 |
| | $ | 602.0 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (dollars per barrel) |
| Key Operating Statistics | | | | | |
| Per crude oil throughput barrel: | | | | | |
| Gross profit(3) | $ | 3.83 |
| | $ | 2.10 |
| | $ | 6.23 |
|
| Refining margin(4) | 11.50 |
| | 9.27 |
| | 14.45 |
|
| FIFO impact, (favorable) unfavorable | (0.40 | ) | | (0.72 | ) | | 0.86 |
|
| Refining margin adjusted for FIFO impact(4) | 11.10 |
| | 8.55 |
| | 15.31 |
|
| Direct operating expenses and major scheduled turnaround expenses(1)(2) | 5.94 |
| | 5.43 |
| | 6.79 |
|
| Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6) | $ | 5.55 |
| | $ | 5.08 |
| | $ | 6.40 |
|
| Barrels sold (barrels per day)(6) | 218,912 |
| | 211,643 |
| | 204,708 |
|
|
| | | | | | | | | | | |
| | 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 |
| | $ | 16.90 |
|
| Gross profit(3) | $ | 6.20 |
| | $ | 3.87 |
| | $ | 9.94 |
|
| Direct operating expenses and major scheduled turnaround expenses(1)(2) | $ | 6.79 |
| | $ | 5.80 |
| | $ | 5.28 |
|
| Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6) | $ | 6.40 |
| | $ | 5.44 |
| | $ | 5.00 |
|
| Barrels sold (barrels per day)(6) | 204,708 |
| | 209,669 |
| | 198,142 |
|
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | | | % | | | | % | | | | % | | | % | | | | % | | | | % |
| Refining Throughput and Production Data (bpd) | | |
| | | | | | | |
| | | | | |
| Throughput: | | | | | | | | | | | | |
| Sweet | 176,097 |
| | 86.0 | | 179,059 |
| | 86.2 | | 149,147 |
| | 75.4 | 194,613 |
| | 89.8 | | 177,256 |
| | 84.8 | | 176,097 |
| | 86.0 |
| Medium | 2,460 |
| | 1.2 | | 2,022 |
| | 1.0 | | 19,151 |
| | 9.7 | — |
| | — | | 2,525 |
| | 1.2 | | 2,460 |
| | 1.2 |
| Heavy sour | 14,520 |
| | 7.1 | | 15,464 |
| | 7.4 | | 19,270 |
| | 9.8 | 10,135 |
| | 4.7 | | 18,261 |
| | 8.7 | | 14,520 |
| | 7.1 |
| Total crude oil throughput | 193,077 |
| | 94.3 | | 196,545 |
| | 94.6 | | 187,568 |
| | 94.9 | 204,748 |
| | 94.5 | | 198,042 |
| | 94.7 | | 193,077 |
| | 94.3 |
| All other feedstocks and blendstocks | 11,672 |
| | 5.7 | | 11,284 |
| | 5.4 | | 10,121 |
| | 5.1 | 12,032 |
| | 5.5 | | 11,077 |
| | 5.3 | | 11,672 |
| | 5.7 |
| Total throughput | 204,749 |
| | 100.0 | | 207,829 |
| | 100.0 | | 197,689 |
| | 100.0 | 216,780 |
| | 100.0 | | 209,119 |
| | 100.0 | | 204,749 |
| | 100.0 |
| Production: | | | | | | | | | | | | |
| Gasoline | 99,961 |
| | 48.5 | | 102,275 |
| | 48.9 | | 94,561 |
| | 47.7 | 110,226 |
| | 50.7 | | 108,762 |
| | 51.9 | | 99,961 |
| | 48.5 |
| Distillate | 85,953 |
| | 41.7 | | 87,639 |
| | 41.9 | | 82,089 |
| | 41.4 | 90,409 |
| | 41.6 | | 85,092 |
| | 40.6 | | 85,953 |
| | 41.7 |
| Other (excluding internally produced fuel) | 20,074 |
| | 9.8 | | 19,149 |
| | 9.2 | | 21,617 |
| | 10.9 | 16,818 |
| | 7.7 | | 15,751 |
| | 7.5 | | 20,074 |
| | 9.8 |
| Total refining production (excluding internally produced fuel) | 205,988 |
| | 100.0 | | 209,063 |
| | 100.0 | | 198,267 |
| | 100.0 | 217,453 |
| | 100.0 | | 209,605 |
| | 100.0 | | 205,988 |
| | 100.0 |
| Product price (dollars per gallon): | | | | | | | | | | | | |
| Gasoline | $ | 1.61 |
| | $ | 2.53 |
| | $ | 2.72 |
| | $ | 1.59 |
| | $ | 1.34 |
| | $ | 1.61 |
| |
| Distillate | 1.62 |
| | 2.81 |
| | 3.02 |
| | 1.66 |
| | 1.36 |
| | 1.62 |
| |
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Market Indicators (dollars per barrel) | | | | | | | | | | |
| West Texas Intermediate (WTI) NYMEX | $ | 48.76 |
| | $ | 92.91 |
| | $ | 98.05 |
| $ | 50.85 |
| | $ | 43.47 |
| | $ | 48.76 |
|
| Crude Oil Differentials: | | | | | | | | | | |
| WTI less WTS (light/medium sour) | (0.28 | ) | | 5.95 |
| | 2.64 |
| 0.97 |
| | 0.85 |
| | (0.28 | ) |
| WTI less WCS (heavy sour) | 13.20 |
| | 18.48 |
| | 24.58 |
| 12.69 |
| | 13.95 |
| | 13.20 |
|
| NYMEX Crack Spreads: | | | | | | | | | | |
| Gasoline | 19.89 |
| | 17.29 |
| | 21.44 |
| 17.46 |
| | 15.42 |
| | 19.89 |
|
| Heating Oil | 20.93 |
| | 23.59 |
| | 27.60 |
| 18.93 |
| | 13.89 |
| | 20.93 |
|
| NYMEX 2-1-1 Crack Spread | 20.41 |
| | 20.44 |
| | 24.52 |
| 18.19 |
| | 14.66 |
| | 20.41 |
|
| PADD II Group 3 Product Basis: | | | | | | | | | | |
| Gasoline | (2.12 | ) | | (4.45 | ) | | (4.54 | ) | (1.83 | ) | | (3.62 | ) | | (2.12 | ) |
| Ultra-Low Sulfur Diesel | (2.02 | ) | | 0.75 |
| | 0.58 |
| (0.50 | ) | | (0.92 | ) | | (2.02 | ) |
| PADD II Group 3 Product Crack Spread: | | | | | | | | | | |
| Gasoline | 17.76 |
| | 12.84 |
| | 16.90 |
| 15.63 |
| | 11.82 |
| | 17.76 |
|
| Ultra-Low Sulfur Diesel | 18.91 |
| | 24.34 |
| | 28.18 |
| 18.42 |
| | 12.96 |
| | 18.91 |
|
| PADD II Group 3 2-1-1 | 18.34 |
| | 18.59 |
| | 22.54 |
| 17.03 |
| | 12.39 |
| | 18.34 |
|
| |
| (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 oil throughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period. |
| |
| (3) | Gross profit, is a measurementGAAP measure, is calculated as the difference between net sales and cost of product sold (exclusive of depreciationmaterials and amortization)other , direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, flood insurance recovery and depreciation and amortization. Each of the components used in this calculation are taken directly from the petroleum business' financial results. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period. |
| |
| (4) | Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciationmaterials and amortization).other. 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 thetheir cost of product sold that it ismaterials and other at which they are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciationmaterials and amortization))other) 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 its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel isare 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. |
Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of materials and other adjusted for FIFO impact. Refining margin adjusted for FIFO impact 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 materials and other (taking into account the impact of our utilization of FIFO) at which they are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in the industry, thereby limiting its usefulness as a comparative measure. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. In order to derive the refining margin per crude oil throughput barrel adjusted for FIFO impact, we utilize the total dollar figures for refining margin adjusted for FIFO impact as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin adjusted for FIFO impact and refining margin per crude oil throughput barrel adjusted for FIFO impact are 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.
The calculation of refining margin, refining margin adjusted for FIFO impact, refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel (each a non-GAAP financial measure), including a reconciliation to the most directly comparable GAAP financial measure for the years ended December 31, 2017, 2016 and 2015 is as follows:
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions) |
| Net sales | $ | 5,664.2 |
| | $ | 4,431.3 |
| | $ | 5,161.9 |
|
| Cost of materials and other | 4,804.7 |
| | 3,759.2 |
| | 4,143.6 |
|
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 363.4 |
| | 361.9 |
| | 376.3 |
|
| Major scheduled turnaround expenses | 80.4 |
| | 31.5 |
| | 102.2 |
|
| Flood insurance recovery | — |
| | — |
| | (27.3 | ) |
| Depreciation and amortization | 129.3 |
| | 126.3 |
| | 128.0 |
|
| Gross profit | 286.4 |
| | 152.4 |
| | 439.1 |
|
| Add: | | | | | |
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 363.4 |
| | 361.9 |
| | 376.3 |
|
| Major scheduled turnaround expenses | 80.4 |
| | 31.5 |
| | 102.2 |
|
| Flood insurance recovery | — |
| | — |
| | (27.3 | ) |
| Depreciation and amortization | 129.3 |
| | 126.3 |
| | 128.0 |
|
| Refining margin | 859.5 |
| | 672.1 |
| | 1,018.3 |
|
| FIFO impact, (favorable) unfavorable | (29.6 | ) | | (52.1 | ) | | 60.3 |
|
Refining margin adjusted for FIFO impact
| $ | 829.9 |
| | $ | 620.0 |
| | $ | 1,078.6 |
|
|
| | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| Total crude oil throughput barrels per day | 204,748 |
| | 198,042 |
| | 193,077 |
|
| Days in the period | 365 |
| | 366 |
| | 365 |
|
| Total crude oil throughput barrels | 74,733,020 |
| | 72,483,372 |
| | 70,473,105 |
|
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except for $ per barrel data) |
| Refining margin | $ | 859.5 |
| | $ | 672.1 |
| | $ | 1,018.3 |
|
| Divided by: crude oil throughput barrels | 74.7 |
| | 72.5 |
| | 70.5 |
|
| Refining margin per crude oil throughput barrel | $ | 11.50 |
| | $ | 9.27 |
| | $ | 14.45 |
|
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except for $ per barrel data) |
| Refining margin adjusted for FIFO impact | $ | 829.9 |
| | $ | 620.0 |
| | $ | 1,078.6 |
|
| Divided by: crude oil throughput barrels | 74.7 |
| | 72.5 |
| | 70.5 |
|
| Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 11.10 |
| | $ | 8.55 |
| | $ | 15.31 |
|
| |
| (5) | Petroleum EBITDA represents net income for the petroleum segment before (i) interest expense and other financing costs, net of interest income,income; (ii) income tax expenseexpense; and (iii) depreciation and amortization. Adjusted Petroleum EBITDA represents Petroleum EBITDA adjusted for (i) FIFO impact (favorable) unfavorable,unfavorable; (ii) share-based compensation, non-cash,non-cash; (iii) loss on extinguishment of debt,debt; (iv) major scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and Adjusted EBITDA); (v) (gain) loss on derivatives, net,net; (vi) current period settlements on derivative contractscontracts; and (vii) flood insurance recovery. We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership's available cash for distribution. Petroleum EBITDA and Adjusted Petroleum EBITDA are not recognized terms under GAAP and should |
available cash for distribution. Petroleum EBITDA and Adjusted Petroleum EBITDA are not recognized terms under GAAP and should not be substituted for net income as a measure of performance. Management believesor cash flow from operations. We believe that Petroleum EBITDA and Adjusted Petroleum EBITDA enable investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, help investors evaluate the petroleum segment's ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. Petroleum EBITDA and Adjusted Petroleum 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 petroleum segment to Petroleum EBITDA and Petroleum EBITDA to Adjusted Petroleum EBITDA for the years ended December 31, 2015, 20142017, 2016 and 2013:2015:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Petroleum: | | | | | | | | | | |
| Petroleum net income | $ | 291.2 |
| | $ | 358.7 |
| | $ | 590.4 |
| $ | 88.8 |
| | $ | 15.3 |
| | $ | 291.2 |
|
| Add: | | | | | | | | | | |
| Interest expense and other financing costs, net of interest income | 42.2 |
| | 33.9 |
| | 43.7 |
| 46.7 |
| | 43.3 |
| | 42.2 |
|
| Income tax expense | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Depreciation and amortization | 130.2 |
| | 122.5 |
| | 114.3 |
| 133.1 |
| | 129.0 |
| | 130.2 |
|
| Petroleum EBITDA | 463.6 |
| | 515.1 |
| | 748.4 |
| 268.6 |
| | 187.6 |
| | 463.6 |
|
| Add: | | | | | | | | | | |
| FIFO impact (favorable) unfavorable(a) | 60.3 |
| | 160.8 |
| | (21.3 | ) | |
| FIFO impact, (favorable) unfavorable(a) | | (29.6 | ) | | (52.1 | ) | | 60.3 |
|
| Share-based compensation, non-cash | 0.6 |
| | 2.3 |
| | 9.5 |
| — |
| | — |
| | 0.6 |
|
| Loss on extinguishment of debt | — |
| | — |
| | 26.1 |
| |
| Major scheduled turnaround expenses(b) | 102.2 |
| | 6.8 |
| | — |
| 80.4 |
| | 31.5 |
| | 102.2 |
|
| (Gain) loss on derivatives, net | 28.6 |
| | (185.6 | ) | | (57.1 | ) | |
| Loss on derivatives, net | | 69.8 |
| | 19.4 |
| | 28.6 |
|
| Current period settlements on derivative contracts(c) | (26.0 | ) | | 122.2 |
| | 6.4 |
| (16.6 | ) | | 36.4 |
| | (26.0 | ) |
| Flood insurance recovery(d) | (27.3 | ) | | — |
| | — |
| — |
| | — |
| | (27.3 | ) |
| Adjusted Petroleum EBITDA | $ | 602.0 |
| | $ | 621.6 |
| | $ | 712.0 |
| $ | 372.6 |
| | $ | 222.8 |
| | $ | 602.0 |
|
| |
| (a) | FIFO is the petroleum business' basis for determining inventory value on a GAAP basis.under GAAP. Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. |
| |
| (b) | Represents expense associated with major scheduled turnaround activities performed at the Coffeyville refinery ($102.2 million in 2015 and $5.5 million in 2014) and the Wynnewood refinery ($1.3 million in 2014).refineries. |
| |
| (c) | Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recovery associated 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 Coffeyville refinery onin June/July 2007. Refer to Part II, Item 8, Note 1315 ("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 of barrels sold for the period to derive the metric. |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions) |
| Coffeyville Refinery Financial Results | | | | | |
| Net sales | $ | 3,867.8 |
| | $ | 2,948.9 |
| | $ | 3,220.6 |
|
| Cost of materials and other | 3,285.8 |
| | 2,513.9 |
| | 2,626.1 |
|
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 209.5 |
| | 196.4 |
| | 209.1 |
|
| Major scheduled turnaround expenses | — |
| | 31.5 |
| | 102.2 |
|
| Depreciation and amortization | 71.5 |
| | 69.7 |
| | 72.1 |
|
| Flood insurance recovery | — |
| | — |
| | (27.3 | ) |
| Gross profit | 301.0 |
| | 137.4 |
| | 238.4 |
|
| Plus: | | | | | |
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below) | 209.5 |
| | 227.9 |
| | 311.3 |
|
| Flood insurance recovery | — |
| | — |
| | (27.3 | ) |
| Depreciation and amortization | 71.5 |
| | 69.7 |
| | 72.1 |
|
| Refining margin | 582.0 |
| | 435.0 |
| | 594.5 |
|
| FIFO impact, (favorable) unfavorable | (20.2 | ) | | (37.8 | ) | | 38.0 |
|
| Refining margin adjusted for FIFO impact | $ | 561.8 |
| | $ | 397.2 |
| | $ | 632.5 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (dollars per barrel) |
| Coffeyville Refinery Key Operating Statistics | | | | | |
| Per crude oil throughput barrel: | | | | | |
| Gross profit | $ | 6.27 |
| | $ | 3.03 |
| | $ | 5.77 |
|
| Refining margin(1) | $ | 12.12 |
| | $ | 9.57 |
| | $ | 14.37 |
|
| FIFO impact, (favorable) unfavorable | $ | (0.42 | ) | | $ | (0.83 | ) | | $ | 0.92 |
|
| Refining margin adjusted for FIFO impact(1) | $ | 11.70 |
| | $ | 8.74 |
| | $ | 15.29 |
|
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 4.36 |
| | $ | 5.02 |
| | $ | 7.53 |
|
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 4.00 |
| | $ | 4.54 |
| | $ | 6.92 |
|
| Barrels sold (barrels per day) | 143,598 |
| | 137,047 |
| | 123,279 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (in millions) |
| Coffeyville Refinery Financial Results | | | | | |
| Net sales | $ | 3,220.6 |
| | $ | 5,755.5 |
| | $ | 5,370.8 |
|
| Cost of product sold (exclusive of depreciation and amortization) | 2,626.1 |
| | 5,254.9 |
| | 4,648.6 |
|
| Direct operating expenses (exclusive of depreciation and amortization) | 209.1 |
| | 223.6 |
| | 219.4 |
|
| Major scheduled turnaround expenses | 102.2 |
| | 5.5 |
| | — |
|
| Flood insurance recovery | (27.3 | ) | | — |
| | — |
|
| Depreciation and amortization | 72.1 |
| | 73.6 |
| | 70.8 |
|
| Gross profit | $ | 238.4 |
| | $ | 197.9 |
| | $ | 432.0 |
|
| Plus: | | | | | |
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | 311.3 |
| | 229.1 |
| | 219.4 |
|
| Flood insurance recovery | (27.3 | ) | | — |
| | — |
|
| Depreciation and amortization | 72.1 |
| | 73.6 |
| | 70.8 |
|
| Refining 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 |
| | $ | 17.90 |
|
| Gross profit | $ | 5.77 |
| | $ | 4.53 |
| | $ | 10.71 |
|
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 7.53 |
| | $ | 5.24 |
| | $ | 5.44 |
|
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 6.92 |
| | $ | 4.73 |
| | $ | 5.00 |
|
| Barrels sold (barrels per day) | 123,279 |
| | 132,791 |
| | 120,166 |
|
|
| | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | % | | | | % | | | | % |
| Coffeyville Refinery Throughput and Production Data (bpd) | | | | | | | | | | | |
| Throughput: | | | | | | | | | | | |
| Sweet | 121,434 |
| | 86.4 | | 104,679 |
| | 78.9 | | 96,727 |
| | 79.5 |
| Medium | — |
| | — | | 1,229 |
| | 0.9 | | 2,058 |
| | 1.7 |
| Heavy sour | 10,135 |
| | 7.2 | | 18,261 |
| | 13.8 | | 14,520 |
| | 11.9 |
| Total crude oil throughput | 131,569 |
| | 93.6 | | 124,169 |
| | 93.6 | | 113,305 |
| | 93.1 |
| All other feedstocks and blendstocks | 9,058 |
| | 6.4 | | 8,453 |
| | 6.4 | | 8,400 |
| | 6.9 |
| Total throughput | 140,627 |
| | 100.0 | | 132,622 |
| | 100.0 | | 121,705 |
| | 100.0 |
| Production: | | | | | | | | | | | |
| Gasoline | 71,915 |
| | 50.4 | | 69,303 |
| | 51.4 | | 57,815 |
| | 46.5 |
| Distillate | 59,593 |
| | 41.7 | | 55,790 |
| | 41.4 | | 53,136 |
| | 42.7 |
| Other (excluding internally produced fuel) | 11,335 |
| | 7.9 | | 9,756 |
| | 7.2 | | 13,503 |
| | 10.8 |
| Total refining production (excluding internally produced fuel) | 142,843 |
| | 100.0 | | 134,849 |
| | 100.0 | | 124,454 |
| | 100.0 |
| |
| (1) | The calculation of refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel for the years ended December 31, 2017, 2016 and 2015 is as follows: |
|
| | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| Total crude oil throughput barrels per day | 131,569 |
| | 124,169 |
| | 113,305 |
|
| Days in the period | 365 |
| | 366 |
| | 365 |
|
| Total crude oil throughput barrels | 48,022,685 |
| | 45,445,854 |
| | 41,356,325 |
|
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except for $ per barrel data) |
| Refining margin | $ | 582.0 |
| | $ | 435.0 |
| | $ | 594.5 |
|
| Divided by: crude oil throughput barrels | 48.0 |
| | 45.4 |
| | 41.4 |
|
| Refining margin per crude oil throughput barrel | $ | 12.12 |
| | $ | 9.57 |
| | $ | 14.37 |
|
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except for $ per barrel data) |
| Refining margin adjusted for FIFO impact | $ | 561.8 |
| | $ | 397.2 |
| | $ | 632.5 |
|
| Divided by: crude oil throughput barrels | 48.0 |
| | 45.4 |
| | 41.4 |
|
| Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 11.70 |
| | $ | 8.74 |
| | $ | 15.29 |
|
|
| | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | | | % | | | | % | | | | % |
| Coffeyville Refinery Throughput and Production Data (bpd) | | | | | | | | | | | |
| Throughput: | | | | | | | | | | | |
| Sweet | 96,727 |
| | 79.5 | | 103,018 |
| | 80.0 | | 90,818 |
| | 77.1 |
| Medium | 2,058 |
| | 1.7 | | 1,222 |
| | 1.0 | | 453 |
| | 0.4 |
| Heavy sour | 14,520 |
| | 11.9 | | 15,464 |
| | 12.0 | | 19,270 |
| | 16.3 |
| Total crude oil throughput | 113,305 |
| | 93.1 | | 119,704 |
| | 93.0 | | 110,541 |
| | 93.8 |
| All other feedstocks and blendstocks | 8,400 |
| | 6.9 | | 9,047 |
| | 7.0 | | 7,253 |
| | 6.2 |
| Total throughput | 121,705 |
| | 100.0 | | 128,751 |
| | 100.0 | | 117,794 |
| | 100.0 |
| Production: | | | | | | | | | | | |
| Gasoline | 57,815 |
| | 46.5 | | 64,002 |
| | 48.6 | | 56,262 |
| | 46.8 |
| Distillate | 53,136 |
| | 42.7 | | 56,381 |
| | 42.8 | | 50,353 |
| | 41.9 |
| Other (excluding internally produced fuel) | 13,503 |
| | 10.8 | | 11,314 |
| | 8.6 | | 13,499 |
| | 11.3 |
| Total refining production (excluding internally produced fuel) | 124,454 |
| | 100.0 | | 131,697 |
| | 100.0 | | 120,114 |
| | 100.0 |
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Wynnewood Refinery Financial Results | | | | | | | | | | |
| Net sales | $ | 1,936.9 |
| | $ | 3,069.8 |
| | $ | 3,308.4 |
| $ | 1,792.1 |
| | $ | 1,478.0 |
| | $ | 1,936.9 |
|
| Cost of product sold (exclusive of depreciation and amortization) | 1,516.3 |
| | 2,758.1 |
| | 2,877.5 |
| |
| Direct operating expenses (exclusive of depreciation and amortization) | 166.2 |
| | 185.5 |
| | 142.4 |
| |
| Cost of materials and other | | 1,519.7 |
| | 1,245.4 |
| | 1,516.3 |
|
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | | 153.9 |
| | 165.5 |
| | 166.2 |
|
| Major scheduled turnaround expenses | — |
| | 1.3 |
| | — |
| 80.4 |
| | — |
| | — |
|
| Depreciation and amortization | 50.2 |
| | 41.8 |
| | 38.6 |
| 51.7 |
| | 50.7 |
| | 50.2 |
|
| Gross profit | $ | 204.2 |
| | $ | 83.1 |
| | $ | 249.9 |
| |
| Gross profit (loss) | | (13.6 | ) | | 16.4 |
| | 204.2 |
|
| Plus: | | | | | | | | | | |
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | 166.2 |
| | 186.8 |
| | 142.4 |
| |
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below) | | 234.3 |
| | 165.5 |
| | 166.2 |
|
| Depreciation and amortization | 50.2 |
| | 41.8 |
| | 38.6 |
| 51.7 |
| | 50.7 |
| | 50.2 |
|
| Refining margin | $ | 420.6 |
| | $ | 311.7 |
| | $ | 430.9 |
| 272.4 |
| | 232.6 |
| | 420.6 |
|
| FIFO impact, (favorable) unfavorable | | (9.4 | ) | | (14.2 | ) | | 22.3 |
|
| Refining margin adjusted for FIFO impact | | $ | 263.0 |
| | $ | 218.4 |
| | $ | 442.9 |
|
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (dollars per barrel) | (dollars per barrel) |
| Wynnewood Refinery Key Operating Statistics | | | | | | | | | | |
| Per crude oil throughput barrel: | | | | | | | | | | |
| Refining margin | $ | 14.44 |
| | $ | 11.11 |
| | $ | 15.33 |
| |
| Gross profit | $ | 7.01 |
| | $ | 2.96 |
| | $ | 8.89 |
| |
| Gross profit (loss) | | $ | (0.51 | ) | | $ | 0.61 |
| | $ | 7.01 |
|
| Refining margin(1) | | $ | 10.20 |
| | $ | 8.60 |
| | $ | 14.44 |
|
| FIFO impact, (favorable) unfavorable | | $ | (0.35 | ) | | $ | (0.53 | ) | | $ | 0.77 |
|
| Refining margin adjusted for FIFO impact(1) | | $ | 9.85 |
| | $ | 8.07 |
| | $ | 15.21 |
|
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 5.71 |
| | $ | 6.66 |
| | $ | 5.06 |
| $ | 8.77 |
| | $ | 6.12 |
| | $ | 5.71 |
|
| Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 5.59 |
| | $ | 6.66 |
| | $ | 5.00 |
| $ | 8.52 |
| | $ | 6.06 |
| | $ | 5.59 |
|
| Barrels sold (barrels per day) | 81,429 |
| | 76,878 |
| | 77,976 |
| 75,314 |
| | 74,596 |
| | 81,429 |
|
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | | | % | | | | % | | | | % | | | % | | | | % | | | | % |
| Wynnewood Refinery Throughput and Production Data (bpd) | | | | | | | | | | | | |
| Throughput: | | | | | | | | | | | | |
| Sweet | 79,370 |
| | 95.6 | | 76,041 |
| | 96.2 | | 58,329 |
| | 73.0 | 73,179 |
| | 96.1 | | 72,577 |
| | 94.9 | | 79,370 |
| | 95.6 |
| Medium | 402 |
| | 0.5 | | 800 |
| | 1.0 | | 18,698 |
| | 23.4 | — |
| | — | | 1,296 |
| | 1.7 | | 402 |
| | 0.5 |
| Heavy sour | — |
| | — | | — |
| | — | | — |
| | — | — |
| | — | | — |
| | — | | — |
| | — |
| Total crude oil throughput | 79,772 |
| | 96.1 | | 76,841 |
| | 97.2 | | 77,027 |
| | 96.4 | 73,179 |
| | 96.1 | | 73,873 |
| | 96.6 | | 79,772 |
| | 96.1 |
| All other feedstocks and blendstocks | 3,272 |
| | 3.9 | | 2,237 |
| | 2.8 | | 2,868 |
| | 3.6 | 2,974 |
| | 3.9 | | 2,624 |
| | 3.4 | | 3,272 |
| | 3.9 |
| Total throughput | 83,044 |
| | 100.0 | | 79,078 |
| | 100.0 | | 79,895 |
| | 100.0 | 76,153 |
| | 100.0 | | 76,497 |
| | 100.0 | | 83,044 |
| | 100.0 |
| Production: | | | | | | | | | | | | | | | | | | | | | | |
| Gasoline | 42,146 |
| | 51.7 | | 38,273 |
| | 49.5 | | 38,299 |
| | 49.0 | 38,311 |
| | 51.3 | | 39,459 |
| | 52.8 | | 42,146 |
| | 51.7 |
| Distillate | 32,817 |
| | 40.2 | | 31,258 |
| | 40.4 | | 31,736 |
| | 40.6 | 30,816 |
| | 41.3 | | 29,302 |
| | 39.2 | | 32,817 |
| | 40.2 |
| Other (excluding internally produced fuel) | 6,571 |
| | 8.1 | | 7,835 |
| | 10.1 | | 8,118 |
| | 10.4 | 5,483 |
| | 7.4 | | 5,995 |
| | 8.0 | | 6,571 |
| | 8.1 |
| Total refining production (excluding internally produced fuel) | 81,534 |
| | 100.0 | | 77,366 |
| | 100.0 | | 78,153 |
| | 100.0 | 74,610 |
| | 100.0 | | 74,756 |
| | 100.0 | | 81,534 |
| | 100.0 |
| |
| (1) | The calculation of refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel for the years ended December 31, 2017, 2016 and 2015 is as follows: |
|
| | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| Total crude oil throughput barrels per day | 73,179 |
| | 73,873 |
| | 79,772 |
|
| Days in the period | 365 |
| | 366 |
| | 365 |
|
| Total crude oil throughput barrels | 26,710,335 |
| | 27,037,518 |
| | 29,116,780 |
|
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except for $ per barrel data) |
| Refining margin | $ | 272.4 |
| | $ | 232.6 |
| | $ | 420.6 |
|
| Divided by: crude oil throughput barrels | 26.7 |
| | 27.0 |
| | 29.1 |
|
| Refining margin per crude oil throughput barrel | $ | 10.20 |
| | $ | 8.60 |
| | $ | 14.44 |
|
|
| | | | | | | | | | | |
| | Year Ended
December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except for $ per barrel data) |
| Refining margin adjusted for FIFO impact | $ | 263.0 |
| | $ | 218.4 |
| | $ | 442.9 |
|
| Divided by: crude oil throughput barrels | 26.7 |
| | 27.0 |
| | 29.1 |
|
| Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 9.85 |
| | $ | 8.07 |
| | $ | 15.21 |
|
Year Ended December 31, 20152017 Compared to the Year Ended December 31, 20142016 (Petroleum Business)
Net Sales. Petroleum net sales were $5,161.9$5,664.2 million for the year ended December 31, 2015,2017, compared to $8,829.7$4,431.3 million for the year ended December 31, 2014.2016. The decreaseincrease of $3,667.8$1,232.9 million was largely the result of significantly lowerhigher sales prices for transportation fuels and by-products. The average sales price per gallon for the year ended December 31, 20152017 for gasoline of $1.61$1.59 and distillate of $1.62 decreased$1.66 increased by approximately 36.4%18.7% and 42.3%22.1%, respectively, as compared to the year ended December 31, 2014.2016. Overall sales volume decreasedincreased approximately 3.3%4.7% for the year ended December 31, 20152017 compared to the year ended December 31, 2014.2016. Sales volumes for 2015 were impacted by decreased productionincreased in 2017 as a result of 2016 volumes being significantly impacted by the second phase of major scheduled turnaround completed at our Coffeyville refinery. Also contributing to the Coffeyville refineryincrease in sales was an increase in products purchased for resale for the fourth quarter of 2015 and lower purchased product volumes for resale. Sales volumes for 2014 were impacted by reduced crude oil throughput and productionyear ended December 31, 2017 as a result ofcompared to the Coffeyville refinery shutdown following the isomerization unit fire during the third quarter of 2014 and the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014.year ended December 31, 2016.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the year ended December 31, 20152017 compared to the year ended December 31, 2014:2016:
| | | | Year Ended December 31, 2015 | | Year Ended December 31, 2014 | | Total Variance | | | | | Year Ended December 31, 2017 | | Year Ended December 31, 2016 | | Total Variance | | | | |
| | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | Sales $(2) | | Price Variance | | Volume Variance | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | Sales $(2) | | Price Variance | | Volume Variance |
| | | | | | | | | | | | | | | | | | (in millions) | | | | | | | | | | | | | | | | | (in millions) |
| Gasoline | 40.1 |
| | $ | 67.52 |
| | $ | 2,708.4 |
| | 40.3 |
| | $ | 106.21 |
| | $ | 4,282.2 |
| | (0.2 | ) | | $ | (1,573.8 | ) | | $ | (1,552.1 | ) | | $ | (21.7 | ) | 44.3 |
| | $ | 66.90 |
| | $ | 2,966.8 |
| | 42.6 |
| | $ | 56.16 |
| | $ | 2,390.8 |
| | 1.7 |
| | $ | 576.0 |
| | $ | 476.3 |
| | $ | 99.7 |
|
| Distillate | 33.1 |
| | $ | 68.01 |
| | $ | 2,248.2 |
| | 34.9 |
| | $ | 118.09 |
| | $ | 4,122.3 |
| | (1.8 | ) | | $ | (1,874.1 | ) | | $ | (1,656.4 | ) | | $ | (217.7 | ) | 34.4 |
| | $ | 69.71 |
| | $ | 2,399.8 |
| | 32.4 |
| | $ | 56.99 |
| | $ | 1,844.3 |
| | 2.0 |
| | $ | 555.5 |
| | $ | 438.0 |
| | $ | 117.5 |
|
| |
| (2) | Sales dollars in millions |
Cost of Product Sold (Exclusive of DepreciationMaterials and Amortization).Other. Cost of product sold (exclusive of depreciationmaterials and amortization)other includes cost of crude oil, other feedstocks, and blendstocks, purchased refined products, for resale, RINs and transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciationmaterials and amortization)other was $4,143.6$4,804.7 million for the year ended December 31, 2015,2017, compared to $8,013.4$3,759.2 million for the year ended December 31, 2014.2016. The decreaseincrease of $3,869.8$1,045.5 million was primarily the result of a decreasean increase in the cost of consumed crude and purchased products for resale. The decreaseincrease in consumed crude oil cost was due to a decreasean increase in crude oil throughput volume and crude oil prices. The WTI benchmark crude oil price decreased 47.5%increased approximately 17.0% from the year ended December 31, 20152017 as compared to the year ended December 31, 2014.2016. The petroleum business' average cost per barrel of crude oil consumed for the year ended December 31,
2015 2017 was $47.86$50.63 compared to $92.57$41.99 for the year ended December 31, 2014,2016, a decreaseincrease of approximately 48.3%20.6%. Crude oil throughput volume decreasedincreased by approximately 1.8%3.1% for the year ended December 31, 20152017 as compared to the equivalent period in 20142016 due primarily to the major scheduled turnaround completed at the Coffeyville refinery in the fourthfirst quarter of 2015.2016. Sales volumes of refined fuels decreasedincreased by approximately 3.3%4.7% during the same period.
The impact of FIFO accounting also impacted cost of product soldmaterials and other during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the years ended December 31, 20152017 and 2014,2016, the petroleum business had an unfavorablefavorable FIFO inventory impact of $60.3$29.6 million compared to an unfavorablea favorable FIFO inventory impact of $160.8$52.1 million, respectively. The major factor contributing 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 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$11.50 for the year ended December 31, 20152017 from $11.38$9.27 for the year ended December 31, 2014.2016. Refining margin adjusted for FIFO impact was $15.31$11.10 per crude oil throughput barrel for the year ended December 31, 2015,2017, as compared to $13.62$8.55 per crude oil throughput barrel for the year ended December 31, 2014.2016. Gross profit per barrel increased to $6.20$3.83 for the year ended December 31, 2015,2017, as compared to gross profit per barrel of $3.87$2.10 in the equivalent period in 2014.2016. The increase in refining margin and gross profit per barrel was primarily due to the higher unfavorable FIFO impactimprovement in 2014 as result ofproduct margins. The benchmark 2-1-1 crack spread improved to $18.19 per barrel for the significant declineyear ended December 31, 2017 from $14.66 per barrel for the year ended December 31, 2016. Also contributing to increase in refining margin and gross profit per barrel was the improvement in the market priceGroup 3 gasoline basis to NYMEX gasoline to ($1.83) per barrel for the year ended December 31, 2017 as compared to ($3.62) per barrel in the comparable period in 2016.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the petroleum business include costs associated with the operations of the refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, 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$443.8 million for the year ended December 31, 2015,2017, compared to direct operating expenses and major scheduled turnaround expenses of $416.0$393.4 million for the year ended December 31, 2014.2016. The increase of $62.5$50.4 million was primarily the result of higher costs for the first phase of major scheduled turnaround activities performed at the Wynnewood refinery in 2017 as compared to the second phase of the major scheduled turnaround activities completed at the Coffeyville refinery in 2016 ($95.448.9 million), and higher utilities costs ($8.4 million). These increases were partially offset by decreasesa decrease in repair and maintenance costs ($22.1 million) and energy and utility costs ($18.97.1 million). The decrease in repairs and maintenanceUtilities costs was due to opportunity maintenance performed at the Coffeyville refinery during the shutdown following the isomerization fire in the third quarter of 2014 and during the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014. The decrease in energy and utility costs wasincreased primarily due to a 27.6% decrease28.1% increase in the petroleum business' natural gas cost per unitMMBtu and a 14.7% decrease15.3% increase in natural gas consumption.its electricity cost per Kilowatt Hour ("KWH"). Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 20152017 increased to $6.79$5.94 per barrel as compared to $5.80$5.43 per barrel for the year ended December 31, 2014.2016. The increase in the direct operating expenses per barrel of crude oil throughput was primarily a function of higher overall expenses.
Loss on Derivatives, net. For the year ended December 31, 2017, the petroleum business recorded a $69.8 million net loss on derivatives compared to a $19.4 million net loss on derivatives for the year ended December 31, 2016. This change was primarily due to an increase in open positions from 4.0 million barrels as of December 31, 2016 to 14.3 million barrels as of December 31, 2017 and changes in the benchmark 2-1-1 crack spread, which resulted in a $38.3 million net loss. The petroleum business enters into commodity hedging instruments in order to fix the price on a portion of its future crude oil purchases and to fix the margin on a portion of future production. In addition, the petroleum business had open forward purchase and sale commitments of 5.8 million barrels of Canadian crude oil priced at fixed differentials, which resulted in a $26.0 million unrealized net loss as of December 31, 2017.
Operating Income. Petroleum operating income was $361.7$203.8 million for the year ended December 31, 2015,2017, as compared to operating income of $207.2$77.8 million for the year ended December 31, 2014.2016. The increase of $154.5$126.0 million was the result of an increase in the refining margin ($202.0187.4 million) due to higher sales prices for our transportation fuels and the flood insurance recovery ($27.3 million),by-products which was, partially offset by increases in direct operating expenses ($62.550.4 million), depreciation and amortization ($7.74.1 million) and selling, general and administrative expenses ($4.66.9 million).
Year Ended December 31, 20142016 Compared to the Year Ended December 31, 2013 (Petroleum Business)2015
Net Sales. Petroleum net sales were $8,829.7$4,431.3 million for the year ended December 31, 2014,2016, compared to $8,683.5$5,161.9 million for the year ended December 31, 2013.2015. The increasedecrease of $146.2$730.6 million was primarilylargely the result of higher overall sales volumes largely offset by lower sales prices for gasolinetransportation fuels and distillates. Overall sales volume increased 8.4% for the year ended December 31, 2014 compared to the year ended December 31, 2013. Sales volumes for 2014 were impacted by reduced crude oil throughput and production as a result of the Coffeyville refinery shutdown following the isomerization unit fire during the third quarter of 2014 and the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014. Sales volumes for 2013 were impacted by downtime associated with the FCCU outage at the Coffeyville refinery in the third quarter of 2013.by-products. The average sales price per gallon for the year ended December 31, 20142016 for gasoline of $2.53$1.34 and distillate of $2.81 each$1.36 decreased by approximately 7.0%16.8% and 16.0%, respectively, as compared to the year ended December 31, 2013.2015. Overall sales volume decreased approximately 2.3% for the year ended December 31, 2016 compared to the year ended December 31, 2015. Sales volumes for 2015 were more significantly impacted by decreased production as a result of the first phase of major scheduled turnaround completed at the Coffeyville refinery in the fourth quarter of 2015 than the second phase of major scheduled turnaround completed at the Coffeyville refinery in the first quarter of 2016.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the year ended December 31, 20142016 compared to the year ended December 31, 2013:2015:
| | | | Year Ended December 31, 2014 | | Year Ended December 31, 2013 | | Total Variance | | | | | Year Ended December 31, 2016 | | Year Ended December 31, 2015 | | Total Variance | | | | |
| | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | Sales $(2) | | Price Variance | | Volume Variance | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | $ per barrel | | Sales $(2) | | Volume(1) | | Sales $(2) | | Price
Variance | | Volume
Variance |
| | | | | | | | | | | | | | | | | | (in millions) | | | | | | | | | | | | | | | | | (in millions) |
| Gasoline | 40.3 |
| | $ | 106.21 |
| | $ | 4,282.2 |
| | 37.8 |
| | $ | 114.29 |
| | $ | 4,330.0 |
| | 2.5 |
| | $ | (47.8 | ) | | $ | (325.9 | ) | | $ | 278.1 |
| 42.6 |
| | $ | 56.16 |
| | $ | 2,390.8 |
| | 40.1 |
| | $ | 67.52 |
| | $ | 2,708.4 |
| | 2.5 |
| | $ | (317.6 | ) | | $ | (483.2 | ) | | $ | 165.6 |
|
| Distillate | 34.9 |
| | $ | 118.09 |
| | $ | 4,122.3 |
| | 30.6 |
| | $ | 126.79 |
| | $ | 3,880.6 |
| | 4.3 |
| | $ | 241.7 |
| | $ | (303.5 | ) | | $ | 545.2 |
| 32.4 |
| | $ | 56.99 |
| | $ | 1,844.3 |
| | 33.1 |
| | $ | 68.01 |
| | $ | 2,248.2 |
| | (0.7 | ) | | $ | (403.9 | ) | | $ | (356.8 | ) | | $ | (47.1 | ) |
| |
| (2) | Sales dollars in millions |
Cost of Product Sold (Exclusive of DepreciationMaterials and Amortization).Other. Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciationmaterials and amortization)other was $8,013.4$3,759.2 million for the year ended December 31, 2014,2016, compared to $7,526.7$4,143.6 million for the year ended December 31, 2013.2015. The increasedecrease of $486.7$384.4 million was primarily the result of an increasea decrease in the cost of consumed crude oil and refined fuels purchased products for resale. The increasedecrease in consumed crude oil cost was due to a 4.8% increasedecrease in consumed volumes, which was partially offset by lower crude oil prices. The WTI benchmark crude oil price decreased approximately 10.8% from the year ended December 31, 2016 as compared to the year ended December 31, 2015. The petroleum business' average cost per barrel of crude oil consumed for the year ended December 31, 20142016 was $92.57$41.99 compared to $95.05$47.86 for the year ended December 31, 2013,2015, a decrease of approximately 2.6%12.3%. Crude oil throughput volume increased by approximately 2.9% for the year ended December 31, 2016 as compared to the equivalent period in 2015 due primarily to the major scheduled turnaround completed at the Coffeyville refinery in the fourth quarter of 2015. Sales volumes of refined fuels increased by approximately 8.4%. 2.3% during the same period.
The impact of FIFO accounting also impacted cost of product soldmaterials and other during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the years ended December 31, 20142016 and 2013,2015, the petroleum business had an favorable FIFO inventory impact of $52.1 million compared to an unfavorable FIFO inventory impact of $160.8$60.3 million, compared to a favorable FIFO inventory impact of $21.3 million, respectively. The major factor contributing 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 beginning of 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 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 decreased to $11.38$9.27 for the year ended December 31, 20142016 from $16.90$14.45 for the year ended December 31, 2013.2015. Refining margin adjusted for FIFO impact was $13.62$8.55 per crude oil throughput barrel for the year ended December 31, 2014,2016, as compared to $16.59$15.31 per crude oil throughput barrel for the year ended December 31, 2013.2015. Gross profit per barrel decreased to $3.87$2.10 for the year ended December 31, 2014,2016, as compared to gross profit per barrel of $9.94$6.23 in the equivalent period in 2013.2015. The decrease in refining margin and gross profit per barrel was primarily due to a decreasethe decline in sales prices of gasoline and distillate.product margins. The average sales price for both gasoline and distillatesbenchmark 2-1-1 crack spread declined approximately 7.0%to $14.66 per barrel for the year ended December 31, 2014 as compared to2016 from $20.41 per barrel for the same period last year.year ended December 31, 2015.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the petroleum business include costs associated with the operations of the refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, 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$393.4 million for the year ended December 31, 2014,2016, compared to direct operating expenses and major scheduled turnaround expenses of $361.7$478.5 million for the year ended December 31, 2013.2015. The increasedecrease of $54.3$85.1 million was primarily the result of lower costs for the increase in expenses associated with energy and utility costs ($18.1 million), repairs and maintenance ($10.2 million), labor ($8.9 million), certain turnaround activities performed at the Coffeyville and Wynnewood refineries ($6.8 million), production chemicals ($4.7 million) and rental costs ($4.5 million). The increase in energy and utility costs was primarily 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 and turnaround costs was due to opportunity maintenance andsecond phase of major scheduled turnaround activities performed at the Coffeyville refinery duringin 2016 as compared to the shutdown following the isomerization firefirst phase completed in the third quarter of 20142015 ($70.7 million), lower insurance expense ($4.5 million), environmental expense ($4.3 million), production chemicals ($3.1 million), repair and during the FCCU outage at the Wynnewood refinery during the fourth quarter of 2014.maintenance costs ($2.4 million), outside services ($2.3 million) and allocated shared services expenses ($2.2 million). These decreases were partially offset by an increase in labor costs ($4.0 million). Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2014 increased2016 decreased to $5.80$5.43 per barrel as compared to $5.28$6.79 per barrel for the year ended December 31, 2013.2015. The increasedecrease in the direct operating expenses per barrel of crude oil throughput was primarily a function of higherlower overall expenses.
Operating Income. Petroleum operating income was $207.2$77.8 million for the year ended December 31, 2014,2016, as compared to operating income of $603.0$361.7 million for the year ended December 31, 2013.2015. The decrease of $395.8$283.9 million was the result of
a decrease in the refining margin ($340.5346.2 million) and increasesthe 2015 flood insurance recovery ($27.3 million), partially offset by decreases in direct operating expenses ($54.385.1 million) and, depreciation and amortization ($8.21.2 million), partially offset by a decrease in and selling, general and administrative expenses ($7.23.3 million).
Nitrogen Fertilizer Business Results of Operations
The tables below provide an overview of the nitrogen fertilizer business' results of operations, relevant market indicators and its key operating statistics for the years ended December 31, 2015, 20142017, 2016 and 2013:2015:
| | | | Year Ended December 31, | Year Ended December 31, |
| 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Nitrogen Fertilizer Business Financial Results | | | | | | | | | | |
| Net sales | $ | 289.2 |
| | $ | 298.7 |
| | $ | 323.7 |
| $ | 330.8 |
| | $ | 356.3 |
| | $ | 289.2 |
|
| Cost of product sold(1) | 65.2 |
| | 72.0 |
| | 58.1 |
| |
| Operating costs and expenses: | | | | | | |
| Cost of materials and other | | 84.9 |
| | 93.7 |
| | 65.2 |
|
| Direct operating expenses(1) | 99.1 |
| | 98.9 |
| | 94.1 |
| 152.9 |
| | 141.7 |
| | 99.1 |
|
| Major scheduled turnaround expenses | 7.0 |
| | — |
| | — |
| 2.6 |
| | 6.6 |
| | 7.0 |
|
| Selling, general and administrative(1) | 20.8 |
| | 17.7 |
| | 21.0 |
| |
| Depreciation and amortization | 28.4 |
| | 27.3 |
| | 25.6 |
| 74.0 |
| | 58.2 |
| | 28.4 |
|
| Operating income | 68.7 |
| | 82.8 |
| | 124.9 |
| |
| Cost of sales | | 314.4 |
| | 300.2 |
| | 199.7 |
|
| Selling, general and administrative | | 25.6 |
| | 29.3 |
| | 20.8 |
|
| Operating income (loss) | | (9.2 | ) | | 26.8 |
| | 68.7 |
|
| Interest expense and other financing costs | (7.0 | ) | | (6.7 | ) | | (6.3 | ) | (62.9 | ) | | (48.6 | ) | | (7.0 | ) |
| Other income, net | 0.3 |
| | — |
| | 0.1 |
| |
| Income before income tax expense | 62.0 |
| | 76.1 |
| | 118.7 |
| |
| Loss on extinguishment of debt | | — |
| | (4.9 | ) | | — |
|
| Other income (loss), net | | (0.5 | ) | | 0.1 |
| | 0.3 |
|
| Income (loss) before income tax expense | | (72.6 | ) | | (26.6 | ) | | 62.0 |
|
| Income tax expense | — |
| | — |
| | 0.1 |
| 0.2 |
| | 0.3 |
| | — |
|
| Net income | $ | 62.0 |
| | $ | 76.1 |
| | $ | 118.6 |
| |
| Net income (loss) | | $ | (72.8 | ) | | $ | (26.9 | ) | | $ | 62.0 |
|
| | | | | | | | | | | |
| Adjusted Nitrogen Fertilizer EBITDA(2) | $ | 106.8 |
| | $ | 110.3 |
| | $ | 152.8 |
| $ | 65.8 |
| | $ | 92.7 |
| | $ | 106.8 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| 2015 | | 2014 | | 2013 |
| Key Operating Statistics | | | | | |
| Production volume (thousand tons): | | | | | |
| Ammonia (gross produced)(3) | 385.4 |
| | 388.9 |
| | 402.0 |
|
| Ammonia (net available for sale)(3)(4) | 37.3 |
| | 28.3 |
| | 37.9 |
|
| UAN | 928.6 |
| | 963.7 |
| | 930.6 |
|
| | | | | | |
| Pet coke consumed (thousand tons) | 469.9 |
| | 489.7 |
| | 487.0 |
|
| Pet coke (cost per ton) | $ | 25 |
| | $ | 28 |
| | $ | 30 |
|
| | | | | | |
| Sales (thousand tons): | | | | | |
| Ammonia | 32.3 |
| | 24.4 |
| | 40.5 |
|
| UAN | 939.5 |
| | 951.0 |
| | 904.6 |
|
| | | | | | |
| Product pricing at gate (dollars per ton)(5): | | | | | |
| Ammonia | $ | 521 |
| | $ | 518 |
| | $ | 643 |
|
| UAN | $ | 247 |
| | $ | 259 |
| | $ | 282 |
|
| | | | | | |
| On-stream factors(6): | | | | | |
| Gasification | 90.2 | % | | 96.8 | % | | 95.6 | % |
| Ammonia | 87.5 | % | | 92.6 | % | | 94.4 | % |
| UAN | 87.3 | % | | 92.0 | % | | 91.9 | % |
| | | | | | |
| Reconciliation to net sales (dollars in millions): | | | | | |
| Sales net at gate | $ | 248.8 |
| | $ | 259.3 |
| | $ | 281.5 |
|
| Freight in revenue | 27.2 |
| | 27.5 |
| | 30.2 |
|
| Hydrogen revenue | 11.8 |
| | 10.1 |
| | 11.4 |
|
| Other revenue | 1.4 |
| | 1.8 |
| | 0.6 |
|
| Total net sales | $ | 289.2 |
| | $ | 298.7 |
| | $ | 323.7 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| Market Indicators | | | | | |
| Natural gas NYMEX (dollars per MMBtu) | $ | 2.63 |
| | $ | 4.26 |
| | $ | 3.73 |
|
| Ammonia — Southern Plains (dollars per ton) | 510 |
| | 539 |
| | 581 |
|
| UAN — Corn belt (dollars per ton) | 284 |
| | 314 |
| | 337 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
| Key Operating Statistics | | | | | |
| Sales (thousand tons): | | | | | |
| Ammonia | 286.1 |
| | 201.4 |
| | 32.3 |
|
| UAN | 1,254.5 |
| | 1,237.5 |
| | 939.5 |
|
| Product pricing at gate (dollars per ton)(3): | | | | | |
| Ammonia | $ | 280 |
| | $ | 376 |
| | $ | 521 |
|
| UAN | $ | 152 |
| | $ | 177 |
| | $ | 247 |
|
| Production volume (thousand tons): | | | | | |
| Ammonia (gross produced)(4) | 814.7 |
| | 693.5 |
| | 385.4 |
|
| Ammonia (net available for sale)(4) | 267.8 |
| | 183.6 |
| | 37.3 |
|
| UAN | 1,268.4 |
| | 1,192.6 |
| | 928.6 |
|
| Feedstock: | | | | | |
| Petroleum coke used in production (thousand tons) | 487.5 |
| | 513.7 |
| | 469.9 |
|
| Petroleum coke (dollars per ton) | $ | 17 |
| | $ | 15 |
| | $ | 25 |
|
| Natural gas used in production (thousands of MMBtu)(5) | 7,619.5 |
| | 5,596.0 |
| | — |
|
| Natural gas used in production (dollars per MMBtu)(5)(6) | $ | 3.24 |
| | $ | 2.96 |
| | $ | — |
|
| Natural gas cost of materials and other (thousands of MMBtu)(5) | 8,051.5 |
| | 4,618.7 |
| | — |
|
| Natural gas cost of materials and other (dollars per MMBtu)(5)(6) | $ | 3.26 |
| | $ | 2.87 |
| | $ | — |
|
| Coffeyville Facility on-stream factors(7): | | | | | |
| Gasification | 98.5 | % | | 96.9 | % | | 90.2 | % |
| Ammonia | 97.4 | % | | 94.9 | % | | 87.5 | % |
| UAN | 91.7 | % | | 93.1 | % | | 87.3 | % |
| East Dubuque Facility on-stream factors (7): | | | | | |
| Ammonia | 90.4 | % | | 87.7 | % | | — | % |
| UAN | 90.3 | % | | 87.3 | % | | — | % |
| | | | | | |
| Reconciliation to net sales (dollars in millions): | | | | | |
| Sales net at gate | $ | 290.0 |
| | $ | 309.0 |
| | $ | 248.8 |
|
| Freight in revenue | 32.8 |
| | 33.0 |
| | 27.2 |
|
| Hydrogen revenue | 0.4 |
| | 3.2 |
| | 11.8 |
|
| Other revenue | 7.6 |
| | 11.1 |
| | 1.4 |
|
| Total net sales | $ | 330.8 |
| | $ | 356.3 |
| | $ | 289.2 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Market Indicators | | | | | |
| Ammonia — Southern Plains (dollars per ton) | $ | 314 |
| | $ | 356 |
| | $ | 510 |
|
| Ammonia — Corn belt (dollars per ton) | $ | 358 |
| | $ | 416 |
| | $ | 566 |
|
| UAN — Corn belt (dollars per ton) | $ | 192 |
| | $ | 208 |
| | $ | 284 |
|
| Natural gas NYMEX (dollars per MMBtu) | $ | 3.02 |
| | $ | 2.55 |
| | $ | 2.63 |
|
| |
| (1) | Amounts are shown exclusive of depreciation and amortization.amortization and major scheduled turnaround expenses. |
| |
| (2) | Nitrogen Fertilizer EBITDA represents nitrogen fertilizer net income (loss) adjusted for (i) interest expense and other financing costs, net of interest income,(income) expense; (ii) income tax expenseexpense; and (iii) depreciation and amortization.amortization expense. Adjusted Nitrogen Fertilizer EBITDA represents Nitrogen Fertilizer EBITDA further adjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, when applicable; (ii) share-based compensation, non-cash; (iii) gain or loss on extinguishment of debt anddebt; (iv) expenses associated with the pending Rentech Nitrogen mergers, asEast Dubuque Merger, when applicable; (v) business interruption insurance recovery, when applicable; and (vi) loss on disposition of assets, when applicable. We present Adjusted Nitrogen Fertilizer EBITDA because we have found it helpful to consider an operating measure that excludes expenses, such as major scheduled turnaround expense, gain or loss on extinguishment of debt, andloss on disposition of assets, expenses associated with the pending Rentech Nitrogen mergers,East Dubuque Merger and business interruption insurance recovery, relating to transactions not reflective of the Nitrogen Fertilizer Partnership's core operations. In addition, we believe that it is useful to exclude from Adjusted Nitrogen Fertilizer EBITDA share-based compensation, non-cash, although it is a |
recurring cost incurred in the ordinary course of business. We believe share-based compensation, non-cash, reflects a non-cash cost which may obscure, 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 available cash for distribution. Adjusted Nitrogen Fertilizer EBITDA is not a recognized term under GAAP and should not be substituted for net income as a measure of performance. Management believes that Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer EBITDA enable investors and analysts to better understand the Nitrogen Fertilizer Partnership's ability to make distributions to its common unitholders, help investors and analysts evaluate its ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance by allowing investors to evaluate the same information used by management. Nitrogen Fertilizer EBITDA and Adjusted Nitrogen Fertilizer 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 EBITDA for the years ended December 31, 2015, 20142017, 2016 and 2013:2015:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Nitrogen Fertilizer: | | | | | | | | | | |
| Nitrogen Fertilizer net income | $ | 62.0 |
| | $ | 76.1 |
| | $ | 118.6 |
| |
| Nitrogen Fertilizer net income (loss) | | $ | (72.8 | ) | | $ | (26.9 | ) | | $ | 62.0 |
|
| Add: | | | | | | | | | | |
| Interest expense and other financing costs, net | 7.0 |
| | 6.7 |
| | 6.3 |
| 62.9 |
| | 48.6 |
| | 7.0 |
|
| Income tax expense | — |
| | — |
| | 0.1 |
| 0.2 |
| | 0.3 |
| | — |
|
| Depreciation and amortization | 28.4 |
| | 27.3 |
| | 25.6 |
| 74.0 |
| | 58.2 |
| | 28.4 |
|
| Nitrogen Fertilizer EBITDA | 97.4 |
| | 110.1 |
| | 150.6 |
| 64.3 |
| | 80.2 |
| | 97.4 |
|
| Add: | | | | | | | | | | |
| Major scheduled turnaround expenses | | 2.6 |
| | 6.6 |
| | 7.0 |
|
| Share-based compensation, non-cash | 0.1 |
| | 0.2 |
| | 2.2 |
| — |
| | — |
| | 0.1 |
|
| Major scheduled turnaround expenses | 7.0 |
| | — |
| | — |
| |
| Expenses associated with the Rentech Nitrogen mergers | 2.3 |
| | — |
| | — |
| |
| Loss on extinguishment of debt | | — |
| | 4.9 |
| | — |
|
| Expenses associated with the East Dubuque Merger | | — |
| | 3.1 |
| | 2.3 |
|
| Less: | | | | | | |
| Insurance recovery - business interruption | | (1.1 | ) | | (2.1 | ) | | — |
|
| Adjusted Nitrogen Fertilizer EBITDA | $ | 106.8 |
| | $ | 110.3 |
| | $ | 152.8 |
| $ | 65.8 |
| | $ | 92.7 |
| | $ | 106.8 |
|
| |
| (3) | Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. Net tons available 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 during the 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 pricing measure that is comparable across the fertilizer industry. |
| |
| (4) | Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into other fertilizer products. Net tons available for sale represent the ammonia available for sale that was not upgraded into other fertilizer products. |
| |
| (5) | The feedstock natural gas shown above does not include natural gas used for fuel. The cost of fuel natural gas is included in direct operating expense (exclusive of depreciation and amortization). |
| |
| (6) | The cost per MMBtu excludes derivative activity, when applicable. The impact of natural gas derivative activity was not material for the periods presented. |
| |
| (7) | 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 operating efficiency. Excluding the impact of the full facility turnaround and the Linde air separation unit outages, (i) the on-stream factors in 2015 would have been 99.9% for gasification, 97.7% for ammonia and 97.6% for UAN. Excluding the impact of the downtime associated with the installation of the 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 downtime associated with the replacement of damaged catalyst, the unplanned Linde air separation unit outages and the unplanned downtime associated with weather issues (iii) the on-stream factors in 2013 would have been 99.5% for gasification, 98.9% for ammonia and 98.0% for UAN. |
Coffeyville Facility
81
TableThe Linde air separation unit experienced a shut down during the second quarter of Contents2017. Following the Linde outage, the Coffeyville Facility UAN unit experienced a number of operational challenges, resulting in approximately 11 days of UAN downtime during the second quarter of 2017. Excluding the impact of the Linde air separation unit outage at the Coffeyville Facility, the UAN unit on-stream factors at the Coffeyville Facility would have been 94.7% for the year ended December 31, 2017.Excluding the impact of the full facility turnaround and the Linde air separation unit outages at the Coffeyville Fertilizer Facility, the on-stream factors for the year ended December 31, 2015 would have been 99.9% for gasifier, 97.7% for ammonia and 97.6% for UAN.
East Dubuque Facility
Excluding the impact of the full facility turnaround at the East Dubuque Facility, the on-stream factors would have been 94.2% for ammonia and 94.0% for UAN for the year ended December 31, 2017.
Excluding the impact of the full facility turnaround at the East Dubuque Facility, the on-stream factors would have been 97.8% for ammonia and 97.1% for UAN for the post-acquisition period ended December 31, 2016.
Year Ended December 31, 20152017 compared to the Year Ended December 31, 20142016 (Nitrogen Fertilizer Business)
Net Sales. Nitrogen fertilizer net sales were $289.2$330.8 million for the year ended December 31, 2015,2017, compared to $298.7$356.3 million for the year ended December 31, 2014. The2016.
Excluding the East Dubuque Facility, net sales decrease of $9.5were $195.8 million for the year ended December 31, 2015 as2017 compared to $228.3 million for the year ended December 31, 20142016. The decrease of $32.5 million was primarily attributable to the result of lower UAN sales prices ($11.624.0 million), lower UAN sales volumes ($3.37.2 million) and lower hydrogenammonia sales prices ($0.34.5 million), partially offset by higher ammonia sales volumes ($4.26.5 million) and higher hydrogen sales volumes ($2.0 million).at the Coffeyville Facility. For the year ended December 31, 2015,2017, UAN ammonia and hydrogenammonia made up $258.8 million, $17.2$170.5 million and $11.8$18.4 million of the nitrogen fertilizer business' net sales, respectively.respectively, including freight. This compared to UAN ammonia and hydrogenammonia net sales of $273.7 million, $13.1$201.7 million and $10.1$16.4 million, respectively, for the year ended December 31, 2014. 2016, including freight.
The following table demonstrates the impact of changes in sales volumes and pricing for the primary components of net sales price for UAN, ammonia and hydrogenat the Coffeyville Fertilizer Facility for the year ended December 31, 20152017 compared to the year ended December 31, 2014:2016:
| | | | 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) | | Price Variance | | Volume Variance | Price Variance | | Volume Variance |
| |
| | | | | | | | | | | | | | | | (in millions) | (in millions) |
| UAN | 939,547 |
| | $ | 275 |
| | $ | 258.8 |
| | 951,043 |
| | $ | 288 |
| | $ | 273.7 |
| | (11,496 | ) | | $ | (14.9 | ) | | $ | (11.6 | ) | | $ | (3.3 | ) | $ | (24.0 | ) | | $ | (7.2 | ) |
| Ammonia | 32,326 |
| | $ | 533 |
| | $ | 17.2 |
| | 24,378 |
| | $ | 536 |
| | $ | 13.1 |
| | 7,948 |
| | $ | 4.1 |
| | $ | (0.1 | ) | | $ | 4.2 |
| $ | (4.5 | ) | | $ | 6.5 |
|
| Hydrogen | 1,196,320 |
| | $ | 10 |
| | $ | 11.8 |
| | 996,516 |
| | $ | 10 |
| | $ | 10.1 |
| | 199,804 |
| | $ | 1.7 |
| | $ | (0.3 | ) | | $ | 2.0 |
| $ | (0.2 | ) | | $ | (2.6 | ) |
| |
(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. |
ForThe decrease in UAN and ammonia sales prices at the Coffeyville Fertilizer Facility for the year ended December 31, 20152017 compared to the year ended December 31, 2014, the nitrogen fertilizer segment's operations experienced a decrease 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 ended December 31, 2015 compared to the year ended December 31, 20142016 was partiallyprimarily attributable to pricing fluctuation in the 2015 turnaround and the Linde air separation unit related outages. The increase in ammonia sales for the year ended December 31, 2015 compared to the year ended December 31, 2014 was partially attributable to higher 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 decreased approximately 4.6% for the year ended December 31, 2015 as compared to the year ended December 31, 2014. Product pricing at gate for ammonia increased approximately 0.6% for the year ended December 31, 2015 as compared to the year ended December 31, 2014.market.
Cost of Product Sold (Exclusive of DepreciationMaterials and Amortization).Other. Nitrogen fertilizer cost of product sold (exclusive of depreciationmaterials and amortization)other includes cost of freight and distribution expenses, pet coke expenses,feedstock, purchased ammonia and purchased hydrogen. Cost of product sold excluding depreciationmaterials and amortizationother for the year ended December 31, 20152017 was $65.2$84.9 million, compared to $72.0$93.7 million for the year ended December 31, 2014.2016.
Excluding the East Dubuque Facility, cost of materials and other was $55.0 million for the year ended December 31, 2017 compared to $57.0 million for the year ended December 31, 2016. The $6.8decrease of $2.0 million was attributable to lower costs from transactions with third parties of $6.9 million, partially offset by higher transactions with affiliates of $4.9 million. The decrease in transactions with third parties was primarily the result of lower consumption of pet coke mostlydecreased distribution costs due to the decrease in production during the turnaroundtiming of regulatory railcar repairs and the Linde air separation unit related downtime, lower pet coke pricing, decreased distribution costs, freightmaintenance ($3.5 million) and a reduction of expenses and purchased ammonia. The lower distribution costs is due to lower UAN sales at the Coffeyville Facility. The increase in transactions with affiliates was primarily the result of increased hydrogen purchases from a smaller portionsubsidiary of the nitrogen fertilizer business' fleet due for regulatory inspections and related repairs during the year ended December 31, 2015 as compared to the year ended December 31, 2014.Petroleum business ($4.0 million).
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer business consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services, including turnaround, and environmental and safety compliance costs as well as catalyst and chemical costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 20152017 were $106.1$155.5 million, as compared to $98.9$148.3 million for the year ended December 31, 2014.2016. The total increase of $7.2 million for the year ended December 31, 2015,2017, as compared to the year ended December 31, 2014, resulted primarily from higher 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 the increased efforts required to complete activities during downtime. The increase in repairs and maintenance is due to the nitrogen fertilizer business being able to perform an increased amount of normal repairs and maintenance during the downtime. The lower utilities, net are primarily the result of lower usage during the downtime from the turnaround and the Linde outages.2016.
Operating Income. Nitrogen fertilizerExcluding the East Dubuque Facility, direct operating income was $68.7expenses were $94.4 million for the year ended December 31, 2015, as2017 compared to operating income of $82.8$92.6 million for the year ended December 31, 2014.2016. The increase of $1.8 million was attributable to higher costs from transactions with third parties of $3.0 million, partially offset by a decrease in transactions with affiliates of $14.1$1.2 million. The increase in transactions with third parties was primarily the result of higher utilities ($4.3 million) mostly due to higher electricity prices and also the result of other less significant fluctuations, partially offset by lower repairs and maintenance ($3.2 million).
Operating Income (loss). Nitrogen fertilizer operating loss was $9.2 million for the year ended December 31, 20152017, as compared to operating income of $26.8 million for the year ended December 31, 20142016. The decrease of $36.0 million was the result of the decrease in net sales ($9.525.5 million) and, increases in direct operating expenses ($7.211.2 million), and depreciation and amortization ($15.8 million), partially offset by decreases in cost of materials and other ($8.8 million), turnaround expenses ($4.0 million), and selling, general and administrative expenses ($3.1 million) and depreciation and amortization ($1.1 million), partially offset by a decrease in cost of product sold ($6.83.7 million).
Year Ended December 31, 20142016 compared to the Year Ended December 31, 2013 (Nitrogen Fertilizer Business)2015
Net Sales. Nitrogen fertilizer net sales were $298.7$356.3 million for the year ended December 31, 2014,2016, compared to $323.7$289.2 million for the year ended December 31, 2013.2015. The net sales decreaseincrease of $25.0$67.1 million wasis primarily attributable to increased sales volume due to the resultinclusion of lower UAN sales pricesthe nine months of the East Dubuque Facility ($25.8 million), lower ammonia sales volumes ($10.7 million) and lower ammonia sales prices ($3.0 million), partially offset by higher UAN sales volumes ($14.6128.0 million). For the year ended December 31, 2014,2016, UAN ammonia and hydrogenammonia made up $273.7 million, $13.1$249.1 million and $10.1$78.0 million of the nitrogen fertilizer business' net sales, respectively. This compared to UAN ammonia and hydrogenammonia net sales of $284.9 million, $26.8$258.8 million and $11.4$17.2 million, respectively, for the year ended December 31, 2013.2015.
Excluding the East Dubuque Merger, net sales would have decreased by $60.9 million. The following table demonstrates the impact of changes in sales volumes and pricing for the primary components of net sales price for UAN, ammonia and hydrogenat the Coffeyville Fertilizer Facility for the year ended December 31, 20142016 compared to the year ended December 31, 2013:2015:
| | | | 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) | | Price Variance | | Volume Variance | Price
Variance | | Volume
Variance |
| |
| | | | | | | | | | | | | | | | (in millions) | (in millions) |
| UAN | 951,043 |
| | $ | 288 |
| | $ | 273.7 |
| | 904,596 |
| | $ | 315 |
| | $ | 284.9 |
| | 46,447 |
| | $ | (11.2 | ) | | $ | (25.8 | ) | | $ | 14.6 |
| $ | (69.8 | ) | | $ | 16.8 |
|
| Ammonia | 24,378 |
| | $ | 536 |
| | $ | 13.1 |
| | 40,535 |
| | $ | 660 |
| | $ | 26.8 |
| | (16,157 | ) | | $ | (13.7 | ) | | $ | (3.0 | ) | | $ | (10.7 | ) | $ | (7.6 | ) | | $ | 6.8 |
|
| Hydrogen | 996,516 |
| | $ | 10 |
| | $ | 10.1 |
| | 1,165,300 |
| | $ | 10 |
| | $ | 11.4 |
| | (168,784 | ) | | $ | (1.3 | ) | | $ | 0.3 |
| | $ | (1.6 | ) | $ | (1.8 | ) | | $ | (6.8 | ) |
| |
(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 aThe decrease of 39.9% in ammonia sales unit volumes. The increase in UAN and decrease in ammonia sales volumeprices at the Coffeyville Fertilizer Facility for the year ended December 31, 20142016 compared to the year ended December 31, 20132015 was partiallyprimarily attributable to pricing fluctuation in the market. The increase of UAN expansion being available for the full period in 2014.
Product pricing at gate represents net sales less freight revenue divided by productand ammonia sales volume in tons. Product pricing at gatethe Coffeyville Fertilizer Facility for the year ended December 31, 20142016 compared to the year ended December 31, 20132015 was primarily attributable to the lost production during the Coffeyville Fertilizer Facility major scheduled turnaround during the third quarter of 2015. Lower hydrogen needs from the Refining Partnership resulted in 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 and amortization) includes cost of freight and distribution expenses, pet coke expenses, purchased ammonia and purchased hydrogen. Cost of product sold excluding depreciation and amortizationhydrogen sales volume at the Coffeyville Fertilizer Facility for the year ended December 31, 20142016 compared to the year ended December 31, 2015.
Cost of Materials and Other. Cost of materials and other for the year ended December 31, 2016 was $72.0$93.7 million, compared to $58.1$65.2 million for the year ended December 31, 2013.2015. The $13.9$28.5 million increase resulted from $15.3 million in higher costs from transactions with third parties,was attributable to the inclusion of the nine months of the East Dubuque Facility ($36.7 million), which is offset by lower costs from transactions with affiliates of $1.4 million. The higher third-party costs incurred during the year ended December 31, 2014 were primarily the result of increased 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 ofcost decreases at the nitrogen fertilizer business' fleet due for regulatory inspections and related repairs during the year ended December 31, 2014 as compared to the prior year.Coffeyville Fertilizer Facility.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer business consist primarily of energy and utility costs, direct costs of labor, property taxes, plant-related maintenance services and environmental and safety compliance costs as well as catalyst and chemical costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 20142016 were $98.9$148.3 million, as compared to $94.1$106.1 million for the year ended December 31, 2013.2015. The total increase of $4.8$42.2 million for the year ended December 31, 2014,2016, as compared to the year ended December 31, 2013,2015, was comprisedprimarily attributable to the inclusion of a $5.9 million increase in costs from transactions with third parties, partially offset by a $1.1 million decrease in direct operating
costs from affiliates. The increase resulted primarily from higher utilities, netthe East Dubuque Facility ($1.355.7 million), refractory brick amortization ($2.7 million), repairs and maintenance ($1.2 million), partially offset by lower insurance costs ($1.1 million). The increased utility costs were largely due to higher electrical and natural gas prices, partially offset by lower electrical volumes. The increase in refractory brick amortization is primarily due to a decrease in the estimated useful life to reflect higher estimated rates of use in the production process.
Operating Income. Nitrogen fertilizer operating income was $82.8$26.8 million for the year ended December 31, 2014,2016, as compared to operating income of $124.9$68.7 million for the year ended December 31, 2013.2015. The decrease of $42.1$41.9 million for the year ended December 31, 2014 as compared to the year ended December 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 ($4.842.2 million) and, depreciation and amortization ($1.729.8 million), cost of materials and other ($28.5 million) and selling, general and administrative expenses ($8.5 million), partially offset by a decreaseincreases in selling, general and administrative expensenet sales ($3.367.1 million).
Liquidity and Capital Resources
Although results are consolidated for financial reporting, CVR Energy, CVR Refining and CVR Partners are independent business entities and operate with independent capital structures. Since the Nitrogen Fertilizer Partnership's IPO in April 2011 and the Refining Partnership's IPO in January 2013, with the exception of cash distributions paid to us by the Nitrogen Fertilizer Partnership and the Refining Partnership, the cash needs of the Nitrogen Fertilizer Partnership and the Refining Partnership have been met independently from the cash needs of CVR Energy and each other with a combination of existing cash and cash equivalent balances, cash generated from operating activities and credit facility borrowings. The Refining Partnership's and the Nitrogen Fertilizer Partnership's ability to generate sufficient cash flows from their respective operating activities and to then make distributions on their common units, 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 to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.
We believe that the petroleum business and the nitrogen fertilizer business' cash flows from operations and existing cash and cash equivalents, along with borrowings under their respective existing credit facilities, as necessary, will be sufficient to satisfy the anticipated cash requirements associated with their existing operations for at least the next twelve12 months, and that we have sufficient cash resources to fund our operations for at least the next twelve12 months. 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 outsidebeyond our control.
Depending on the needs of our businesses, contractual limitations and market conditions, we may from time to time seek to issue equity securities, incur additional debt, issue debt securities, or otherwise refinance our existing debts. There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.
Cash Balances and Other Liquidity
As of December 31, 2015,2017, we had consolidated cash and cash equivalents of $765.1$481.8 million. Of that amount, $527.8$258.8 million was cash and cash equivalents of CVR Energy, $187.3$173.8 million was cash and cash equivalents of the Refining Partnership and $50.0$49.2 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. As of February 16, 2016,20, 2018, we had consolidated cash and cash equivalents of approximately $796.6$499.7 million.
The Amended and Restated ABL Credit Facility provides the Refining Partnership with borrowing availability of up to $400.0 million with an incremental 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 the credit facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base 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. As of February 16, 2016, the Refining Partnership had $262.1 million available under the Amended and Restated ABL Credit Facility. Availability under the Amended 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 an uncommitted incremental facility of up to $50.0 million. The Nitrogen Fertilizer Partnership's credit facility matures in April 2016. The Nitrogen Fertilizer Partnership's credit facility is used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF. As of February 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, and the $125.0 million principal portion of the term loan facility is presented as a current
liability as of December 31, 2015. On February 9, 2016, CRLLC and the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant to which CRLLC agreed to guaranty the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. Refer to Note 9 ("Long-Term Debt") to Part II, Item 8 of this Report for discussion of the guaranty. The Nitrogen Fertilizer Partnership is considering various capital structure and refinancing options in regard to the credit facility and in contemplation of the Rentech Nitrogen mergers as discussed in "Pending Mergers." The Nitrogen Fertilizer Partnership anticipates these 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 this Report, the Nitrogen Fertilizer Partnership entered into a 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 Partners term 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 Rentech Nitrogen's existing $50.0 million credit facility with General Electric Capital Corporation, the cash consideration payable by the Nitrogen Fertilizer Partnership upon closing of the mergers and expenses associated with the 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 the actual 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 cash each quarter, within 60 days after the end of each quarter. The Refining Partnership's distributions began with the quarter ended March 31, 2013 and were adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO). The distributions are made to all common unitholders. As of December 31, 2015,2017, we held approximately 66% and 53%34% of the Refining Partnership's and the Nitrogen Fertilizer Partnership's common units outstanding, respectively. The amount of each distribution will be determined pursuant to each general partner's calculation of available cash for the applicable quarter. The general partner of each partnership, as a non-economic interest holder, is not entitled to receive cash distributions. As a result of each general partner's distribution policy, funds held by the Refining Partnership and the Nitrogen Fertilizer Partnership will not be available for our use, and we as a unitholder will receive our applicable percentage of the distribution of funds within 60 days following each quarter. The Refining Partnership and the Nitrogen Fertilizer Partnership do not have a legal obligation to pay distributions and there is no guarantee that they will pay any distributions on the units in any quarter.
Borrowing Activities
2023 Notes. The Nitrogen Fertilizer Partnership and CVR Nitrogen Finance Corporation ("CVR Nitrogen Finance") issued $645.0 million aggregate principal amount of 9.250% Senior Secured Notes due 2023 are guaranteed on a senior secured basis by all of the Nitrogen Fertilizer Partnership's existing subsidiaries.
At any time prior to June 15, 2019, the Nitrogen Fertilizer Partnership may on any of one or more occasions redeem up to 35% of the aggregate principal amount of the 2023 Notes issued under the indenture governing the 2023 Notes in an amount not greater than the net proceeds of one or more public equity offerings at a redemption price of 109.250% of the principal amount of the 2023 Notes, plus any accrued and unpaid interest to the date of redemption. Prior to June 15, 2019, the Nitrogen Fertilizer Partnership may on any one or more occasions redeem all or part of the 2023 Notes at a redemption price equal to the sum of: (i) the principal amount thereof, plus (ii) the Make Whole Premium, as defined in the indenture governing the 2023 Notes, at the redemption date, plus any accrued and unpaid interest to the applicable redemption date.
On and after June 15, 2019, the Nitrogen Fertilizer Partnership may on any one or more occasions redeem all or a part of the 2023 Notes at the redemption prices (expressed as percentages of principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such Notes, if redeemed during the 12-month period beginning on June 15 of the years indicated below:
|
| | |
| Year | | Percentage |
| 2019 | | 104.625% |
| 2020 | | 102.313% |
| 2021 and thereafter | | 100.000% |
Upon the occurrence of certain change of control events as defined in the indenture (including the sale of all or substantially all of the properties or assets of the Nitrogen Fertilizer Partnership and its subsidiaries taken as a whole), each holder of the 2023 Notes will have the right to require that the Nitrogen Fertilizer Partnership repurchase all or a portion of such holder’s 2023 Notes in cash at a purchase price equal to 101% of the aggregate principal amount thereof plus any accrued and unpaid interest to the date of repurchase.
See Part II, Item 8, Note 11 ("Long-Term Debt") of this Report for additional information on the 2023 Notes, including a description of the covenants contained therein. The Nitrogen Fertilizer Partnership was in compliance with the covenants as of December 31, 2017. The Nitrogen Fertilizer Partnership also had a nominal principal amount of 6.50% Senior Notes due 2021 (the "2021 Notes") outstanding as of December 31, 2017, which contain substantially no restrictive covenants and are not secured. See Part II, Item 8, Note 11 ("Long-Term Debt") of this Report for additional information regarding the 2021 Notes.
2022 Notes. On October 23, 2012, CVRThe Refining LLC ("Refining LLC") and its wholly-owned subsidiary, Coffeyville Finance Inc. ("Coffeyville Finance"), issuedPartnership's $500.0 million aggregate principal amount of the 2022 Notes. The net proceeds from the offering of the 2022 Notes were used to purchase all of the First6.5% Second Lien SecuredSenior Notes due 2015 through a tender offer2022 are unsecured 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 interest expense using the effective-interest amortization method. As of December 31, 2015, the 2022 Notes had an aggregate principal balance and a net carrying value 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 of Refining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) 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 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 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes were no longer secured 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 outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Refining Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership incurred approximately $0.4 million of debt registration costs 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 as interest expense using the effective-interest amortization method.
The 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. Interest is 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 priceprices (expressed as percentages of (i) 103.250% ofprincipal amount) set forth below, plus any accrued and unpaid interest to the principal amount thereof,applicable redemption date on such 2022 Notes, if redeemed during the twelve-month12-month period beginning on November 1 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2019; and (iv) 100% of the principal amount, if redeemed on or after November 1, 2020, in each case, plus any accrued and unpaid interest. years indicated below:
|
| | | |
| Year | | Percentage |
| 2017 | | 103.250 | % |
| 2018 | | 102.167 | % |
| 2019 | | 101.083 | % |
| 2020 and thereafter | | 100.000 | % |
Prior to November 1, 2017, some or all of the 2022 Notes may bewere able to have been redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.
In the event of a "change of control," the issuers are required to offer to buy back all of the 2022 Notes at 101% of their principal amount. A change of control 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 any person other than qualifying owners (as defined in the indenture), (ii) liquidation or dissolution of Refining LLC, or (iii) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the voting stockmember interest of Refining LLC.
The indenture governingSee Part II, Item 8, Note 11 ("Long-Term Debt") of this Report for additional information on the 2022 Notes, imposes covenants that restrict the abilityincluding a description of the issuers and subsidiary guarantors to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes are rated investment grade by both Standard & Poor's Rating Services and Moody's Investors Services, Inc. However, such covenants would be reinstituted if the 2022 Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would result in, 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 other available 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 will apply differently depending on the Refining Partnership'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 Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, 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.contained therein. The Refining Partnership was in compliance with the covenants as of December 31, 2015, and the ratio was satisfied (not less than 2.5 to 1.0).2017.
Amended and Restated Asset Based (ABL) Credit Facility. On December 20, 2012,November 14, 2017, CRLLC, CVR Refining, Refining LLC and certaineach of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into Amendment No. 1 to the Amended and Restated ABL Credit FacilityAgreement (the “Amendment”) with a group of lenders and Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent and collateral agent for a syndicateagent. The Amendment amends certain provisions of lenders. The Amended and Restated ABL Credit Facility replaced our prior ABL credit facility. Under the Amended and Restated ABL Credit Facility,Agreement, dated December 20, 2012, by and among Wells Fargo, the Refining Partnership assumed our positiongroup of lenders party thereto and the Credit Parties (the “Existing Credit Agreement” and as borrower and our obligations underamended by the AmendedAmendment, the “Amended and Restated ABL Credit Facility upon the closing of the Refining Partnership IPO on January 23, 2013.Facility”), which was otherwise scheduled to mature in December 2017. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swing lineswingline loans of $360.0$60.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The proceeds of the loans may be used for capital expenditures, working capital and general corporate purposes. The Amended and Restated Credit Facility matures in November 2022.
As of February 20, 2018, the Refining Partnership had $359.1 million available under the Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability and projected excess availability at all times during the three-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the six-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 to 1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and may be used for working capital and other general corporate purposes (including permitted acquisitions).
BorrowingsFacility. Availability under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of thewas limited by borrowing base andconditions.
See Part II, Item 8, Note 11 ("Long-Term Debt") of this Report for additional information on the total commitments
and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility, also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50%a description of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership is also required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and 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 amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility.contained therein. The Refining Partnership was in compliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2015.2017.
Old Senior Secured Notes.Asset Based (ABL) Credit Facility. On April 6, 2010, CRLLCThe Nitrogen Fertilizer Partnership has an ABL Credit Facility, the proceeds of which may be used to fund working capital and its then wholly-owned subsidiary, Coffeyville Finance completed the private offering of $225.0 millionother general corporate purposes. The ABL Credit Facility is a senior secured asset-based revolving credit facility with an aggregate principal amount of Old Second Lien Notes. We redeemed all outstanding Old Second Lien Notes on January 23, 2013, following the 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, entered into a credit facility (the "Nitrogen Fertilizer Partnership credit facility") with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The Nitrogen Fertilizer Partnership credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facilityavailability of up to $50.0 million. There is no scheduled amortizationmillion with an incremental facility, which permits an increase in borrowings of up to $25.0 million in the aggregate subject to additional lender commitments and the Nitrogen Fertilizer Partnership credit facilitycertain other conditions. The ABL Credit Facility matures in April 2016, as discussed above.September 2021.
Borrowings under the Nitrogen Fertilizer Partnership credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the Nitrogen Fertilizer Partnership credit facility is the Eurodollar rate plus a marginAs of 3.50%, or for base rate loans, the prime rate plus 2.50%. Under its terms, the lenders under the Nitrogen Fertilizer Partnership credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF andFebruary 20, 2018, the Nitrogen Fertilizer Partnership and allits subsidiaries had availability under the ABL Credit Facility of $46.4 million. Availability under the ABL Credit Facility was limited by borrowing base conditions.
See Part II, Item 8, Note 11 ("Long-Term Debt") of this Report for additional information on the ABL Credit Facility, including a description of the capital stock of CRNF and each domestic subsidiary owned by the Nitrogen Fertilizer Partnership or CRNF. CRNF is the borrower under the Nitrogen Fertilizer Partnership credit facility. All obligations under the Nitrogen Fertilizer Partnership credit facility are unconditionally guaranteed by the Nitrogen Fertilizer Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility are non-recourse to the Company 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 the Nitrogen Fertilizer Partnership and CRNF) terminates or violates any of its covenants in any of the intercompany agreements between the Nitrogen Fertilizer Partnership and CVR Energy and its subsidiaries (other than the Nitrogen Fertilizer Partnership and CRNF) and such action has a material adverse effect on the Nitrogen Fertilizer Partnership. If an event of default occurs, the administrative agent under the Nitrogen Fertilizer Partnership credit facility would be entitled 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 Swaps
contained therein. The Nitrogen Fertilizer Partnership has determined thatwas in compliance with the two interest rate swap agreements entered into in 2011 qualify for hedge accounting treatment. The impact recorded for eachcovenants as of the years ended December 31, 2015, 2014 and 2013 was $1.1 million, in additional interest expense. For the years ended December 31, 2015, 2014 and 2013, the Nitrogen Fertilizer Partnership recorded a decrease in fair market value on the interest rate swaps of $0.1 million, $0.2 million and $0.2 million, respectively, which was unrealized in accumulated other comprehensive income (loss) ("AOCI"). The combined fair market
value of the interest rate swaps recorded in other current liabilities on the Consolidated Balance Sheets at December 31, 2015 is not material. This amount is unrealized and, therefore, included in AOCI.2017.
Capital Spending
We divide the petroleum business and the nitrogen fertilizer business' capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.
The following table summarizes our total actual capital expenditures for 20152017 and current estimated capital expenditures in 20162018 by operating segment and 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 the manner allocated below:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 Actual | | 2016 Estimate | 2017 Actual | | 2018 Estimate |
| | (in millions) | (in millions) |
| | (unaudited) | (unaudited) |
| Petroleum Business (the Refining Partnership): | | | | | | |
| Coffeyville refinery: | | | | | | |
| Maintenance | $ | 69.7 |
| | $ | 60.0 |
| $ | 36.9 |
| | $ | 75.0 |
|
| Growth | 73.2 |
| | 50.0 |
| 3.0 |
| | 10.0 |
|
| Coffeyville refinery total capital excluding major scheduled turnaround expenses | 142.9 |
| | 110.0 |
| |
| Coffeyville refinery total capital spending | | 39.9 |
| | 85.0 |
|
| Wynnewood refinery: | | | | | | |
| Maintenance | 25.6 |
| | 40.0 |
| 38.1 |
| | 65.0 |
|
| Growth | 6.4 |
| | 6.0 |
| 4.0 |
| | 25.0 |
|
| Wynnewood refinery total capital excluding major scheduled turnaround expenses | 32.0 |
| | 46.0 |
| |
| Wynnewood refinery total capital spending | | 42.1 |
| | 90.0 |
|
Other Petroleum: | | | | | | |
| Maintenance | 8.1 |
| | 20.0 |
| 2.7 |
| | 15.0 |
|
| Growth | 11.7 |
| | 24.0 |
| 15.0 |
| | 10.0 |
|
| Other petroleum total capital excluding major scheduled turnaround expenses | 19.8 |
| | 44.0 |
| |
| Petroleum business total capital excluding major scheduled turnaround expenses | 194.7 |
| | 200.0 |
| |
| Other petroleum total capital spending | | 17.7 |
| | 25.0 |
|
| Petroleum business total capital spending | | 99.7 |
| | 200.0 |
|
| Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership): | | | | | | |
| Maintenance | 9.5 |
| | 7.0 |
| 14.1 |
| | 18.0 |
|
| Growth | 7.5 |
| | 3.0 |
| 0.4 |
| | 3.0 |
|
| Nitrogen fertilizer business total capital excluding major scheduled turnaround expenses | 17.0 |
| | 10.0 |
| |
| Nitrogen fertilizer business total capital spending | | 14.5 |
| | 21.0 |
|
| Corporate | 7.0 |
| | 10.0 |
| 4.4 |
| | 10.0 |
|
| Total capital spending excluding major scheduled turnaround expenses | $ | 218.7 |
| | $ | 220.0 |
| |
| Total capital spending | | $ | 118.6 |
| | $ | 231.0 |
|
The petroleum business' and the nitrogen fertilizer business' estimated capital expenditures are subject to change due to unanticipated increaseschanges in the cost, scope and completion time for capital projects. For example, they may experience increasesincreases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of the refineries or nitrogen fertilizer plant.plants. The petroleum business and nitrogen fertilizer business may also accelerate or defer some capital expenditures from time to time. Capital spending for the Nitrogen Fertilizer Partnership's nitrogen fertilizer business and the Refining Partnership's petroleum business is determined by each partnership's respective board of directors of its general partner.
In October 2014,On December 1, 2017, CVR Refining acquired the board of directors of the general partner of the Refining Partnership approved the construction of a hydrogen plant at the Coffeyville refinery. The hydrogen plant will increase the overall plant liquid volume recovery and provide additional hydrogen thatCushing to Ellis crude oil pipeline system from Plains All American Pipeline, L.P. ("Plains") for $15.0 million, which amount is needed for environmental compliance. The estimated cost of this project, excluding capitalized interest, is approximately $122.5 million with an anticipated completion dateincluded in other petroleum growth capital spending in the second quarter of 2016. As oftable above. The approximately 100-mile, 8- and 10-inch pipeline system links CVR Refining’s Wynnewood, Oklahoma, refinery to Cushing.
December 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 an additional 0.5 million barrels of crude storage capacity. The tanks became operational in October 2015. As of December 31, 2015, the Refining Partnership had incurred costs of approximately $9.8 million, excluding capitalized interest, for the crude oil storage tanks. The total cost of this project, excluding capitalized interest, is expected to be approximately $11.0 million to $12.0 million.
Cash Flows
The following table sets forth our consolidated cash flows for the periods indicated below:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Net cash provided by (used in): | | | | | | | | | | |
| Operating activities | $ | 536.8 |
| | $ | 640.3 |
| | $ | 440.1 |
| $ | 166.9 |
| | $ | 267.5 |
| | $ | 536.8 |
|
Investing activities | (150.6 | ) | | (296.6 | ) | | (250.3 | ) | (195.0 | ) | | (201.4 | ) | | (150.6 | ) |
| Financing activities | (374.8 | ) | | (432.1 | ) | | (243.7 | ) | (225.9 | ) | | (95.4 | ) | | (374.8 | ) |
| Net increase (decrease) in cash and cash equivalents | $ | 11.4 |
| | $ | (88.4 | ) | | $ | (53.9 | ) | $ | (254.0 | ) | | $ | (29.3 | ) | | $ | 11.4 |
|
| |
| (1) | Investing activities for the year ended December 31, 2017 includes the acquisition of the Cushing to Ellis crude oil pipeline system totaling $15.0 million and equity method investments in the Midway joint venture of $76.0 million. |
Cash Flows Provided by Operating Activities
For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.
Net cash flows provided by operating activities for the year ended December 31, 2017 were $166.9 million. The negative cash flow from operating activities generated over this period was primarily driven by $216.9 million of net income before noncontrolling interest and favorable impacts to trade working capital, partially offset by unfavorable impacts to other working capital. Trade working capital for the year ended December 31, 2017 resulted in a net cash inflow of $23.2 million, which was attributable to an increase in accounts payable ($88.1 million), offset by increases in accounts receivable ($27.3 million) and inventory ($37.6 million).The increase in accounts payable was primarily associated with an increase in the petroleum business' lease crude payables due to increased activity and crude pricing. The increase in accounts receivable was primarily attributable to increased pricing and volume for petroleum products sold and the increase in inventories was primarily related to increased pricing for gasoline, distillates and crude oil in the petroleum business. Other working capital activities resulted in a net cash outflow of $148.3 million, which was primarily related to decreases in other current liabilities ($168.0 million) and due to parent ($15.7 million), partially offset by a decrease in prepaid expenses and other current assets ($33.9 million). The large decrease in other current liabilities was primarily attributable to a decrease in the petroleum business' biofuel blending obligation as a result of RINs purchases during the year ended December 31, 2017 to fulfill the petroleum business' requirements under the RFS, partially offset by an increase in unrealized loss on open derivative positions and forward purchase commitments. The decrease in due to parent was the result of the timing and application of the tax payments to AEPC under the Tax Allocation Agreement. The decrease in prepaid expense was primarily related to a decrease in crude barrels in-transit and a decrease in prepaid pipeline capacity.
Net cash flows provided by operating activities for the year ended December 31, 2016 were $267.5 million. The positive cash flow from operating activities generated over this period was primarily driven by $8.9 million of net income before noncontrolling interest and favorable impacts to other working capital, partially offset by unfavorable impacts to trade working capital. Trade working capital for the year ended December 31, 2016 resulted in a net cash outflow of $65.2 million, which was attributable to increases in accounts receivable ($47.5 million) and inventory ($7.3 million), primarily attributable to increased pricing for petroleum products, and a decrease in accounts payable ($10.4 million). Each of the cash flow impacts in trade working capital were largely attributable to the crude oil pricing environment and increases in sales prices for gasoline and distillates at the petroleum business in 2016 as compared to 2015. Other working capital activities resulted in a net cash inflow of $146.3 million, which was primarily related to increases in other current liabilities ($151.2 million) and due to parent ($22.2 million), partially offset by decreases in deferred revenue ($20.4 million) and accrued income taxes ($3.3 million) and an increase in prepaid expenses and other current assets ($3.4 million). The large increase in other current liabilities was primarily attributable to the increase in the biofuel blending obligation at the petroleum business to fulfill the petroleum business' requirements under the RFS, as a result of increased RINs obligation associated with increased RINs prices during the year ended December 31, 2016. The increase in due to parent was the result of the timing and application of the tax payments to AEPC under the Tax Allocation Agreement. The decrease in deferred revenue was primarily attributable to the East Dubuque Merger. Settlements on derivative contracts during 2016 also contributed to the positive cash flow from operating activities.
Net cash flows provided by operating activities for the year ended December 31, 2015 were $536.8 million. The positive cash flow from operating activities generated over this period was primarily driven by $297.8 million of net income before noncontrolling interest and favorable impacts to trade working 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, which was attributable to decreases in accounts receivable ($41.0 million) and inventory ($39.7 million), partially offset by a decrease in accounts payable ($14.3 million). Each of the cash flow impacts in trade working capital were largely attributable to the crude oil pricing environment and significant decreases in sales 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 other current assets was primarily due to the sale of trading securities, the timing of payments associated with the petroleum business' crude oil intermediation agreement and a reduction in prepaid insurance. The decrease in due from parent was the result of the timing and application of overpayments to AEPC under the Tax Allocation Agreement. The decrease in other current liabilities was primarily attributable to a decrease in the biofuel blending obligation at the petroleum business as a result of increased RINs purchases during the year ended December 31, 2015 to fulfill the petroleum business' requirements under the RFS. The decrease in deferred revenue was primarily attributable to lower market demand for prepaid contracts at the nitrogen fertilizer business for the year ended 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 operating activities generated over this period was primarily driven by $309.4 million of net income before noncontrolling interest and favorable impacts to trade working capital of $211.2 million, partially offset by an unfavorable impact to other working capital of $6.3 million. Trade working capital for the year ended December 31, 2014 resulted in a net cash inflow of $211.2 million, which was attributable to decreases in inventory ($197.3 million) and accounts receivable ($105.7 million), partially offset by a decrease in accounts payable ($91.8 million). Each of the cash flow impacts in trade working capital were largely attributable to the crude oil pricing environment and significant reduction in pricing during the fourth quarter of 2014. The favorable trade working capital 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 of 2014. These favorable trade working capital impacts were partially offset by the decrease in accounts payable at the petroleum business as a result of payables 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 in an on-going litigation matter during 2014. Other working capital activities resulted in net cash outflow of $6.3
million, 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 ($15.0 million), 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 attributable to 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 ended December 31, 2014 compared to the prior period. The decrease in prepaid expenses and other current assets was primarily due to a reduction in prepaid insurance 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 operating activities generated over this period was primarily driven by $522.0 million of net income before noncontrolling interest, partially offset by unfavorable impacts to trade working capital $67.4 million and other working capital $53.2 million. Trade working capital for the year ended December 31, 2013 resulted in 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 accounts payable of ($38.7 million). The increase in accounts receivable primarily resulted from increased sales volumes at the petroleum business as compared to the end of 2012 due to the turnaround at the Wynnewood refinery completed in the fourth quarter of 2012. The decrease in accounts payable was largely the result of a decrease in amounts payable related to the turnaround completed at the Wynnewood refinery in the fourth quarter of 2012, partially offset by increased payables for leased crude purchases due to increased crude gathering capacity and timing of payments. Other working capital activities resulted in net 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 in other current liabilities ($26.7 million), partially offset by an increase in due (to) from parent ($9.1 million). The increase in prepaid expenses and other current assets was primarily due to timing of settlements associated with the petroleum business' crude oil intermediation agreement. The decrease in other current liabilities was primarily attributable to a decrease in liabilities related to share-based compensation, property taxes and interest on borrowings as compared to the prior year-end.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended December 31, 20152017 was $150.6$195.0 million compared to $296.6$201.4 million for the year ended December 31, 2014.2016. The decrease of $146.0$6.4 million of cash used in investing activities was primarily due to the resultnet cash paid by the nitrogen fertilizer business in 2016 for the acquisition of decreased purchases of available-for-sale securitiesCVR Nitrogen ($78.363.8 million) and proceeds received from the sale of available-for-sale securities ($68.0 million) for the year ended December 31, 2015. Capital spending remained relatively consistent for the year ended December 31, 2015lower capital expenditures in 2017 compared to 2016 ($14.1 million), offset by an increase in cash investments in affiliates in 2017 compared to 2016 ($70.9 million) primarily associated with the year ended December 31, 2014.petroleum business' investment in the Midway joint venture.
Net cash used in investing activities for the year ended December 31, 20142016 was $296.6$201.4 million compared to $250.3$150.6 million for the year ended December 31, 2013.2015. The increase inof $50.8 million of cash used in investing activities was primarily due to the resultnet cash paid for the acquisition of CVR Nitrogen ($63.8 million), security purchases of held($18.6 million), investment in VPP ($5.6 million) and a decrease in proceeds from available-for-sale securities during the year ended December 31, 2014,($48.7 million), partially offset by a $38.1 million decrease in capital spending. The decrease in capital spending was primarily the result of decreases in nitrogen fertilizer capital expenditures of approximately $22.7 million following the completion of the UAN expansion project in February 2013.during 2016 ($86.0 million).
Cash Flows Used In Financing Activities
Net cash used in financing activities for the year ended December 31, 2017 was $225.9 million compared to $95.4 million for the year ended December 31, 2016. The net cash used in financing activities for the year ended December 31, 2017 was primarily attributable to dividend payments of $173.7 million to our common stockholders and distributions of $47.3 million and $1.5 million to the Refining Partnership's and Nitrogen Fertilizer Partnership's common unitholders, respectively. The increase in net cash used in financing activities of $130.5 million for the year ended December 31, 2017 compared to 2016 was primarily due to the $132.5 million net proceeds received in 2016 from the Nitrogen Fertilizer Partnerships' issuance of 2023 Notes net of debt repayments.
Net cash used in financing activities for the year ended December 31, 2016 was $95.4 million. The net cash used in financing activities for the year ended December 31, 2016 was primarily attributable to debt repayments totaling $496.3 million, dividend payments of $173.6 million to common stockholders and distributions of $41.9 million to the Nitrogen Fertilizer Partnership common unitholders, offset by net proceeds of $628.8 million from the Nitrogen Fertilizer Partnerships' issuance of 2023 Notes.
Net cash used in financing activities for the year ended December 31, 2015 was approximately $374.8 million. The net cash used in financing activities for the year ended December 31, 2015 was primarily attributable to dividend payments to common stockholders of $173.7 million and distributions to the Refining 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 activities for the year ended December 31, 2014 was primarily attributable to dividend payments to common stockholders of $434.2 million, distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $184.9 million, partially offset by proceeds of $188.3 million from the Refining 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 activities for the year ended December 31, 2013 was primarily attributable to dividend payments of $1,237.3 million, distributions to the Refining Partnership and Nitrogen Fertilizer Partnership common unitholders of $164.2 million and payments to extinguish the Second Lien Notes of $243.4 million, largely offset by proceeds from CVR Refining's initial public offering of $655.7 million, proceeds from CVR Refining's Underwritten Offering of $393.6 million, proceeds
from 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, 2015,2017, there were no borrowings or repayments under the Amended and Restated ABL credit facilityCredit Facility or the Nitrogen Fertilizer Partnership revolving credit facility.ABL Credit Facility.
Capital and Commercial Commitments
In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of December 31, 20152017 relating to long-term debt outstanding, operating leases, capital lease obligations, unconditional purchasecontractual obligations and other specified capital and commercial commitments for the five-year period following December 31, 20152017 and thereafter.
| | | | Payments Due by Period | Payments Due by Period |
| | Total | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | Thereafter | Total | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter |
| | (in millions) | (in millions) |
| Contractual Obligations | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt(1) | $ | 625.0 |
| | $ | 125.0 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 500.0 |
| $ | 1,147.2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 2.2 |
| | $ | 500.0 |
| | $ | 645.0 |
|
| Operating leases(2) | 23.5 |
| | 8.0 |
| | 5.5 |
| | 3.9 |
| | 2.1 |
| | 1.5 |
| | 2.5 |
| 32.3 |
| | 7.4 |
| | 6.5 |
| | 5.9 |
| | 5.3 |
| | 4.8 |
| | 2.4 |
|
| Capital lease obligations(3) | 48.5 |
| | 1.6 |
| | 1.9 |
| | 2.1 |
| | 2.3 |
| | 2.6 |
| | 38.0 |
| 45.0 |
| | 2.1 |
| | 2.3 |
| | 2.6 |
| | 2.9 |
| | 3.1 |
| | 32.0 |
|
| Unconditional purchase obligations(4) | 1,349.6 |
| | 141.0 |
| | 125.6 |
| | 124.3 |
| | 123.5 |
| | 107.8 |
| | 727.4 |
| 1,107.1 |
| | 165.0 |
| | 124.3 |
| | 100.6 |
| | 89.8 |
| | 84.7 |
| | 542.7 |
|
| Environmental liabilities(5) | 3.7 |
| | 2.0 |
| | 0.5 |
| | 0.5 |
| | 0.1 |
| | 0.1 |
| | 0.5 |
| 4.0 |
| | 2.9 |
| | 1.1 |
| | — |
| | — |
| | — |
| | — |
|
| Interest payments(6) | 270.1 |
| | 38.7 |
| | 37.1 |
| | 36.9 |
| | 36.7 |
| | 36.4 |
| | 84.3 |
| 518.3 |
| | 96.9 |
| | 96.7 |
| | 96.4 |
| | 96.1 |
| | 90.2 |
| | 42.0 |
|
| Total | $ | 2,320.4 |
| | $ | 316.3 |
| | $ | 170.6 |
| | $ | 167.7 |
| | $ | 164.7 |
| | $ | 148.4 |
| | $ | 1,352.7 |
| $ | 2,853.9 |
| | $ | 274.3 |
| | $ | 230.9 |
| | $ | 205.5 |
| | $ | 196.3 |
| | $ | 682.8 |
| | $ | 1,264.1 |
|
| Other Commercial Commitments | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Standby letters of credit(7) | $ | 27.8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 28.4 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| |
| (1) | Consists of the 2021 Notes, the 2022 Notes and the Nitrogen Fertilizer Partnership's term loan facility outstanding2023 Notes as of December 31, 2015. The Nitrogen Fertilizer Partnership'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.2017. |
| |
| (2) | The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, under operating leases for various periods. See Note 18 ("Related Party Transactions") to Part II, Item 8 of this Report for a discussion of our railcar leases with affiliates. |
| |
| (3) | The amount includes commitments under capital lease arrangements for two leases associated with pipelines and storage and terminal equipment at the Wynnewood refinery. |
| |
| (4) | The amount includes (a) commitments under several agreements for the petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electricelectricity supply agreement with the city of Coffeyville and electricity supply agreements associated with our East Dubuque Facility in Illinois, (c) a product supply agreement with Linde, (d) a pet coke supply agreement with HollyFrontier Corporation with a term ending in December 2016,2018, (e) commitments related to our biofuels blending obligation, (f) various agreements associated with our East Dubuque Facility in Illinois for gas and (f)gas transportation and (g) approximately $781.5$698.6 million payable ratably over fifteen13 years pursuant to petroleum transportation service agreements 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, 2015,2017, where applicable. 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 twenty20 years on TransCanada's Keystone pipeline system. The petroleum business began receiving crude oil under the agreements in the first quarter of 2011. |
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| (5) | Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and Wynnewood, Oklahoma. We also are required to make payments with respect to other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See "BusinessItem 1."Business — Environmental Matters." |
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| (6) | Interest payments are based on stated interest rates for our long-term debt outstanding and interest payments for the capital lease obligationsobligation as of December 31, 2015.2017 and also includes commitment fees on the unutilized commitments of the ABL Credit Facility. |
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| (7) | Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.2$0.3 million of letters of credit issued in connection with environmental liabilities, $26.7$26.5 million in letters of credit to secure transportation services for crude oil and a $0.9$1.6 million letter of credit issued to 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 budgeted capital expenditures and to satisfy their other capital and commercial commitments will depend on their respective independent abilities to generate cash flow in the future. Their ability to refinance their respective indebtedness is also subject to the availability of the credit markets, which in recent periods have been extremely volatile. This, to a certain extent, is subject to refining spreads (for the Refining Partnership), fertilizer margins (for the Nitrogen Fertilizer Partnership) and general economic, financial, competitive, legislative, regulatory and other factors they are unable to control. Our businesses may not generate sufficient cash flow from operations, and future borrowings may not be available to the Nitrogen Fertilizer Partnership under its revolving credit facility or any replacement credit facilitythe 2021 and 2023 senior notes or to the Refining Partnership under the Amended and Restated ABL Credit Facility or the 2022 senior notes (or other credit facilities our businesses 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 sell assets 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, and may not be able to refinance such indebtedness on commercially reasonable terms or at all.
Off-Balance Sheet Arrangements
We do not have any "off-balance sheet arrangements" as such term is defined within the rules and regulations of the SEC.
Recent Accounting Pronouncements
Refer to Part II, Item 8, Note 2 ("Summary of Significant Accounting Policies"), of this Report for a discussion of recent accounting pronouncements applicable to us.
Critical Accounting Policies
We 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 and subsequent events. Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Report. Our critical accounting policies, which are describedlisted below, could materially affect the amounts recorded in our consolidated financial statements.
Goodwill
•Estimated lives used in computing depreciation for property, plant and equipment
To comply with Accounting Standards Codification ("ASC") Topic 350, •Intangibles — Goodwill impairment
•Income taxes
•Impairment of long-lived assets
•Derivative instruments and Otherfair value of financial instruments
• ("ASC 350"), we perform a test for goodwill impairment annually, or more frequently in the event we determine that a triggering event has occurred. Our annual testing is performed as of November 1 each year. In accordance with ASC 350, we identified our reporting units based upon our two key operating segments. These reporting units are our petroleum and nitrogen fertilizer segments. For 2015, 2014 and 2013, the nitrogen fertilizer segment was the only reporting unit that had goodwill.Share-based compensation
In accordance with ASC 350, the nitrogen fertilizer segment may electRefer to performNote 2 ("Summary of Significant Accounting Policies") to Part II, Item 8 of this Report for a qualitative assessment to determine whether the two-step quantitative impairment test is required. If the nitrogen fertilizer segment elects to perform a qualitative assessment, the two-step impairment test is required only if the nitrogen 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 ended December 31, 2015 and 2014, the nitrogen fertilizer segment elected to perform a qualitative assessment.discussion of these accounting policies.
The nitrogen fertilizer segment began the qualitative assessment by analyzing the key drivers and other external factors that impact the business in order to 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 not more 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-step valuation. The key drivers that were considered in the evaluation of the nitrogen fertilizer segment's fair value included:
general economic conditions;
fertilizer pricing;
input costs;
liquidity and capital resources; and
customer outlook.
Long-Lived Assets
We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. We account for impairment of long-lived assets in accordance with ASC Topic 360, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets ("ASC 360"). In accordance with ASC 360, we review long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.
Derivative Instruments and Fair Value of Financial Instruments
The petroleum business uses futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices and finished goods product prices to provide economic hedges of inventory positions. Although management considers these derivatives economic hedges, these derivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging ("ASC 815"), and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. The petroleum business recorded 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 and 2013, 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 cash flow hedge. These derivative instruments have been designated as hedges for accounting purposes. Accordingly, these instruments are recorded at fair value in the Consolidated Balance Sheets, at each reporting period end. The actual measurement of the cash flow hedge ineffectiveness is recognized in earnings, if applicable. 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 approximates fair value, as a result of the short-term nature of the instruments.
Share-Based Compensation
We account for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation ("ASC 718"). ASC 718 requires that compensation costs relating to share-based payment transactions be recognized in a company's financial statements. ASC 718 applies to transactions in which 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 on the fair value of those equity instruments. Total share-based compensation expense for the years ended December 31, 2015, 2014 and 2013 was $12.8 million, $12.3 million and $18.4 million, respectively.
Income Taxes
We provide for income taxes in accordance with ASC Topic 740, Income Taxes, accounting for uncertainty in income taxes. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets and if
we 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 a valuation allowance. We consider future taxable income in making such assessments which requires numerous judgments and assumptions. We record contingent 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 Risk
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices, RINs prices, and interest rates. None of our market risk sensitive instruments are held for trading.trading purposes.
Commodity Price Risk
The petroleum business, as a manufacturer of refined petroleum products, and the nitrogen fertilizer business, as a manufacturer of nitrogen fertilizer products, 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 physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.
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, reducing its risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to the time elapsed between raw material acquisition and the sale of finished goods. In addition, the petroleum business seeks to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in the annual operating plan. Accordingly, 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 havehas entered into, derivative instruments which serve to:
lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows;
hedge the value of inventories in excess of minimum required inventories; and
manage existing derivative positions related to 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.business. The nitrogen fertilizer business has not historically hedged for commodity prices.
Basis Risk.
The effectiveness of ourthe petroleum business' derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors including time or location differences between the derivative instrument and the underlying physical commodity. OurThe selection of the appropriate index to utilize in a hedging strategy is a prime consideration in ourthe petroleum business' basis risk exposure.
Examples of our basis risk exposure are as follows:
Time Basis — In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will be weighted differently than the swap price as the result of timing.
Location Basis — In hedging NYMEX crack spreads, we experiencethe petroleum business experiences location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in ourits' Group 3 pricing area.
Price 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 price exposure to inventory positions that are in excess of its base level. Excess inventories are typically the result of plant operations, such as a turnaround or other plant maintenance.
To reduce the basis risk between the price of products for Group 3 and that of the NYMEX associated with selling forward derivative contracts for NYMEX crack spreads, the petroleum business may enter into basis swap positions to lock the price difference. If the difference between the price of products on the NYMEX and Group 3 (or some other price benchmark as specified in the swap) is different than the value contracted in the swap, then it will receive from 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 of the 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 forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or decreases then wethe petroleum business would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the Group 3 pricing.
From time to time, the petroleum business also holds various NYMEX positions through a third-party clearing house. At December 31, 2015,2017, the Refining Partnership had no open commodity positions. At December 31, 2015,2017, the Refining Partnership's account balance maintained at the third-party clearing house totaled approximately $7.5$1.4 million, which is reflected on the Consolidated Balance Sheets in cash and cash equivalents. NYMEX transactions conducted for the year ended December 31, 20152017 resulted in gain (loss)loss on derivatives, net of approximately $3.2$0.5 million.
The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, the Refining Partnership 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 are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheets with changes in fair value currently recognized in the Consolidated Statements of Operations. At December 31, 2015,2017, the Refining Partnership had open commodity hedgingswap instruments consisting of 2.57.1 million barrels of 2-1-1crack spreads, 3.6 million barrels of distillate crack spreads primarily to fix the margin on a portionand 3.6 million barrels of its future distillate production.gasoline crack spreads. Additionally, as of December 31, 2017, we had open forward purchase and sale commitments for 5.8 million barrels of Canadian crude oil priced at fixed differentials that are not considered probable of physical settlement and are accounted for as derivatives at December 31, 2017. A change of $1.00 per barrel in the fair value of the crack spread swapsbenchmark would result in an increase or decrease in the related fair values of commodity hedging instruments of $2.5 million. Additionally, at December 31, 2015, the Refining Partnership had open commodity hedging instruments consisting of 1.4 million 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 barrel in 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 hedging instruments of $1.4$17.7 million. The fair value of the outstanding contracts at December 31, 20152017 was a net unrealized gainloss of $44.6$64.3 million, comprised of short-term unrealized gains and losses.
Interest Rate Risk
As of December 31, 2015 and prior to the expiration of the interest rate swaps on February 12, 2016, the Nitrogen Fertilizer Partnership had exposure to interest 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 credit agreement, would increase interest cost to the Nitrogen Fertilizer Partnership by approximately $625,000 on an annualized basis, thus decreasing net income by 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 on 100% 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 increase interest cost to the Nitrogen Fertilizer Partnership by approximately $1,250,000$1.3 million on an annualized basis, thus decreasing net income by the same amount.
The credit facility expires on April 13, 2016. The Nitrogen FertilizerCompliance Program Price Risk
As a producer of transportation fuels from petroleum, the Refining Partnership is considering capital structure and refinancing options associatedrequired to blend biofuels into the product it produces or to purchase RINs in the open market in lieu of blending to meet the mandates established by the EPA. The Refining Partnership is exposed to market risk related to volatility in the price of RINs needed to comply with the credit facility maturity. The credit facility is discussed inRFS. To mitigate the impact of this risk on the Refining Partnership's results of operations and cash flows, the Refining Partnership purchased RINs when prices are deemed favorable. See Note 914 ("Long-Term Debt")Commitments and the interest rate swap agreements are discussed in Note 15 ("Derivative Financial Instruments"Contingencies") to Part II, Item 8 of this Report.Report and "Major Influences on Results of Operations" in Part II, Item 7 of this Report for further discussion about compliance with the RFS.
Foreign Currency Exchange
Given that ours, the petroleum business' and the nitrogen fertilizer business' operations are based entirely in the United States, we are not significantly exposed to foreign currency exchange rate risk. A portion of the petroleum business' Canadian crude oil purchasespipeline transportation costs are conductedtransacted 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 reporting period. Based on the short period of time between the deliverybilling and settlement of purchases of crude oilthese transportation costs in Canadian dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not material.
Item 8. Financial Statements and Supplementary Data
CVR Energy, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CVR Energy, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of CVR Energy, Inc. (a Delaware corporation) and subsidiaries (the "Company") as of December 31, 20152017 and 2014, and2016, the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Company's management. Our responsibility is to express 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)"financial statements"). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CVR Energy, Inc. and subsidiariesthe Company as of December 31, 20152017 and 2014,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20152017, 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) ("PCAOB"), the Company's internal control over financial reporting as of December 31, 2015,2017, based on criteria established in the 2013 Internal Control —- Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)("COSO"), and our report dated February 19, 201626, 2018 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
Houston, TexasWe have served as the Company's auditor since 2013.
Kansas City, Missouri
February 19, 201626, 2018
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CVR Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of CVR Energy, Inc. (a Delaware corporation) and subsidiaries (the "Company") as of December 31, 2015,2017, based on criteria established in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)("COSO"). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria 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) ("PCAOB"), the consolidated financial statements of the Company as of and for the year ended December 31, 2017, and our report dated February 26, 2018 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report Onon Internal Control Over Financial Reporting under Item 9A.. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance 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 on criteria 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 financial statements of the Company as of and for the year ended December 31, 2015, and our report dated February 19, 2016 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, TexasKansas City, Missouri
February 19, 201626, 2018
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| | (in millions, except share data) | (in millions, except share data) |
ASSETS | | Current assets: | | | | | | |
| Cash and cash equivalents | $ | 765.1 |
| | $ | 753.7 |
| |
| Accounts receivable, net of allowance for doubtful accounts of $0.3 and $0.4, respectively | 95.8 |
| | 136.7 |
| |
| Inventories | 289.9 |
| | 329.6 |
| |
| Prepaid expenses and other current assets | 105.4 |
| | 174.7 |
| |
| Income tax receivable | 6.9 |
| | 11.1 |
| |
| Deferred income taxes | — |
| | 6.3 |
| |
| Cash and cash equivalents (including $223.0 and $369.7, respectively, of consolidated variable interest entities ("VIEs")) | | $ | 481.8 |
| | $ | 735.8 |
|
Accounts receivable of VIEs, net of allowance for doubtful accounts of $1.1 and $0.5, respectively
| | 178.7 |
| | 151.9 |
|
| Inventories of VIEs | | 385.2 |
| | 349.2 |
|
Prepaid expenses and other current assets (including $30.0 and $65.0, respectively, of VIEs)
| | 33.7 |
| | 68.4 |
|
Income tax receivable (including $0.0 and $0.2, respectively, of VIEs)
| | 9.7 |
| | 10.2 |
|
| Due from parent | 11.6 |
| | 44.5 |
| 5.1 |
| | — |
|
| Total current assets | 1,274.7 |
| | 1,456.6 |
| 1,094.2 |
| | 1,315.5 |
|
| Property, plant, and equipment, net of accumulated depreciation | 1,967.1 |
| | 1,916.0 |
| |
| Intangible assets, net | 0.2 |
| | 0.2 |
| |
| Goodwill | 41.0 |
| | 41.0 |
| |
| Deferred financing costs, net | 6.2 |
| | 8.4 |
| |
| Other long-term assets | 16.6 |
| | 40.3 |
| |
Property, plant and equipment, net of accumulated depreciation (including $2,548.3 and $2,645.1, respectively, of VIEs)
| | 2,571.8 |
| | 2,672.1 |
|
Intangible assets of VIEs, net
| | 0.2 |
| | 0.2 |
|
Goodwill of VIEs
| | 41.0 |
| | 41.0 |
|
| Equity method investments in affiliates of VIEs | | 82.8 |
| | 5.6 |
|
Other long-term assets (including $13.3 and $19.1, respectively, of VIEs)
| | 16.7 |
| | 15.8 |
|
| Total assets | $ | 3,305.8 |
| | $ | 3,462.5 |
| $ | 3,806.7 |
| | $ | 4,050.2 |
|
LIABILITIES AND EQUITY | | Current liabilities: | | | | | | |
| Note payable and capital lease obligations | $ | 1.6 |
| | $ | 1.4 |
| |
| Current portion of long-term debt | 125.0 |
| | — |
| |
| Accounts payable | 261.5 |
| | 275.0 |
| |
| Personnel accruals | 45.7 |
| | 38.3 |
| |
| Accrued taxes other than income taxes | 23.5 |
| | 26.7 |
| |
| Deferred revenue | 3.1 |
| | 13.6 |
| |
| Other current liabilities | 24.4 |
| | 68.6 |
| |
Note payable and capital lease obligations of VIEs
| | $ | 2.1 |
| | $ | 1.8 |
|
Accounts payable (including $329.0 and $247.7, respectively, of VIEs)
| | 333.9 |
| | 251.0 |
|
Personnel accruals (including $29.9 and $23.6, respectively, of VIEs)
| | 55.9 |
| | 45.7 |
|
Accrued taxes other than income taxes of VIEs
| | 26.5 |
| | 27.0 |
|
| Deferred revenue of VIEs | | 12.9 |
| | 12.6 |
|
| Due to parent | | — |
| | 10.6 |
|
Other current liabilities (including $111.8 and $216.8, respectively, of VIEs)
| | 112.4 |
| | 217.2 |
|
| Total current liabilities | 484.8 |
| | 423.6 |
| 543.7 |
| | 565.9 |
|
| Long-term liabilities: | | | | | | |
| Long-term debt and capital lease obligations, net of current portion | 546.9 |
| | 673.5 |
| |
| Deferred income taxes | 639.7 |
| | 638.3 |
| |
| Other long-term liabilities | 33.9 |
| | 51.8 |
| |
Long-term debt and capital lease obligations of VIEs, net of current portion
| | 1,164.4 |
| | 1,162.8 |
|
| Deferred income taxes (including $1.0 and $0.8, respectively, of VIEs) | | 385.9 |
| | 579.9 |
|
| Other long-term liabilities (including $3.7 and $5.4, respectively, of VIEs) | | 8.7 |
| | 32.0 |
|
| Total long-term liabilities | 1,220.5 |
| | 1,363.6 |
| 1,559.0 |
| | 1,774.7 |
|
| Commitments and contingencies |
| |
|
| |
|
| Equity: | | | | | | |
| CVR stockholders' equity: | | | | | | |
| Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 shares issued | 0.9 |
| | 0.9 |
| 0.9 |
| | 0.9 |
|
| Additional paid-in-capital | 1,174.7 |
| | 1,174.7 |
| 1,197.6 |
| | 1,197.6 |
|
| Retained deficit | (189.2 | ) | | (184.9 | ) | (277.4 | ) | | (338.1 | ) |
| Treasury stock, 98,610 shares at cost | (2.3 | ) | | (2.3 | ) | (2.3 | ) | | (2.3 | ) |
| Accumulated other comprehensive loss, net of tax | — |
| | (0.3 | ) | — |
| | — |
|
| Total CVR stockholders' equity | 984.1 |
| | 988.1 |
| 918.8 |
| | 858.1 |
|
| Noncontrolling interest | 616.4 |
| | 687.2 |
| 785.2 |
| | 851.5 |
|
| Total equity | 1,600.5 |
| | 1,675.3 |
| 1,704.0 |
| | 1,709.6 |
|
| Total liabilities and equity | $ | 3,305.8 |
| | $ | 3,462.5 |
| $ | 3,806.7 |
| | $ | 4,050.2 |
|
See accompanying notes to consolidated financial statements.
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Net sales | $ | 5,432.5 |
| | $ | 9,109.5 |
| | $ | 8,985.8 |
| $ | 5,988.4 |
| | $ | 4,782.4 |
| | $ | 5,432.5 |
|
| Operating costs and expenses: | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | 4,190.4 |
| | 8,066.0 |
| | 7,563.2 |
| |
| Direct operating expenses (exclusive of depreciation and amortization) | 584.7 |
| | 515.1 |
| | 455.8 |
| |
| Cost of materials and other | | 4,882.9 |
| | 3,847.5 |
| | 4,190.4 |
|
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | | 599.5 |
| | 541.8 |
| | 584.7 |
|
| Depreciation and amortization | | 203.3 |
| | 184.5 |
| | 156.4 |
|
| Cost of sales | | 5,685.7 |
| | 4,573.8 |
| | 4,931.5 |
|
| Flood insurance recovery | (27.3 | ) | | — |
| | — |
| — |
| | — |
| | (27.3 | ) |
| Selling, general and administrative expenses (exclusive of depreciation and amortization) | 99.0 |
| | 109.7 |
| | 113.5 |
| |
| Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below) | | 114.2 |
| | 109.1 |
| | 99.0 |
|
| Depreciation and amortization | 164.1 |
| | 154.4 |
| | 142.8 |
| 10.7 |
| | 8.6 |
| | 7.7 |
|
| Total operating costs and expenses | 5,010.9 |
| | 8,845.2 |
| | 8,275.3 |
| 5,810.6 |
| | 4,691.5 |
| | 5,010.9 |
|
| Operating income | 421.6 |
| | 264.3 |
| | 710.5 |
| 177.8 |
| | 90.9 |
| | 421.6 |
|
| Other income (expense): | | | | | | | | | | |
| Interest expense and other financing costs | (48.4 | ) | | (40.0 | ) | | (50.5 | ) | (110.1 | ) | | (83.9 | ) | | (48.4 | ) |
| Interest income | 1.0 |
| | 0.9 |
| | 1.2 |
| 1.1 |
| | 0.7 |
| | 1.0 |
|
| Gain (loss) on derivatives, net | (28.6 | ) | | 185.6 |
| | 57.1 |
| |
| Loss on derivatives, net | | (69.8 | ) | | (19.4 | ) | | (28.6 | ) |
| Loss on extinguishment of debt | — |
| | — |
| | (26.1 | ) | — |
| | (4.9 | ) | | — |
|
| Other income (expense), net | 36.7 |
| | (3.7 | ) | | 13.5 |
| |
| Total other income (expense) | (39.3 | ) | | 142.8 |
| | (4.8 | ) | |
| Income before income taxes | 382.3 |
| | 407.1 |
| | 705.7 |
| |
| Income tax expense | 84.5 |
| | 97.7 |
| | 183.7 |
| |
| Other income, net | | 1.0 |
| | 5.7 |
| | 36.7 |
|
| Total other expense | | (177.8 | ) | | (101.8 | ) | | (39.3 | ) |
| Income (loss) before income taxes | | 0.0 |
| | (10.9 | ) | | 382.3 |
|
| Income tax expense (benefit) | | (216.9 | ) | | (19.8 | ) | | 84.5 |
|
| Net income | 297.8 |
| | 309.4 |
| | 522.0 |
| 216.9 |
| | 8.9 |
| | 297.8 |
|
| Less: Net income attributable to noncontrolling interest | 128.2 |
| | 135.5 |
| | 151.3 |
| |
| Less: Net income (loss) attributable to noncontrolling interest | | (17.5 | ) | | (15.8 | ) | | 128.2 |
|
| Net income attributable to CVR Energy stockholders | $ | 169.6 |
| | $ | 173.9 |
| | $ | 370.7 |
| $ | 234.4 |
| | $ | 24.7 |
| | $ | 169.6 |
|
| | | | | | | | | | | |
| Basic earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
| |
| Diluted earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
| |
| Basic and diluted earnings per share | | $ | 2.70 |
| | $ | 0.28 |
| | $ | 1.95 |
|
| Dividends declared per share | $ | 2.00 |
| | $ | 5.00 |
| | $ | 14.25 |
| $ | 2.00 |
| | $ | 2.00 |
| | $ | 2.00 |
|
| | | | | | | | | | | |
| Weighted-average common shares outstanding: | | | | | | | | | | |
| Basic | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Basic and Diluted | | 86.8 |
| | 86.8 |
| | 86.8 |
|
See accompanying notes to consolidated financial statements.
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 |
| | (in millions) |
| Net income | $ | 297.8 |
| | $ | 309.4 |
| | $ | 522.0 |
|
| Other comprehensive income (loss): | | | | | |
| Unrealized gain on available-for-sale securities, net of tax of $12.6, $0 and $2.4, respectively | 19.2 |
| | — |
| | 3.7 |
|
| Net 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 to trading 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 |
| | 0.8 |
|
| Total other comprehensive income | 0.7 |
| | 0.7 |
| | 0.6 |
|
| Comprehensive income | 298.5 |
| | 310.1 |
| | 522.6 |
|
| Less: Comprehensive income attributable to noncontrolling interest | 128.6 |
| | 135.9 |
| | 151.5 |
|
| Comprehensive income attributable to CVR Energy stockholders | $ | 169.9 |
| | $ | 174.2 |
| | $ | 371.1 |
|
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions) |
| Net income | $ | 216.9 |
| | $ | 8.9 |
| | $ | 297.8 |
|
| Other comprehensive income (loss): | | | | | |
| Unrealized gain on available-for-sale securities, net of tax of $0.0, $0.2 and $12.6, respectively | — |
| | 0.3 |
| | 19.2 |
|
| Net gain reclassified into income on sale of available-for-sale-securities, net of tax of $0.0, $(0.2), and $(8.0), respectively (Note 15) | — |
| | (0.3 | ) | | (12.1 | ) |
| Net gain reclassified into income on reclassification of available-for-sale securities to trading securities, net of tax of $0.0, $0.0, and $(4.6), respectively (Note 15) | — |
| | — |
| | (7.1 | ) |
| Change in fair value of interest rate swaps, net of tax of $0.0, $0.0 and $0.0, respectively | — |
| | — |
| | (0.1 | ) |
| Net loss reclassified into income on settlement of interest rate swaps, net of tax of $0.0, $0.0, and $0.2, respectively (Note 16) | — |
| | — |
| | 0.8 |
|
| Total other comprehensive income | — |
| | — |
| | 0.7 |
|
| Comprehensive income | 216.9 |
| | 8.9 |
| | 298.5 |
|
| Less: Comprehensive income (loss) attributable to noncontrolling interest | (17.5 | ) | | (15.8 | ) | | 128.6 |
|
| Comprehensive income attributable to CVR Energy stockholders | $ | 234.4 |
| | $ | 24.7 |
| | $ | 169.9 |
|
See accompanying notes to consolidated financial statements.
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
| | | | Common Stockholders | | | | | Common Stockholders | | | | |
| | Shares Issued | | $0.01 Par Value Common Stock | | Additional Paid-In Capital | | Retained Earnings (Deficit) | | Treasury Stock | | Accumulated Other Comprehensive Income (Loss) | | Total CVR Stockholders' Equity | | Noncontrolling Interest | | Total Equity | Shares Issued | | $0.01 Par Value Common Stock | | Additional Paid-In Capital | | Retained Earnings (Deficit) | | Treasury Stock | | Accumulated Other Comprehensive Income (Loss) | | Total CVR Stockholders' Equity | | Noncontrolling Interest | | Total Equity |
| | (in millions, except share data) | (in millions, except share data) |
| Balance at December 31, 2012 | 86,929,660 |
| | $ | 0.9 |
| | $ | 582.3 |
| | $ | 945.4 |
| | $ | (2.3 | ) | | $ | (1.2 | ) | | $ | 1,525.1 |
| | $ | 135.0 |
| | $ | 1,660.1 |
| |
| January issuance of CVR Refining's common units to the public, net of $148.0 tax impact | — |
| | — |
| | 229.3 |
| | — |
| | — |
| | — |
| | 229.3 |
| | 276.4 |
| | 505.7 |
| |
| May issuance of CVR Refining's common units to the public, net of $96.0 tax impact | — |
| | — |
| | 148.9 |
| | — |
| | — |
| | — |
| | 148.9 |
| | 148.7 |
| | 297.6 |
| |
| Sale of CVR Refining's common units to affiliate, net of $15.2 tax impact | — |
| | — |
| | 23.6 |
| | — |
| | — |
| | — |
| | 23.6 |
| | 22.7 |
| | 46.3 |
| |
| Secondary offering of CVR Partners' common units to public, net of $88.5 tax impact | — |
| | — |
| | 129.7 |
| | — |
| | — |
| | 0.2 |
| | 129.9 |
| | 74.1 |
| | 204.0 |
| |
| Dividends paid to CVR Energy stockholders | — |
| | — |
| | — |
| | (1,237.3 | ) | | — |
| | — |
| | (1,237.3 | ) | | — |
| | (1,237.3 | ) | |
| Distributions from CVR Partners to public unitholders | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (50.0 | ) | | (50.0 | ) | |
| Distributions from CVR Refining to public unitholders | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (114.2 | ) | | (114.2 | ) | |
| Share-based compensation | — |
| | — |
| | 1.0 |
| | (2.6 | ) | | — |
| | — |
| | (1.6 | ) | | 2.8 |
| | 1.2 |
| |
| Excess 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 |
| | 522.0 |
| |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | 0.4 |
| | 0.4 |
| | 0.2 |
| | 0.6 |
| |
| Balance at December 31, 2013 | 86,929,660 |
| | $ | 0.9 |
| | $ | 1,114.4 |
| | $ | 76.2 |
| | $ | (2.3 | ) | | $ | (0.6 | ) | | $ | 1,188.6 |
| | $ | 646.8 |
| | $ | 1,835.4 |
| |
| June issuance of CVR Refining's common units to the public, net of $39.4 tax impact | — |
| | — |
| | 60.3 |
| | — |
| | — |
| | — |
| | 60.3 |
| | 88.6 |
| | 148.9 |
| |
| Dividends paid to CVR Energy stockholders | — |
| | — |
| | — |
| | (434.2 | ) | | — |
| | — |
| | (434.2 | ) | | — |
| | (434.2 | ) | |
| Distributions from CVR Partners to public unitholders | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (48.2 | ) | | (48.2 | ) | |
| Distributions from CVR Refining to public unitholders | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (136.7 | ) | | (136.7 | ) | |
| Share-based compensation | — |
| | — |
| | 0.1 |
| | (0.8 | ) | | — |
| | — |
| | (0.7 | ) | | 0.8 |
| | 0.1 |
| |
| Excess tax deficiency from share-based compensation | — |
| | — |
| | (0.1 | ) | | — |
| | — |
| | — |
| | (0.1 | ) | | — |
| | (0.1 | ) | |
| Net income | — |
| | — |
| | — |
| | 173.9 |
| | — |
| | — |
| | 173.9 |
| | 135.5 |
| | 309.4 |
| |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | 0.3 |
| | 0.3 |
| | 0.4 |
| | 0.7 |
| |
| Balance at December 31, 2014 | 86,929,660 |
| | $ | 0.9 |
| | $ | 1,174.7 |
| | $ | (184.9 | ) | | $ | (2.3 | ) | | $ | (0.3 | ) | | $ | 988.1 |
| | $ | 687.2 |
| | $ | 1,675.3 |
| 86,929,660 |
| | $ | 0.9 |
| | $ | 1,174.7 |
| | $ | (184.9 | ) | | $ | (2.3 | ) | | $ | (0.3 | ) | | $ | 988.1 |
| | $ | 687.2 |
| | $ | 1,675.3 |
|
| Dividends paid to CVR Energy stockholders | — |
| | — |
| | — |
| | (173.7 | ) | | — |
| | — |
| | (173.7 | ) | | — |
| | (173.7 | ) | — |
| | — |
| | — |
| | (173.7 | ) | | — |
| | — |
| | (173.7 | ) | | — |
| | (173.7 | ) |
| Distributions from CVR Partners to public unitholders | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (42.8 | ) | | (42.8 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (42.8 | ) | | (42.8 | ) |
| Distributions from CVR Refining to public unitholders | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (156.9 | ) | | (156.9 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (156.9 | ) | | (156.9 | ) |
| Share-based compensation | — |
| | — |
| | 0.1 |
| | (0.2 | ) | | — |
| | — |
| | (0.1 | ) | | 0.3 |
| | 0.2 |
| — |
| | — |
| | 0.1 |
| | (0.2 | ) | | — |
| | — |
| | (0.1 | ) | | 0.3 |
| | 0.2 |
|
| Excess tax deficiency from share-based compensation | — |
| | — |
| | (0.1 | ) | | — |
| | — |
| | — |
| | (0.1 | ) | | — |
| | (0.1 | ) | — |
| | — |
| | (0.1 | ) | | — |
| | — |
| | — |
| | (0.1 | ) | | — |
| | (0.1 | ) |
| Net income | — |
| | — |
| | — |
| | 169.6 |
| | — |
| | — |
| | 169.6 |
| | 128.2 |
| | 297.8 |
| — |
| | — |
| | — |
| | 169.6 |
| | — |
| | — |
| | 169.6 |
| | 128.2 |
| | 297.8 |
|
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | 0.3 |
| | 0.3 |
| | 0.4 |
| | 0.7 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 0.3 |
| | 0.3 |
| | 0.4 |
| | 0.7 |
|
| Balance at December 31, 2015 | 86,929,660 |
| | $ | 0.9 |
| | $ | 1,174.7 |
| | $ | (189.2 | ) | | $ | (2.3 | ) | | $ | — |
| | $ | 984.1 |
| | $ | 616.4 |
| | $ | 1,600.5 |
| 86,929,660 |
| | 0.9 |
| | 1,174.7 |
| | (189.2 | ) | | (2.3 | ) | | — |
| | 984.1 |
| | 616.4 |
| | 1,600.5 |
|
| Dividends paid to CVR Energy stockholders | | — |
| | — |
| | — |
| | (173.6 | ) | | — |
| | — |
| | (173.6 | ) | | — |
| | (173.6 | ) |
| Distributions from CVR Partners to public unitholders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (41.9 | ) | | (41.9 | ) |
Impact of CVR Partners' common units issuance for the East Dubuque Merger, net of tax of $20.0
| | — |
| | — |
| | 22.9 |
| | — |
| | — |
| | — |
| | 22.9 |
| | 292.8 |
| | 315.7 |
|
| Net income (loss) | | — |
| | — |
| | — |
| | 24.7 |
| | — |
| | — |
| | 24.7 |
| | (15.8 | ) | | 8.9 |
|
| Balance at December 31, 2016 | | 86,929,660 |
| | 0.9 |
| | 1,197.6 |
| | (338.1 | ) | | (2.3 | ) | | — |
| | 858.1 |
| | 851.5 |
| | 1,709.6 |
|
| Dividends paid to CVR Energy stockholders | | — |
| | — |
| | — |
| | (173.7 | ) | | — |
| | — |
| | (173.7 | ) | | — |
| | (173.7 | ) |
| Distributions from CVR Partners to public unitholders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1.5 | ) | | (1.5 | ) |
| Distributions from CVR Refining to public unitholders | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (47.3 | ) | | (47.3 | ) |
| Net income (loss) | | — |
| | — |
| | — |
| | 234.4 |
| | — |
| | — |
| | 234.4 |
| | (17.5 | ) | | 216.9 |
|
| Balance at December 31, 2017 | | 86,929,660 |
| | $ | 0.9 |
| | $ | 1,197.6 |
| | $ | (277.4 | ) | | $ | (2.3 | ) | | $ | — |
| | $ | 918.8 |
| | $ | 785.2 |
| | $ | 1,704.0 |
|
See accompanying notes to consolidated financial statements.
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Cash flows from operating activities: | | | | | | | | | | |
| Net income | $ | 297.8 |
| | $ | 309.4 |
| | $ | 522.0 |
| $ | 216.9 |
| | $ | 8.9 |
| | $ | 297.8 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | | | |
| Depreciation and amortization | 164.1 |
| | 154.4 |
| | 142.8 |
| 214.0 |
| | 193.1 |
| | 164.1 |
|
| Allowance for doubtful accounts | (0.1 | ) | | (0.5 | ) | | (1.1 | ) | 0.6 |
| | 0.2 |
| | (0.1 | ) |
| Amortization of deferred financing costs | 2.8 |
| | 2.8 |
| | 2.9 |
| |
| Amortization of deferred financing costs and original issue discount | | 4.8 |
| | 3.6 |
| | 2.8 |
|
| Amortization of debt fair value adjustment | | — |
| | 1.2 |
| | — |
|
| Deferred income taxes | (10.4 | ) | | 19.2 |
| | (93.3 | ) | (216.5 | ) | | (84.4 | ) | | (10.4 | ) |
| Excess income tax deficiency of share-based compensation | 0.1 |
| | 0.1 |
| | 0.1 |
| — |
| | — |
| | 0.1 |
|
| Loss on disposition of assets | 1.8 |
| | 0.4 |
| | 0.1 |
| 2.4 |
| | 0.5 |
| | 1.8 |
|
| Loss on extinguishment of debt | — |
| | — |
| | 26.1 |
| — |
| | 4.9 |
| | — |
|
| Share-based compensation | 12.8 |
| | 12.3 |
| | 18.4 |
| 18.8 |
| | 9.3 |
| | 12.8 |
|
| Gain on sale of available-for-sale securities | (20.1 | ) | | — |
| | (6.1 | ) | — |
| | (4.9 | ) | | (20.1 | ) |
| (Gain) loss on derivatives, net | 28.6 |
| | (185.6 | ) | | (57.1 | ) | |
| Unrealized gain on securities | | — |
| | (0.3 | ) | | — |
|
| Loss on derivatives, net | | 69.8 |
| | 19.4 |
| | 28.6 |
|
| Current period settlements on derivative contracts | (26.0 | ) | | 122.2 |
| | 6.4 |
| (16.6 | ) | | 36.4 |
| | (26.0 | ) |
| Income from equity method investments, net of distributions | | (0.7 | ) | | — |
| | — |
|
| Changes in assets and liabilities: | | | | | | | | | | |
| Accounts receivable | 41.0 |
| | 105.7 |
| | (30.2 | ) | (27.3 | ) | | (47.5 | ) | | 41.0 |
|
| Inventories | 39.7 |
| | 197.3 |
| | 1.5 |
| (37.6 | ) | | (7.3 | ) | | 39.7 |
|
| Prepaid expenses and other current assets | 40.4 |
| | 10.7 |
| | (28.7 | ) | 33.9 |
| | (3.4 | ) | | 40.4 |
|
| Due to (from) parent | 32.8 |
| | (44.6 | ) | | 9.1 |
| (15.7 | ) | | 22.2 |
| | 32.8 |
|
| Other long-term assets | 3.8 |
| | (0.8 | ) | | (0.5 | ) | 1.0 |
| | (0.6 | ) | | 3.8 |
|
| Accounts payable | (14.3 | ) | | (91.8 | ) | | (38.7 | ) | 88.1 |
| | (10.4 | ) | | (14.3 | ) |
| Accrued income taxes | 4.2 |
| | (0.3 | ) | | (6.6 | ) | 0.6 |
| | (3.3 | ) | | 4.2 |
|
| Deferred revenue | (10.5 | ) | | 12.9 |
| | (0.3 | ) | 0.9 |
| | (20.4 | ) | | (10.5 | ) |
| Other current liabilities | (52.1 | ) | | 15.0 |
| | (26.7 | ) | (168.0 | ) | | 151.2 |
| | (52.1 | ) |
| Other long-term liabilities | 0.4 |
| | 1.5 |
| | — |
| (2.5 | ) | | (0.9 | ) | | 0.4 |
|
| Net cash provided by operating activities | 536.8 |
| | 640.3 |
| | 440.1 |
| 166.9 |
| | 267.5 |
| | 536.8 |
|
| Cash flows from investing activities: | | | | | | | | | | |
| Capital expenditures | (218.7 | ) | | (218.4 | ) | | (256.5 | ) | (118.6 | ) | | (132.7 | ) | | (218.7 | ) |
| Proceeds from sale of assets | 0.1 |
| | 0.1 |
| | 0.1 |
| 0.1 |
| | — |
| | 0.1 |
|
Acquisition of CVR Nitrogen, net of cash acquired
| | — |
| | (63.8 | ) | | — |
|
Purchase of securities
| | — |
| | (4.2 | ) | | — |
|
Investment in affiliates, net of return of investment
| | (76.5 | ) | | (5.6 | ) | | — |
|
| Purchase of available-for-sale securities | — |
| | (78.3 | ) | | (18.6 | ) | — |
| | (14.4 | ) | | — |
|
| Proceeds from sale of available-for-sale securities | 68.0 |
| | — |
| | 24.7 |
| — |
| | 19.3 |
| | 68.0 |
|
| Net cash used in investing activities | (150.6 | ) | | (296.6 | ) | | (250.3 | ) | (195.0 | ) | | (201.4 | ) | | (150.6 | ) |
| Cash flows from financing activities: | | | | | | | | | | |
| Principal payments on senior secured notes | — |
| | — |
| | (243.4 | ) | |
Proceeds on issuance of 2023 Notes, net of original issue discount
| | — |
| | 628.8 |
| | — |
|
| Principal and premium payments on 2021 Notes | | — |
| | (322.2 | ) | | — |
|
| Payments of revolving debt | | — |
| | (49.1 | ) | | — |
|
Principal payments on CRNF credit facility
| | — |
| | (125.0 | ) | | — |
|
| Payment of capital lease obligations | (1.3 | ) | | (1.2 | ) | | (1.2 | ) | (1.8 | ) | | (1.7 | ) | | (1.3 | ) |
| Payment of deferred financing costs | — |
| | — |
| | (0.4 | ) | (1.6 | ) | | (10.7 | ) | | — |
|
| Proceeds from CVR Refining's initial public offering, net of offering costs | — |
| | — |
| | 655.7 |
| |
| Proceeds from CVR Refining's May 2013 offering, net of offering costs | — |
| | — |
| | 393.6 |
| |
| Proceeds from the sale of CVR Refining's common units to affiliate | — |
| | — |
| | 61.5 |
| |
| Proceeds from CVR Refining's June 2014 offering, net of offering costs | — |
| | 188.3 |
| | — |
| |
| Proceeds from CVR Partners' secondary offering, net of offering costs | — |
| | — |
| | 292.6 |
| |
| Dividends to CVR Energy's stockholders | (173.7 | ) | | (434.2 | ) | | (1,237.3 | ) | (173.7 | ) | | (173.6 | ) | | (173.7 | ) |
| Distributions to CVR Refining's noncontrolling interest holders | (156.9 | ) | | (136.7 | ) | | (114.2 | ) | $ | (47.3 | ) | | $ | — |
| | $ | (156.9 | ) |
| Distributions to CVR Partners' noncontrolling interest holders | (42.8 | ) | | (48.2 | ) | | (50.0 | ) | $ | (1.5 | ) | | $ | (41.9 | ) | | $ | (42.8 | ) |
| Excess income tax deficiency of share-based compensation | (0.1 | ) | | (0.1 | ) | | (0.1 | ) | — |
| | — |
| | (0.1 | ) |
| Redemption of common units | — |
| | — |
| | (0.5 | ) | |
| Net cash used in financing activities | (374.8 | ) | | (432.1 | ) | | (243.7 | ) | (225.9 | ) | | (95.4 | ) | | (374.8 | ) |
| Net increase (decrease) in cash and cash equivalents | 11.4 |
| | (88.4 | ) | | (53.9 | ) | (254.0 | ) | | (29.3 | ) | | 11.4 |
|
| Cash and cash equivalents, beginning of period | 753.7 |
| | 842.1 |
| | 896.0 |
| 735.8 |
| | 765.1 |
| | 753.7 |
|
| Cash and cash equivalents, end of period | $ | 765.1 |
| | $ | 753.7 |
| | $ | 842.1 |
| $ | 481.8 |
| | $ | 735.8 |
| | $ | 765.1 |
|
| Supplemental disclosures: | | | | | | | | | | |
| Cash paid for income taxes, net of refunds (received) | $ | 57.9 |
| | $ | 123.5 |
| | $ | 274.5 |
| |
| Cash paid for interest net of capitalized interest of $3.7, $9.4 and $3.6 for the years ended December 31, 2015, 2014 and 2013, respectively | $ | 45.4 |
| | $ | 37.2 |
| | $ | 54.9 |
| |
| Cash paid for income taxes, net of refunds | | $ | 14.9 |
| | $ | 45.5 |
| | $ | 57.9 |
|
| Cash paid for interest net of capitalized interest of $1.1, $5.4, and $3.7 for the years ended December 31, 2017, 2016 and 2015, respectively | | $ | 105.0 |
| | $ | 76.8 |
| | $ | 45.4 |
|
| Non-cash investing and financing activities: | | | | | | | | | | |
| Construction in progress additions included in accounts payable | $ | 22.3 |
| | $ | 21.6 |
| | $ | 32.8 |
| $ | 8.2 |
| | $ | 15.8 |
| | $ | 22.3 |
|
| Change in accounts payable related to construction in progress additions | $ | 0.7 |
| | $ | (11.2 | ) | | $ | (23.4 | ) | $ | (5.2 | ) | | $ | 6.0 |
| | $ | 0.7 |
|
| Landlord incentives for leasehold improvements | | $ | 1.2 |
| | $ | — |
| | $ | — |
|
Fair value of common units issued in a business combination
| | $ | — |
| | $ | 335.7 |
| | $ | — |
|
Fair value of debt assumed in a business combination
| | $ | — |
| | $ | 367.5 |
| | $ | — |
|
Reduction of proceeds from 2023 Notes from underwriting discount
| | $ | — |
| | $ | 16.1 |
| | $ | — |
|
See accompanying notes to consolidated financial statements.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and HistoryNature of the CompanyBusiness
Organization
The "Company," "CVR Energy," or "CVR" may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references 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 holdings in CVR Refining, LP ("CVR Refining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces and markets nitrogen fertilizers in the form of UAN and ammonia. The Company's operations include two business segments: the petroleum segment and the nitrogen 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 which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC.
CVR's common stock is listed on the NYSENew York Stock Exchange ("NYSE") under the symbol "CVI."
As of December 31, 2010, approximately 40% of its outstanding shares were beneficially owned by GS Capital Partners V, L.P. and related entities ("GS" or "Goldman Sachs Funds") and Kelso Investment Associates VII, L.P. and related entities ("Kelso" or "Kelso Funds"). On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interests in CVR and Kelso substantially reduced its interest in the Company. On May 26, 2011, Kelso completed a registered public offering, 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-owned storage tanks.
On April 18, 2012, an affiliate of2017, Icahn Enterprises L.P. ("IEP") entered into a Transaction Agreement (the "Transaction Agreement") with CVR, with respect 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 it had 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 its affiliates owned approximately 82% of the Company's outstanding shares. Prior to the IEP Acquisition, the Company was owned 100% by the public.
CVR Partners, LP
In 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 general partner interest ("managing GP interest"), a special general partner interest ("special GP interest," represented by special GP units) and a de minimis limited partner interest ("LP interest," represented by special LP units). CVR concurrently sold the managing GP interest, including the associated incentive distribution 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 Fertilizer Partnership 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." In connection with
On April 1, 2016, the Nitrogen Fertilizer Partnership IPO,completed the IDRs were purchased bymerger (the "East Dubuque Merger") with CVR Nitrogen, LP (“CVR Nitrogen”) (formerly known as East Dubuque Nitrogen Partners, L.P. and also formerly known as Rentech Nitrogen Partners L.P.) and CVR Nitrogen GP, LLC ("CVR Nitrogen GP") (formerly known as East Dubuque Nitrogen GP, LLC and also formerly known as Rentech Nitrogen GP, LLC), whereby the Nitrogen Fertilizer Partnership and subsequently extinguished. In addition, the noncontrolling interest representing the managing GP interest was purchased by Coffeyville Resources, LLCacquired a nitrogen fertilizer manufacturing facility located in East Dubuque, Illinois (the "East Dubuque Facility"). See Note 3 ("CRLLC"Acquisition"), 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 Sachs
CVR Energy, Inc. and Subsidiaries
NOTES 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, the Company recorded a noncontrolling interest for the common units sold into the public market which represented approximately a 30% interest in the Nitrogen Fertilizer Partnership..
In connection with the Nitrogen Fertilizer Partnership IPO, the Nitrogen Fertilizer Partnership's limited partner interests were converted into common units, the Nitrogen Fertilizer Partnership's special general partner interests were converted into common units, and the Nitrogen Fertilizer Partnership's special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, as discussed above, the managing general partner sold its IDRs to the Nitrogen Fertilizer Partnership. These interests were extinguished, and CALLC III sold the managing general partner to CRLLC for a nominal amount. As a result of the Nitrogen Fertilizer Partnership IPO,Partnership's acquisition of CVR Nitrogen, LP and issuance of the unit consideration, the noncontrolling interest related to the Nitrogen Fertilizer Partnership has two types of partnership interests outstanding:
common units representing limited partner interests;reflected in our Consolidated Financial Statements on April 1, 2016 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 Partnership common 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, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5 million in offering costs during the year ended December 31, 2013.
Immediately subsequent to the closing of the Secondary Offeringsuch date and as of December 31, 2015, public security holders held2017 was approximately 47% of the total Nitrogen Fertilizer Partnership common units, and CRLLC held approximately 53% of the total Nitrogen Fertilizer Partnership common units.66%. 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. The noncontrolling interest reflected on the Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Nitrogen Fertilizer Partnership. Immediately subsequent to the completion of the pending mergers, which are discussed in the "CVR Partners, LP - Pending Mergers" section below, it is estimated that CRLLC will hold approximately 34% of the Nitrogen Fertilizer Partnership's common units and 100% of the Nitrogen 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 it generates each quarter. The available cash for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership's general partner following the end of such quarter. The partnership agreement does not require that the Nitrogen Fertilizer Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Nitrogen Fertilizer Partnership can change the Nitrogen Fertilizer Partnership's distribution 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 services agreement 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. The operations 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 its individual 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 general partner 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-day affairs of the business of the Nitrogen Fertilizer Partnership. CVR, the Nitrogen Fertilizer Partnership, their respective subsidiaries and the general partner are parties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with the Nitrogen Fertilizer Partnership IPO.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CVR Partners, LP - Pending Mergers
On August 9, 2015, CVR Partners, including its two newly-created direct wholly-owned subsidiaries Lux Merger Sub 1 LLC ("Merger Sub 1") and Lux Merger Sub 2 LLC ("Merger Sub 2"), entered into an Agreement and Plan of Merger (the "Merger Agreement") with Rentech Nitrogen Partners, L.P., a publicly traded partnership whose common units are listed on the New York Stock Exchange under the ticker symbol "RNF" ("Rentech Nitrogen"), and Rentech Nitrogen GP, LLC ("Rentech Nitrogen GP"), pursuant to which CVR Partners will acquire Rentech Nitrogen and Rentech Nitrogen GP. The Merger Agreement 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 and into 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 Nitrogen common units") eligible to receive consideration will receive 1.04 common units (the "unit consideration") representing limited partner interests in CVR Partners ("CVR Partners common units") and $2.57 in cash, without interest, (the "cash consideration" and together with the unit consideration, the "merger consideration") for each Rentech Nitrogen common unit. Phantom units granted and outstanding under Rentech Nitrogen's equity plans and held by an employee who will continue in the employment of a CVR Partners-affiliated entity upon closing of the mergers will be canceled and replaced with new incentive awards of substantially equivalent value and on similar terms. Each phantom unit granted and outstanding and held by (i) an employee who will not 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 be entitled to receive the merger consideration. The unit consideration is fixed, and the number of units included in the merger consideration will not be adjusted to reflect changes in the price of Rentech Nitrogen common units or CVR Partners common units. CVR Partners is expected to issue approximately 40.7 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 using natural gas as the facility's primary feedstock. The facility located in Pasadena, Texas (the "Pasadena facility") produces ammonium sulfate, ammonium thiosulfate and sulfuric acid, using ammonia and sulfur as the facility's primary feedstocks. Rentech Nitrogen is required to sell or spin off its Pasadena facility as a condition to closing of the mergers (unless waived), and Rentech Nitrogen common unitholders may receive additional consideration for the Pasadena 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 holders of 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 of the 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 Nitrogen of Rentech Nitrogen's Pasadena facility on terms specified in the Merger Agreement, (v) the absence of certain events of default under the indenture governing Rentech Nitrogen's 6.5% Second Lien Senior Secured Notes due 2021 and (vi) other customary conditions. On February 15, 2016, the Merger Agreement was adopted by holders of a majority of the outstanding Rentech Nitrogen common units. On January 14, 2016, CVR Partners registration statement on Form S-4 with the Securities and Exchange Commission ("SEC") to register the CVR Partners common units issuable as part of the merger consideration was declared effective.
The Merger Agreement includes customary restrictions on the conduct of the Nitrogen Fertilizer Partnership's business prior to the completion of the mergers, generally requiring the Nitrogen Fertilizer Partnership to conduct its business in the ordinary course 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 declare distributions in excess of available cash for distribution in 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 the Merger Agreement, under certain circumstances, either party may be required to make an expense reimbursement payment of $10.0 million, and Rentech Nitrogen may be required to pay CVR Partners a termination fee equal to $31.2 million.
CVR Energy, Inc. and Subsidiaries
NOTES 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 Partners term 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 Rentech Nitrogen's existing $50.0 million credit facility with General Electric Capital Corporation, the cash consideration payable by the Nitrogen Fertilizer Partnership upon closing of the mergers and expenses associated with the 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 the actual number of days elapsed over a 360-day year. Such term loan, if drawn, would have a one-year term.
See Note 13 ("Commitments and Contingencies") for discussion of litigation related to the pending mergers.
CVR Refining, LP
In contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC ("CVR Refining Holdings"), which in turn 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"), to Refining 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 by an 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 $25.00 per 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, 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.
Upon consummation of the Refining Partnership IPO, CVR indirectly owned the Refining Partnership's general partner and limited partnership interests in 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 and offering 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 quarter of 2012;
approximately $85.1 million was distributed to CRLLC; and
CVR Energy, Inc. and Subsidiaries
NOTES 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 partnership purposes.
In connection with the Refining Partnership IPO and through May 19, 2013, the Company recorded a noncontrolling interest for the common units sold into 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 the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection 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 in this paragraph are collectively referred to as the "Transactions." In connection with the Transactions, the Refining Partnership paid approximately $12.2 million 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 the exercise 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 Refining Partnership 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 Refining Partnership common units (including units owned by affiliates of IEP representing 4% of the total Refining Partnership common units), and CVR Refining Holdings 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 6,500,000 common 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 to redeem 6,500,000 common units from CVR Refining Holdings. Immediately subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of the total Refining Partnership common units, and CVR Refining Holdings held approximately 67% 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 the underwriters' exercise of their option to purchase additional common units. The Refining Partnership utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.
Immediately subsequent to the closing of the underwriters' option for the Second Underwritten Offering and asAs of December 31, 2015,2017, public security holders held approximately 34% of the total Refining Partnership common units (including units owned by affiliates of IEP representing 4%3.9% of the total Refining Partnership common units), and CVR Refining Holdings, LLC ("CVR Refining Holdings") held approximately 66% of the total Refining Partnership common units. In addition, CVR Refining 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 Refining Partnership.
The Refining Partnership's general partner, CVR Refining GP, LLC, manages the Refining Partnership's activities subject to the terms and conditions specified in the Refining Partnership's partnership agreement. The Refining Partnership's general partner is owned by CVR Refining Holdings. The operations of its general partner, in its capacity as general partner, are
CVR Energy, Inc. and Subsidiaries
NOTES 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 sole member 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 the Refining Partnership's general partner are not elected by the Refining Partnership's unitholders and are not subject to re-election on a regular basis. The officers 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 cash for each quarter will be determined by the board of directors of the Refining Partnership's general partner following the end of such quarter. The partnership agreement 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 partner of 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 partner obtain certain management and other services from CVR Energy. In addition, by virtue of the fact that the Refining Partnership is a controlled affiliate of CVR Energy, the Refining Partnership is bound by an omnibus agreement entered into by CVR Energy, CVR Partners and the general partner of CVR Partners, 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 affiliates continue to own at least 50% of the Nitrogen Fertilizer Partnership's outstanding units.
(2) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying CVR consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. The ownership interests of noncontrolling investors in its subsidiaries are recorded as noncontrolling interests.
The Nitrogen Fertilizer PartnershipFinancial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2015-02, "Consolidations (Topic 810) - Amendments to the Consolidation Analysis" (“ASU 2015-02”), which amended previous consolidation guidance, including introducing a separate consolidation analysis specific to limited partnerships and other similar entities, became effective for the Company as of January 1, 2016. Under this analysis, limited partnerships and other similar entities are considered a variable interest entity (“VIE”) unless the limited partners hold substantive kick-out rights or participating rights. Management has determined that the Refining Partnership are both consolidated based upon the fact that their general partners are owned by CVR and therefore, CVR has the ability to control their activities. The Nitrogen Fertilizer Partnership's and the Refining Partnership's general partners manage their respective operations and activities subject to the terms and conditions specified in their respective partnership agreements. The operations of each general partner in its capacity as general partner are managed by its board of directors. The limited rights of the common unitholders of the Nitrogen Fertilizer Partnership are VIEs because the limited partners of CVR Refining and CVR Partners lack both substantive kick-out rights and participating rights. As such, management evaluated the qualitative criteria under FASB Accounting Standard Codification ("ASC") Topic 810 - Consolidation in conjunction with ASU 2015-02 to make a determination whether the Refining Partnership are demonstrated byand the factNitrogen Fertilizer Partnership should be consolidated in the Company's financial statements. ASC Topic 810-10 requires the primary beneficiary of a variable interest entity's activities to consolidate the VIE. The primary beneficiary is identified as the enterprise that has a) the common unitholders have nopower to direct the activities of the VIE that most significantly impact the entity's economic performance and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to elect either general partner or either general partner's directors onreceive benefits from the entity that could potentially be significant to the VIE. The standard requires an annual or other continuing basis. Each general partner can only be removed byongoing analysis to determine whether the variable interest gives rise to a vote ofcontrolling financial interest in the holders of at least 66 2/3% of the outstanding 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 partner and 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 the officers of both general partners are also officers of CVR.VIE. Based upon the general partner's rolepartner’s roles and rights as afforded by the partnership agreements and its exposure to losses and benefits of each of the partnerships through its significant limited rights affordedpartner interests, intercompany credit facilities, and services agreements, CVR determined that it is the primary beneficiary of both the Refining Partnership and the Nitrogen Fertilizer Partnership. Based upon that determination, CVR continues to consolidate both the limited partners, theRefining and Nitrogen Fertilizer Partnerships in its consolidated financial statements.
Use of Estimates
The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of CVR will includeAmerica ("GAAP"), using management's best estimates and judgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, cash flows,the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses ofduring the Nitrogen Fertilizer Partnershipreporting period. Actual results could differ materially from these estimates and the Refining Partnership.judgments.
Cash and Cash Equivalents
For purposes of the Consolidated Statements of Cash Flows, CVR considers all highly liquid money market accounts and debt instruments with original maturities of three months or less to be cash equivalents. Under the Company's cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified aswithin accounts payable in the Consolidated Balance Sheets. The change in book overdrafts are reported in the Consolidated Statements of Cash Flows as a component of operating cash flowflows for accounts payable as they do not represent bank overdrafts. The amount of these checks included in accounts payable as of December 31, 20152017 and 20142016 was $24.7$22.8 million and $21.5$18.1 million, respectively.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
Accounts Receivable, net
CVR grants credit to its customers. Credit is extended based on an evaluation of a customer's financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding for longer than their contractual payment terms are considered past due. CVR determines its allowance for doubtful accounts by considering a number of factors, including the length of time trade accounts are past due, the customer's ability to pay its obligations to CVR, and the condition of the general economy and the industry as a whole. CVR writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. Amounts collected on accounts receivable are included in net cash provided by operating activities in the Consolidated Statements of Cash Flows. As of December 31, 2015 and 2014, no customers2017, one customer individually represented greater than 10% of the total net accounts receivable balance. The largest concentration of credit for any one customer at December 31, 20152017 and 20142016 was approximately 9%11% and 8%10%, respectively, of the net accounts receivable balance.
Inventories
Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of the first-in, first-out ("FIFO") cost, or marketnet realizable value for fertilizer products, refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or market.net realizable value. The cost of inventories includes inbound freight costs.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to the Refining Partnership's refineries for which title had not transferred, non-trade accounts receivable, current portions of prepaid insurance, deferred financing costs, derivative agreements and other general current assets.
Property, Plant and Equipment
Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1.0 million in cost which is expected to take more than six months to complete. When assets are placed in service, reasonable useful lives for those assets are estimated. Depreciation is computed using principally the straight-line method over the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:
|
| |
| Asset | Range of Useful Lives, in Years |
| Improvements to land | 15 to 30 |
| Buildings | 20 to 30 |
| Machinery and equipment | 5 to 30 |
| Automotive equipment | 5 to 15 |
| Furniture and fixtures | 3 to 10 |
| Aircraft | 20 |
| Railcars | 25 to 30 |
Leasehold improvements and assets held under capital leases are depreciated or amortized on the straight-line method over the shorter of the contractual lease term or the estimated useful life of the asset. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in the Company's Consolidated Statements of Operations.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. CVR uses November 1 of each year as its annual valuation date for its goodwill impairment test. The Company performed its annual impairment review of goodwill for 2015, 20142017, 2016 and 2013,2015, which is attributable entirely to the nitrogen fertilizer segment and concluded there were no impairments. See Note 68 ("Goodwill") for further discussion.
Deferred Financing Costs
Deferred financing costs associated with debt issuances are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Additionally, any underwriting and original issue discount and premium related to debt issuances are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Deferred financing costs related to the Refining Partnership's Amended and Restated ABL Credit Facility and the Nitrogen Fertilizer Partnership's revolving credit facilityline-of-credit arrangements are amortized to interest expense and other financing costs using the straight-line method through the termination date of the respective facility.
Planned Major Maintenance Costs
The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. Planned major maintenance activities for the nitrogen plant generally occur every two to three years. The required frequency of planned major maintenance activities varies by unit for the refineries, but generally is every four to five years. Costs associated with these turnaround activities were included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
For the years ended December 31, 20152017, 2016 and 2014,2015, the Company's petroleum and nitrogen fertilizer segments incurred the following major scheduled turnaround expenses. No major scheduled turnaround expenses were incurred for the year ended December 31, 2013.
| | | | For the Year Ended December 31, | For the Year Ended December 31, |
| | 2015 | | 2014 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Petroleum segment | | | | | | | | |
| Coffeyville refinery(1) | $ | 102.2 |
| | $ | 5.5 |
| $ | — |
| | $ | 31.5 |
| | $ | 102.2 |
|
| Wynnewood refinery(2) | — |
| | 1.3 |
| 80.4 |
| | — |
| | — |
|
| | | | | | | | | |
| Nitrogen Fertilizer segment | | | | | | | | |
| Nitrogen Fertilizer plant(3) | 7.0 |
| | — |
| |
| Nitrogen Fertilizer plants(3) | | 2.6 |
| | 6.6 |
| | 7.0 |
|
| Total Major Scheduled Turnaround Expenses | $ | 109.2 |
| | $ | 6.8 |
| $ | 83.0 |
| | $ | 38.1 |
| | $ | 109.2 |
|
| |
| (1) | The Coffeyville refinery completed the first phase of its currentmost recent major scheduled turnaround in mid-NovemberNovember 2015. The second phase is scheduled to begin in late February 2016. During the outage atof the Coffeyville refinery as discussed in Note 7 ("Insurance Claims"),turnaround was completed during the Refining Partnership accelerated certain planned turnaround activities scheduled for 2015 and incurred turnaround expenses for the year ended December 31, 2014.first quarter of 2016. |
| |
| (2) | DuringThe Wynnewood refinery completed the fluid catalytic cracking unit ("FCCU") outage atfirst phase of its most recent major scheduled turnaround in November 2017. The second phase of the Wynnewood refinery,turnaround is expected to occur in 2019. In addition to the Refining Partnershiptwo phase turnaround, the petroleum business accelerated certain planned turnaround activities previouslyin the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. The petroleum business incurred approximately $13.0 million of major scheduled for 2016 and incurred turnaround expenses for the year ended December 31, 2014. The next turnaround for the Wynnewood refinery is scheduled to occur in the spring of 2017.hydrocracker. |
| |
| (3) | The Nitrogen Fertilizer Partnership underwent a full facility turnaround at the Coffeyville fertilizer facility in the third quarter of 2015. The Nitrogen Fertilizer Partnership is planning to undergo the next scheduled full facility turnaround inDuring the second halfquarter of 2017.2016 and the third quarter of 2017, the East Dubuque Facility completed major scheduled turnarounds. |
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
Cost Classifications
Cost of product sold (exclusive of depreciationmaterials and amortization)other 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 depreciation and amortization of approximately $6.7 million, $6.3 million and $5.0 million for the years ended December 31, 2015, 2014 and 2013, respectively.costs.
Direct operating expenses (exclusive of depreciation and amortization) includesconsist primarily of energy and other utility costs, direct costs of labor, maintenance and services, energy and utility costs, property taxes, plant-related maintenance services, including turnaround and environmental and safety compliance costs as well as chemicalscatalyst and catalysts and other direct operating expenses. Direct operating expenses excluded depreciation 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.chemical costs.
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 and administrative expenses excluded depreciation and amortization of approximately $7.7 million, $6.3 million and $3.3 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Income Taxes
CVR accounts for income taxes utilizing the asset and liability approach. Under this method, deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected 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 includes the enactment date. See Note 8 ("Income Taxes") for further discussion.
Impairment of Long-Lived Assets
CVR accounts for long-lived assets in accordance with accounting standards issued by the Financial Accounting Standards Board ("FASB")FASB regarding the 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 amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell.
Revenue Recognition
Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has assumed the assumed risk of loss and payment has been received or collection is reasonably assured. Deferred revenue represents customer prepayments under contracts to guarantee 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 and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues.
NonmonetaryNon-monetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in operating expenses on the Consolidated StatementStatements 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 of ownership. The Company records revenue for the gross amount of the sales transactions, and records costs of purchases as an operating expense in the accompanying consolidated financial statements.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Shipping Costs
Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of product sold (exclusive of depreciationmaterials and amortization).other.
Derivative Instruments and Fair Value of Financial Instruments
The petroleum business uses futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices and finished goods product prices to provide economic hedges of inventory positions. Although management considers these derivatives economic hedges, these derivative instruments do not qualify as hedges for hedge accounting purposes under Accounting Standards Codification ("ASC")ASC Topic 815, Derivatives and Hedging ("ASC 815"), and accordingly are recorded at fair value in the balance sheet.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. See Note 17 ("Derivative Financial Instruments") for further discussion.
The nitrogen fertilizer business usesenters into forward swap contracts primarilywith fixed delivery prices to reducepurchase portions of its natural gas requirements. The nitrogen fertilizer partnership elected to apply the exposurenormal purchase and normal sale exclusion to changesnatural gas contracts that are entered into to be used in interest rates on its debt and to provideproduction within a cash flow hedge. These derivative instruments have been designated as hedges for accounting purposes.reasonable time during the normal course of business. Accordingly, these instruments are recorded atthe fair value inof these contracts is not recorded on the Consolidated Balance Sheets at each reporting period end. The measurement of the cash flow hedge ineffectiveness is recognized in earnings, if applicable. The effective portion of the gain or loss on the swaps is reported in accumulated other comprehensive income (loss) ("AOCI"), in accordance with ASC 815. See Note 15 ("Derivative Financial Instruments") for further discussion.Sheets.
Other financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments. See Note 911 ("Long-Term Debt") for further discussion of the fair value of the debt instruments.
Share-Based Compensation
The Company accounts for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation ("ASC 718"). ASC 718 requires that compensation costs relating to share-based payment transactions be recognized in a company's financial statements. ASC 718 applies to transactions in which 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 on the fair value of those equity instruments. Currently, all of the Company's share-based compensation awards are liability-classified and are measured at fair value at the end of each reporting period based on the applicable closing unit price. Compensation expense will fluctuate based on changes in the applicable unit price value and expense reversals resulting from employee terminations prior to award vesting. See Note 34 ("Share-Based Compensation") for further discussion.
The Company's Chief Executive Officer has been awarded share-based compensation awards that contain performance conditions. The fair value of the awards is recognized as compensation expense only if the attainment of the performance conditions is considered probable. Uncertainties involved in this estimate include the continued employment of the Chief Executive Officer and whether or not the performance conditions will be attained. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. If this assumption proves not to be true and the awards do not vest, compensation expense recognized during the performance cycle will be reversed.
Treasury Stock
The Company accounts for its treasury stock under the cost method. To date, all treasury stock purchased was for the purpose of satisfying minimum statutory tax withholdings due at the vesting of non-vested stock awards.
Environmental Matters
Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, internal and third party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.
Use of Estimates
The consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles, using management's best estimates and judgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial
CVR Energy, Inc. and Subsidiaries
NOTES 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 and judgments.
Subsequent Events
The Company evaluated subsequent events, if any, that would require an adjustment to the Company's consolidated financial statements or require disclosure in the notes to the consolidated financial statements through the date of issuance of the consolidated financial statements. See Note 2022 ("Subsequent Events") for further discussion.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update ("ASU")ASU No. 2014-09, creating a new topic, FASB ASC Topic 606, “"Revenue from Contracts with Customers", ("which supersedes revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition.” This ASU 2014-09"), which requires 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 existingIn addition, an entity is required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue recognition guidance in U.S. GAAP when it becomes effective.and cash flows arising from contracts with customers. The standard is effective for interim and annual periods beginning after December 15, 2016 and permits2017. The Company adopted this standard, effective January 1, 2018, using the use of eithermodified retrospective application method, whereby the retrospective or cumulative effect transitionof initially applying the standard is recognized, if applicable, as an adjustment to the opening balance of retained deficit. The standard is applied prospectively and revenues reported in the periods prior to January 1, 2018 will not be changed. During the evaluation of the standard, the Company reviewed its existing revenue streams, including an evaluation of accounting policies, contract reviews and identification of the types of arrangements where differences may arise in the conversion to the new standard, identified practical expedients to be elected, and evaluated additional disclosure requirements. The Company did not identify any material differences in its existing revenue recognition methods that require modification under the new standard and does not expect to record a material cumulative effect adjustment of applying the standard using the modified retrospective method. EarlyThe standard's most significant impacts to the Company relate to enhanced disclosure requirements and a balance sheet presentation difference associated with contracts requiring customer prepayment prior to delivery. Prior to adoption of the new standard, deferred revenue was recorded upon customer prepayment. Under the new standard, a receivable and associated deferred revenue will be recorded at the point in time in which a prepaid contract is not permitted. On July 9, 2015,legally enforceable and the associated right to consideration is unconditional.
In February 2016, the FASB approvedissued ASU No. 2016-02, “Leases” (“ASU 2016-02”) creating a one-year deferralnew topic, FASB ASC Topic 842, "Leases," which supersedes lease requirements in FASB ASC Topic 840, "Leases." The new standard revises accounting for operating leases by a lessee, among other changes, and requires a lessee to recognize a liability related to future lease payments and an asset representing its right to use the underlying asset for the lease term in the balance sheet. Quantitative and qualitative disclosures, including disclosures regarding significant judgments made by management, will be required. The standard is effective for the first interim and annual periods beginning after December 15, 2018, with early adoption permitted. At adoption, ASU 2016-02 will be applied using the modified retrospective application method and allows for certain practical expedients. The Company expects its assessment and implementation plan to be ongoing during 2018 and is currently unable to reasonably estimate the impact of adopting the new lease standard on its consolidated financial statements and related disclosures. The Company currently believes the most significant change will relate to the recognition of right-of-use assets and leases liability on the balance sheet for existing long-term operating leases, the majority of which are railcar leases, and the potential recognition for agreements that do not currently meet the definition of a lease under ASC Topic 840, which will require an evaluation of the effective date makingCompany's unconditional purchase obligations primarily related to petroleum transportation and storage service agreements. The right of use asset, lease liability and related disclosures could be material.
In January 2017, the standardFASB issued ASU No. 2017-01, “Business Combinations (Topic 805) Clarifying the Definition of a Business” ("ASU 2017-01"). The new guidance revises the definition of a business and provides more stringent criteria for use in determining when an acquisition or disposal transaction meets the definition of a business. When substantially all of the fair value of gross assets acquired is concentrated in a single asset (or a group of similar assets), the assets acquired would not represent a business. This introduces an initial required screen that, if met, eliminates the need for further assessment. The new guidance is effective for interim and annual periods beginning after December 15, 2017. The FASB will continue to permit entities to adopt the standard on the original effective date if they choose.2017, with early adoption permitted. The Company has not yet selected a transition method and is currently evaluating theadopted this standard and the impact on its consolidated financial statements and footnote disclosures.as of January 1, 2017.
In February 2015,January 2017, the FASB issued ASU No. 2015-02, 2017-04, “"ConsolidationsIntangibles-Goodwill and Other (Topic 810)350) - Amendments to the Consolidation Analysis." The new guidance makes amendments to the current consolidation guidance, including introducing a separate consolidation analysis specific to limited partnerships and other similar entities. Under this analysis, limited partnerships and other similar entities will be considered a variable-interest entity ("VIE") unless the limited partners hold substantive kick-out rights or participating rights. The standard is effective for annual periods beginning after December 15, 2015. The Company is currently evaluating the standard and the impact, if any, on its consolidated financial statements and footnote disclosures; however, the Company does not anticipate that the standard will impact the Company's conclusion with respect to the consolidation of the Refining and Nitrogen Fertilizer Partnerships.
In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs" Test for Goodwill Impairment(" (“ASU 2015-03"2017-04”). The new standard requires that all costs incurred to issue debt be presented insimplifies the balance sheet as a direct deductionaccounting for goodwill impairments by eliminating step 2 from the goodwill quantitative impairment test. Instead, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss shall be recognized in an amount equal to that excess, limited to the total amount of the debt.goodwill allocated to that reporting unit. The standard is effective for interim and annual periods beginning after December 15, 2015 and is required to be applied on a retrospective basis. Early2019, with early adoption is permitted. The Company expects thatadopted this standard as of January 1, 2017.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(3) Acquisition
On April 1, 2016, the adoptionNitrogen Fertilizer Partnership completed the East Dubuque Merger as contemplated by the Agreement and Plan of ASU 2015-03Merger, dated as of August 9, 2015 (the "Merger Agreement"), whereby the Nitrogen Fertilizer Partnership acquired CVR Nitrogen and CVR Nitrogen GP. Pursuant to the East Dubuque Merger, the Nitrogen Fertilizer Partnership acquired the East Dubuque Facility. The primary reasons for the East Dubuque Merger were to expand the Nitrogen Fertilizer Partnership's geographical footprint, diversify its raw material feedstocks, widen its customer reach and increase its potential for cash-flow generation.
CVR Nitrogen sold its facility located in Pasadena, Texas as a condition to closing the East Dubuque Merger. The Nitrogen Fertilizer Partnership did not receive and will resultnot receive any consideration relating to the sale of the Pasadena Facility.
Under the terms of the Merger Agreement, holders of CVR Nitrogen common units eligible to receive consideration received 1.04 common units (the "unit consideration") representing limited partner interests in CVR Partners ("CVR Partners common units") and $2.57 in cash, without interest (the "cash consideration" and together with the unit consideration, the "merger consideration") for each CVR Nitrogen common unit. Pursuant to the Merger Agreement, CVR Partners issued approximately 40.2 million CVR Partners common units and paid approximately $99.2 million in cash consideration to CVR Nitrogen common unitholders and certain holders of CVR Nitrogen phantom units discussed below.
Phantom units granted and outstanding under CVR Nitrogen’s equity plans and held by an employee who continued in the employment of a reclassificationCVR Partners-affiliated entity upon closing of certain debt issuance coststhe East Dubuque Merger were canceled and replaced with new incentive awards of substantially equivalent value and on similar terms. See Note 4 ("Share-Based Compensation") for further discussion. Each phantom unit granted and outstanding and held by (i) an employee who did not continue in employment of a CVR Partners-affiliated entity, or (ii) a director of CVR Nitrogen GP, upon closing of the Consolidated Balance Sheets.East Dubuque Merger, vested in full and the holders thereof received the merger consideration.
In November 2015,accordance with the FASB issued ASU 2015-17,FASB’s ASC Topic 805 — "Balance Sheet Classification of Deferred Taxes"Business Combinations ("ASU 2015-17"ASC 805"). The new standard, the Nitrogen Fertilizer Partnership accounted for the East Dubuque Merger as an acquisition of a business with CVR Partners as the acquirer. ASC 805 requires that all deferred tax assetsthe consideration transferred be measured at the current market price at the date of the closing of the East Dubuque Merger. The aggregate merger consideration was approximately $802.4 million, including the fair value of CVR Partners common units issued of $335.7 million, a cash contribution of $99.2 million and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet.$367.5 million fair value of assumed debt. The standard is effective for interimEast Dubuque Facility contributed net sales of $127.9 million and annual periods beginning after December 15, 2016 and early adoption is permitted. The new standard may be applied either prospectively or retrospectively upon adoption. The Company elected to early adopt ASU 2015-17 asan operating loss of December 31, 2015 and applied the standard prospectively$1.2 million to the Consolidated Balance Sheet. The Consolidated Balance Sheet asStatement of Operations for the year ended December 31, 2014 was not retrospectively adjusted. Refer to Note 8 ("Income Taxes") for further details.2016.
Parent Affiliate Units
In March 2016, CVR Energy purchased 400,000 CVR Nitrogen common units, representing approximately 1% of the outstanding CVR Nitrogen limited partner interests. CVR Energy did not receive merger consideration for these designated CVR Nitrogen common units. As a result of the East Dubuque Merger, on April 1, 2016, the fair value of the CVR Nitrogen common units of $4.6 million was reclassified as an investment in consolidated subsidiary, which is a non-cash investing activity during the second quarter of 2016. Subsequent to the East Dubuque Merger, the Nitrogen Fertilizer Partnership purchased the 400,000 CVR Nitrogen common units from CVR Energy during the second quarter of 2016 for $5.0 million.
Merger-Related Indebtedness
CVR Nitrogen’s debt arrangements that remained in place after the closing date of the East Dubuque Merger included $320.0 million of its 6.50% notes due 2021 (the "2021 Notes"). The majority of the 2021 Notes were repurchased in June 2016, as discussed further in Note 11 ("Long-Term Debt").
Immediately prior to the East Dubuque Merger, CVR Nitrogen also had outstanding balances under a credit agreement with Wells Fargo Bank, National Association, as successor-in-interest by assignment from General Electric Company, as administrative agent (the "Wells Fargo Credit Agreement"). The Wells Fargo Credit Agreement consisted of a $50.0 million senior secured revolving credit facility with a $10.0 million letter of credit sublimit. In connection with the closing of the East Dubuque Merger, the Nitrogen Fertilizer Partnership paid $49.4 million for the outstanding balance, accrued interest and fees under the Wells Fargo Credit Agreement and the Wells Fargo Credit Agreement was canceled.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
Purchase Price Allocation
Under the acquisition method of accounting, the purchase price was allocated to CVR Nitrogen's net tangible assets based on their fair values as of April 1, 2016. The Nitrogen Fertilizer Partnership has obtained an independent appraisal of the net assets acquired. Determining the fair value of net tangible assets requires judgment and involves the use of significant estimates and assumptions. The Nitrogen Fertilizer Partnership based its fair value estimates on assumptions it believes to be reasonable but are inherently uncertain.
The following table, set forth below, displays the purchase price allocated to CVR Nitrogen's net tangible assets based on their fair values as of April 1, 2016. There were no identifiable intangible assets.
|
| | | | |
| | | Purchase Price Allocation |
| | | (in millions) |
| Cash | | $ | 35.4 |
|
| Accounts receivable | | 8.9 |
|
| Inventories | | 49.1 |
|
| Prepaid expenses and other current assets | | 5.2 |
|
| Property, plant and equipment | | 775.3 |
|
| Other long-term assets | | 1.1 |
|
| Deferred revenue | | (29.8 | ) |
| Other current liabilities | | (37.0 | ) |
| Long-term debt | | (367.5 | ) |
| Other long-term liabilities | | (1.2 | ) |
| Total fair value of net assets acquired | | 439.5 |
|
| Less: Cash acquired | | 35.4 |
|
| Total consideration transferred, net of cash acquired | | $ | 404.1 |
|
Expenses Associated with the East Dubuque Merger
During the year ended December 31, 2016 and 2015, the Nitrogen Fertilizer Partnership incurred $3.1 million and $2.3 million, respectively, of legal and other professional fees and other merger related expenses, which were included in selling, general and administrative expenses (exclusive of depreciation and amortization).
Noncontrolling Interest in CVR Partners
A summary of the effect of the change in CVR Energy's ownership interest in CVR Partners on the equity attributable to CVR Energy, as a result of CVR Partners issuance of the unit consideration in connection with the East Dubuque Merger, is as follows:
|
| | | | |
| | | |
| | | Non-controlling interest
|
| | | (in millions) |
| Fair value of CVR Partners common units issued, as of the close of the East Dubuque Merger | | $ | 335.7 |
|
| Less: Change in CVR Energy's noncontrolling interest in CVR Partner's equity due to the East Dubuque Merger | | 292.8 |
|
| Adjustment to additional paid-in capital, as of the close of the East Dubuque Merger | | $ | 42.9 |
|
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(3)(4) Share-Based Compensation
Long-Term Incentive Plan — CVR Energy
CVR has a Long-Term Incentive Plan ("LTIP"), which permits the grant of options, stock appreciation rights ("SARs"), restricted shares, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of December 31, 2015,2017, only restricted stock units and performance units remain outstanding under the LTIP.LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the LTIP include the Company's employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP 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 issued in respect of incentive stock options. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of shares available for issuance under the LTIP is increased by the number of shares previously allocable to the expired, canceled, settled or otherwise terminated portion of the award. As of December 31, 2015,2017, 6,787,341 shares of common stock were available for issuance under the LTIP.
Restricted Stock Units
A summary of restricted stock units activity and changes during the years ended December 31, 2015, 20142017, 2016 and 20132015 is presented below:
| | | | Restricted Shares | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value | Restricted Shares | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value |
| | | | | | (in millions) | | | | | (in millions) |
| Non-vested at December 31, 2012 | 1,145,611 |
| | $ | 23.24 |
| | $ | 55.9 |
| |
| Granted | 2,600 |
| | 54.75 |
| | | |
| Vested | (709,959 | ) | | 18.73 |
| | | |
| Forfeited | (78,700 | ) | | 42.80 |
| | | |
| Non-vested at December 31, 2013 | 359,552 |
| | $ | 28.09 |
| | $ | 15.6 |
| |
| Granted | — |
| | — |
| | | |
| Vested | (281,684 | ) | | 23.89 |
| | | |
| Forfeited | (29,857 | ) | | 39.17 |
| | | |
| Non-vested at December 31, 2014 | 48,011 |
| | $ | 45.89 |
| | $ | 1.9 |
| 48,011 |
| | $ | 45.89 |
| | $ | 1.9 |
|
| Granted | — |
| | — |
| | | — |
| | — |
| | |
| Vested | (43,085 | ) | | 45.55 |
| | | (43,085 | ) | | 45.55 |
| | |
| Forfeited | (4,327 | ) | | 47.68 |
| | | (4,327 | ) | | 47.68 |
| | |
| Non-vested at December 31, 2015 | 599 |
| | $ | 57.23 |
| | $ | — |
| 599 |
| | $ | 57.23 |
| | $ | — |
|
| Granted | | — |
| | — |
| | |
| Vested | | (599 | ) | | 57.23 |
| | |
| Forfeited | | — |
| | — |
| | |
| Non-vested at December 31, 2016 | | — |
| | $ | — |
| | $ | — |
|
Through the LTIP, shares of restricted stock and restricted stock units (collectively "restricted shares") were previously granted to employees of the Company. These restricted shares arewere generally graded-vesting awards, which vestvested over a three-year period. Compensation expense iswas recognized on a straight-line basis over the vesting period of the respective tranche of the award. The IEP Acquisition and related Transaction Agreement dated April 18,change of control of CVR Energy in 2012 between CVR and an affiliate of IEP discussed in Note 1 ("Organization and History of the Company") triggered a modification to outstanding awards under 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 cash plus one CCPcontingent cash payment right ("CCP") upon vesting. The CCPs expired on August 19, 2013. Restricted shares that vested in 2013, 2014 and 2015 were converted to restricted stock units 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's common stock as determined at the most recent valuation date of December 31 of each year. The awards were remeasured at each subsequent reporting date until they vested. As a result of the modification of the awards, the classification changed from equity-classified awards to liability-classified awards.
CVR Energy, Inc. and Subsidiaries
NOTES 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. The awards vestvested over three years with one-third of the award vesting each year with the exception of awards granted to certain executive officers that vested over one year. The award granted in December 2012 to Mr. Lipinski, the Company's then Chief Executive Officer and President, was canceled in connection with the issuance of certain performance unit awards as discussed further below. Each restricted stock unit and dividend equivalent right representsrepresented the right to receive, 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 dividends declared 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 arewere liability-classified, arewere remeasured each subsequent reporting date until they vest.vested.
As of December 31, 2015, total unrecognized compensation cost related to non-vested2017, no restricted stock units and associated dividend equivalent rights and the weighted average period over which it will be recognized were nominal.outstanding. Total compensation expense for the years ended December 31, 2015, 20142017 and 20132016 related to the restricted stock unit awards was nominal. Total compensation expense for the year ended December 31, 2015 was approximately $0.8 million $2.6 million and $13.2 million, respectively, related to the restricted stock unit awards.
As of December 31, 2014,2017, the Company had ano liability of $1.7 million for non-vested restricted stock unit awards and associated dividend equivalent rights, which is recorded in personnel accruals on the Consolidated Balance Sheets.rights. The liability as of December 31, 20152016 was nominal. For the year ended December 31, 2017, no cash was paid to settle liability-classified restricted stock unit awards and dividend equivalent rights. For the years ended December 31, 2015, 20142016 and 2013,2015, the Company paid cash of $2.5 million, $9.9 milliona nominal amount and $23.8$2.5 million, respectively, to settle liability-classified restricted stock unit awards and dividend equivalent rights upon vesting.
Performance Unit Awards
In 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 restricted stock unit award, as discussed above. In accordance with accounting guidance related to the modification of share-based and other compensatory award arrangements, the Company concluded that the cancellation and concurrent issuance of the performance awards created a substantive service period from the original grant date of the December 2012 restricted stock unit award through December 31, 2014, the end of the performance period for the related performance awards. Compensation cost for the related awards was recognized over the substantive service period. Total compensation expense for the years ended 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 Company had a liability of $1.7 million recorded in personnel accruals on the Consolidated Balance Sheets for the final vested and unpaid 2013 Performance Unit Awards, 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. The performance unit award of 3,500 performance units under the 2015 Performance Unit Award Agreement represents the right to receive, upon vesting, a cash payment equal to $1,000 multiplied by the applicable performance factor. The performance factor is determined based on the level of attainment of the applicable performance objective, set forth as a percentage, which may range from 0-110%. Seventy-five percent of the performance units attributable to the award are subject to a performance objective relating to the average barrels per day crude throughput during the performance cycle, and 25% of the performance units attributable to the award are subject to a performance objective relating to the average gathered crude barrels per day during the performance cycle. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. The amount paid pursuant to the award was paid during the first quarter of 2017. Both the Refining Partnership and the Nitrogen Fertilizer Partnership reimbursed CVR Energy for their allocated portions of the performance unit award. Compensation cost for the 2015 Performance Unit Award Agreement will beof $3.5 million was recognized over the performance cycle from January 1, 2016 to December 31, 2016.
In December 2016, the Company entered into a performance unit award agreement (the "2016 Performance Unit Award Agreement") with Mr. Lipinski with terms substantially the same as the 2015 Performance Unit Award Agreement. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2018. Both the Refining Partnership and the Nitrogen Fertilizer Partnership are responsible for reimbursing CVR Energy for their allocated portions of the performance unit award. Compensation cost for the 2016 Performance Unit Award Agreement of $3.6 million was recognized over the performance cycle from January 1, 2017 to December 31, 2017. As of December 31, 2017, the Company had an outstanding liability of $3.6 million related to the 2016 performance unit award.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
On November 1, 2017, the Company entered into a performance unit agreement (the "2017 Performance Unit Agreement") with David Lamp, the Company's current Chief Executive Officer and President. Compensation cost for the 2017 Performance Unit Agreement will be recognized over the performance cycle from January 1, 2018 to December 31, 2018. The performance unit award of 1,500 performance units under the 2017 Performance Unit Agreement represents the right to receive, upon vesting, a cash payment equal to $1,000 multiplied by the applicable performance factor. The performance factor is determined based on the level of attainment of the applicable performance objective, and both the performance factor and performance objective(s) will be determined by CVR Energy's compensation committee. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2019. Both the Refining Partnership and the Nitrogen Fertilizer Partnership are responsible for reimbursing CVR Energy for their allocated portions of the performance unit award. Assuming a target performance threshold and that the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at December 31, 2017, there was approximately $1.5 million of total unrecognized compensation cost related to the 2017 Performance Unit Agreement to be recognized over a period of one year.
On November 1, 2017, the Company entered into a performance unit award agreement (the "2017 Performance Unit Award Agreement") with Mr. Lamp. The performance unit award represents the right to receive upon vesting, a cash payment equal to a defined threshold in accordance with$10.0 million if the award agreement, multiplied by a performance factor thataverage closing price of CVR Energy's common stock over the 30-trading day period from January 4, 2022 to February 15, 2022 is based upon the achievement of certain operating objectives. Assuming a target performance threshold,equal to or greater than $60 per share. At December 31, 2017, there was approximately $3.5$10.0 million of total unrecognized compensation cost related to the 20152017 Performance Unit Award Agreement to be recognized over a weighted-average period of approximately 1.0 year.4 years.
Long-Term Incentive Plan — CVR Partners
Common Units and Phantom Units
In April 2011, the board of directors of the Nitrogen Fertilizer Partnership's general partner adoptedIndividuals who are eligible to receive awards under 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 Fertilizer Partnership 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 the
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CVR Partners' LTIP is 5,000,000. As of December 31, 2015,2017, 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 general partner and to members of the board of directors of its general partner. In 2013, 20142015, 2016 and 2015,2017, awards of phantom units and distribution equivalent rights were granted to certain employees of the Nitrogen Fertilizer Partnership and its subsidiaries and its general partner. 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 phantom unit and distribution 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 Nitrogen Fertilizer Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Nitrogen Fertilizer Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
A summary of common units and phantom units (collectively "units") activity and changes under the CVR Partners LTIP during the years ended December 31, 2015, 20142017, 2016 and 20132015 is presented below:
| | | | Units | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value | Units | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value |
| | | | | | (in millions) | | | | | (in millions) |
| Non-vested at December 31, 2012 | 201,812 |
| | $ | 23.70 |
| | $ | 5.1 |
| |
| Granted | 58,536 |
| | 16.13 |
| | | |
| Vested | (89,229 | ) | | 23.24 |
| | | |
| Forfeited | — |
| | — |
| | | |
| Non-vested at December 31, 2013 | 171,119 |
| | $ | 21.34 |
| | $ | 2.8 |
| |
| Granted | 198,141 |
| | 9.44 |
| | | |
| Vested | (48,310 | ) | | 20.95 |
| | | |
| Forfeited | (77,004 | ) | | 23.49 |
| | | |
| Non-vested at December 31, 2014 | 243,946 |
| | $ | 11.07 |
| | $ | 2.4 |
| 243,946 |
| | $ | 11.07 |
| | $ | 2.4 |
|
| Granted | 245,199 |
| | 7.87 |
| | | 245,199 |
| | 7.87 |
| | |
| Vested | (94,854 | ) | | 12.55 |
| | | (94,854 | ) | | 12.55 |
| | |
| Forfeited | (2,388 | ) | | 10.99 |
| | | (2,388 | ) | | 10.99 |
| | |
| Non-vested at December 31, 2015 | 391,903 |
| | $ | 8.71 |
| | $ | 3.1 |
| 391,903 |
| | $ | 8.71 |
| | $ | 3.1 |
|
| Granted | | 680,718 |
| | 6.20 |
| | |
| Vested | | (292,536 | ) | | 8.78 |
| | |
| Forfeited | | (8,299 | ) | | 8.72 |
| | |
| Non-vested at December 31, 2016 | | 771,786 |
| | $ | 6.47 |
| | $ | 4.6 |
|
| Granted | | 780,372 |
| | 3.48 |
| | |
| Vested | | (340,730 | ) | | 7.01 |
| | |
| Forfeited | | (23,222 | ) | | 6.49 |
| | |
| Non-vested at December 31, 2017 | | 1,188,206 |
| | $ | 4.35 |
| | $ | 3.9 |
|
As of December 31, 2015,2017, there was approximately $2.7$3.3 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of 1.81.7 years. Total compensation expense recorded for the years ended December 31, 2015, 20142017, 2016 and 20132015 related to the awards under the CVR Partners LTIP was approximately $1.3$1.1 million, $0.4$1.8 million and $1.3 million, respectively.
At December 31, 20152017 and 2014,2016, the Nitrogen Fertilizer Partnership had a liability of $0.7 million and $0.2$1.0 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. For the years ended December 31, 2015, 20142017, 2016 and 20132015 the Nitrogen Fertilizer Partnership paid cash of $0.8$1.4 million, $0.4$2.1 million and $0.2$0.8 million, respectively, to settle liability-classified awards and associated distribution equivalent rights upon vesting.
Performance-Based Phantom Units
In May 2014, the Nitrogen Fertilizer Partnership entered into a Phantom Unit Agreement with the Chief Executive Officer and President of its general partner that included performance-based phantom units and distribution equivalent rights. Compensation cost for these awards is beingwas recognized over the performance 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 services arewere provided. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average
CVR Energy, Inc. and Subsidiaries
NOTES 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 based upon 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 the Nitrogen Fertilizer Partnership from the grant date to and including the vesting date. Total compensation expense recorded for the years ended December 31, 20152017 and 20142016 related to the award was not material. Based on current estimates of performance thresholds for theAs there were no remaining performance cycles related to these awards, there was no unrecognized compensation expense and theor liability associated with the unvested phantom units at December 31, 2015 were also not material.2017.
On December 31, 2014, the first award of Mr. Pytosh'sthe Phantom Unit Agreement vested and a nominal amount was paid in 2015. On December 31, 2015, the second award of Mr. Pytosh'sthe Phantom Unit Agreement vested and a nominal amount will bewas paid in 2016. On December 31, 2016, the third award of the Phantom Unit Agreement vested and nominal amount was paid in 2017. The award was fully vested at December 31, 2016 and the amount associated with the agreement was not material.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Long-Term Incentive Plan – CVR Refining
In connection with the Refining Partnership IPO, on January 16, 2013, the board of directors of the general partner of the Refining Partnership adoptedIndividuals who are eligible to receive awards under the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"). Individuals who are eligible to receive awards under the CVR Refining LTIP include (i) employees of the Refining Partnership and its subsidiaries, (ii) employees of the general partner, (iii) members of the board of directors of the general partner and (iv) certain employees, consultants and directors of CRLLCCoffeyville Resources, LLC ("CRLLC") and CVR Energy who perform services for the benefit of the Refining Partnership. 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 of common 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 reduce the 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 common units.
In 2013, 20142015, 2016 and 2015,2017, awards of phantom units and distribution equivalent rights were granted to employees of the Refining Partnership and its subsidiaries, 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. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each phantom unit and distribution 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 Refining Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Refining Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
CVR Energy, Inc. and Subsidiaries
NOTES 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, 20142017, 2016 and 20132015 is presented below:
| | | | Phantom Units | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value | Phantom Units | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value |
| | | | | | (in millions) | | | | | (in millions) |
| Non-vested at January 16, 2013 | — |
| | $ | — |
| | $ | — |
| |
| Granted | 187,177 |
| | 21.55 |
| | | |
| Vested | — |
| | — |
| | | |
| Forfeited | — |
| | — |
| | | |
| Non-vested at December 31, 2013 | 187,177 |
| | $ | 21.55 |
| | $ | 4.2 |
| |
| Granted | 281,948 |
| | 17.74 |
| | | |
| Vested | (61,002 | ) | | 21.55 |
| | | |
| Forfeited | (4,176 | ) | | 21.55 |
| | | |
| Non-vested at December 31, 2014 | 403,947 |
| | $ | 18.89 |
| | $ | 6.8 |
| 403,947 |
| | $ | 18.89 |
| | $ | 6.8 |
|
| Granted | 302,319 |
| | 20.40 |
| | | 302,319 |
| | 20.40 |
| | |
| Vested | (136,531 | ) | | 19.26 |
| | | (136,531 | ) | | 19.26 |
| | |
| Forfeited | (58,144 | ) | | 18.87 |
| | | (58,144 | ) | | 18.87 |
| | |
| Non-vested at December 31, 2015 | 511,591 |
| | $ | 19.68 |
| | $ | 9.7 |
| 511,591 |
| | $ | 19.68 |
| | $ | 9.7 |
|
| Granted | | 644,148 |
| | 9.43 |
| | |
| Vested | | (218,351 | ) | | 19.78 |
| | |
| Forfeited | | (32,533 | ) | | 19.13 |
| | |
| Non-vested at December 31, 2016 | | 904,855 |
| | $ | 12.38 |
| | $ | 9.4 |
|
| Granted | | 550,172 |
| | 12.66 |
| | |
| Vested | | (349,921 | ) | | 13.42 |
| | |
| Forfeited | | (118,626 | ) | | 13.52 |
| | |
| Non-vested at December 31, 2017 | | 986,480 |
| | $ | 12.03 |
| | $ | 16.3 |
|
As of December 31, 2015,2017, there was approximately $8.3$13.1 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.7 years. Total compensation expense recorded for the years ended December 31, 20152017, 2016 and 20142015 related to the awards under the CVR Refining LTIP was $7.4 million, $1.8 million and $4.6 million, and $2.4 million, respectively. Total compensation expense recorded for the year ended December 31, 2013 was not material. As of December 31, 20152017 and 2014,2016, the Refining Partnership had a liability of $2.3$3.7 million and $1.0$1.5 million, respectively, for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals on the Consolidated Balance Sheets. For the years ended December 31, 20152017, 2016 and 2014,2015, the Refining Partnership paid cash of $3.3$5.1 million, $2.6 million and $1.4$3.3 million, respectively, to settle liability-classified phantom unit awards and associated distribution equivalent rights upon vesting.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In December 2014, the Company granted an award of 227,927 incentive units in the form of stock appreciation rights ("SARs")SARs to an executive of CVR Energy. In April 2015, the award granted was cancelledcanceled and replaced by an award of notional units in the form of SARs by CVR Refining pursuant to the CVR 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 material impact. 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 one unit 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 will be adjusted to include all distributions declared and paid by the Refining Partnership during the vesting period. The fair value of each SAR is estimated at the end of each reporting period using the Black-Scholes option-pricing model. Assumptions utilized to value the award have been omitted due to immateriality of the award. The SARs vested on December 1, 2017 and the awards had a fair value of zero as of December 31, 2017. Total compensation expense during the years ended December 31, 20152017, 2016 and 20142015 and the liability related to the SARs as of December 31, 20152017 and 20142016 were not material.
Incentive Unit Awards
In 2013, 20142015, 2016 and 2015,2017, the Company granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC, CVR Energy and 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 and distribution 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 Refining Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Refining Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
A summary of incentive unit activity and changes during the years ended December 31, 2015, 20142017, 2016 and 20132015 is presented below:
| | | | Incentive Units | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value | Incentive Units | | Weighted- Average Grant-Date Fair Value | | Aggregate Intrinsic Value |
| | | | | | (in millions) | | | | | (in millions) |
| Non-vested at December 31, 2012 | — |
| | $ | — |
| | $ | — |
| |
| Granted | 251,431 |
| | 22.62 |
| | | |
| Vested | — |
| | — |
| | | |
| Forfeited | — |
| | — |
| | | |
| Non-vested at December 31, 2013 | 251,431 |
| | $ | 22.62 |
| | $ | 5.7 |
| |
| Granted | 332,586 |
| | 17.81 |
| | | |
| Vested | (65,601 | ) | | 22.63 |
| | | |
| Forfeited | (82,901 | ) | | 22.62 |
| | | |
| Non-vested at December 31, 2014 | 435,515 |
| | $ | 18.95 |
| | $ | 7.3 |
| 435,515 |
| | $ | 18.95 |
| | $ | 7.3 |
|
| Granted | 347,811 |
| | 20.38 |
| | | 347,811 |
| | 20.38 |
| | |
| Vested | (160,120 | ) | | 19.33 |
| | | (160,120 | ) | | 19.33 |
| | |
| Forfeited | (18,264 | ) | | 19.69 |
| | | (18,264 | ) | | 19.69 |
| | |
| Non-vested at December 31, 2015 | 604,942 |
| | $ | 19.64 |
| | $ | 11.5 |
| 604,942 |
| | $ | 19.64 |
| | $ | 11.5 |
|
| Granted | | 678,469 |
| | 9.46 |
| | |
| Vested | | (256,016 | ) | | 19.69 |
| | |
| Forfeited | | (39,598 | ) | | 19.52 |
| | |
| Non-vested at December 31, 2016 | | 987,797 |
| | $ | 12.63 |
| | $ | 10.3 |
|
| Granted | | 382,648 |
| | 12.87 |
| | |
| Vested | | (371,731 | ) | | 14.14 |
| | |
| Forfeited | | (219,453 | ) | | 12.23 |
| | |
| Non-vested at December 31, 2017 | | 779,261 |
| | $ | 12.14 |
| | $ | 12.9 |
|
As of December 31, 2015,2017, there was approximately $9.6$10.0 million of total unrecognized compensation cost related to non-vested incentive units to be recognized over a weighted-average period of approximately 1.71.6 years. Total compensation expense for the years ended December 31, 20152017, 2016 and 20142015 related to the incentive units was $6.8 million, $2.3 million and $5.7 million, and $2.4 million, respectively. Total compensation expense for the year ended December 31, 2013 related to the incentive units was not material. As of December 31, 20152017 and 2014,2016, the Company had a liability of $2.6$3.3 million and $0.8$1.9 million, respectively, for non-vested incentive units and associated distribution equivalent rights, which is recorded in personnel accruals on the Consolidated Balance Sheets. For the years ended December 31, 20152017, 2016 and 2014,2015, the Company paid cash of $3.9$5.5 million, $3.0 million and $1.6$3.9 million, respectively, to settle liability-classified incentive unit awards and associated distribution equivalent rights upon vesting.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(4)(5) Inventories
Inventories consisted of the following:
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Finished goods | $ | 114.5 |
| | $ | 176.2 |
| $ | 172.0 |
| | $ | 151.7 |
|
| Raw materials and precious metals | 81.2 |
| | 88.0 |
| 113.8 |
| | 98.4 |
|
| In-process inventories | 35.8 |
| | 20.6 |
| 22.4 |
| | 23.9 |
|
| Parts and supplies | 58.4 |
| | 44.8 |
| 77.0 |
| | 75.2 |
|
| | $ | 289.9 |
| | $ | 329.6 |
| |
| Total Inventories | | $ | 385.2 |
| | $ | 349.2 |
|
Due to the crude pricing environment and subsequent reduction in sales prices for the petroleum business' refined products at the end of 2014, the Refining Partnership recorded a lower of FIFO cost or market inventory adjustment of approximately $36.8 million as of December 31, 2014. The inventory adjustment is included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(5)(6) Property, Plant and Equipment
A summary of costs for property,Property, plant and equipment is as follows:consisted of the following:
| | | | December 31, | December 31, |
| | 2015 | | 2014 | 2017 | | 2016 |
| | (in millions) | (in millions) |
| Land and improvements | $ | 38.6 |
| | $ | 37.4 |
| $ | 47.4 |
| | $ | 46.5 |
|
| Buildings | 53.6 |
| | 50.4 |
| 83.3 |
| | 64.8 |
|
| Machinery and equipment | 2,723.0 |
| | 2,581.2 |
| 3,733.8 |
| | 3,656.5 |
|
| Automotive equipment | 24.8 |
| | 22.1 |
| 24.7 |
| | 24.7 |
|
| Furniture and fixtures | 21.3 |
| | 19.0 |
| 32.4 |
| | 28.9 |
|
| Leasehold improvements | 3.6 |
| | 3.4 |
| 4.6 |
| | 3.6 |
|
| Aircraft | 3.6 |
| | 3.7 |
| 3.6 |
| | 3.6 |
|
| Railcars | 16.3 |
| | 14.5 |
| 16.8 |
| | 16.8 |
|
| Construction in progress | 122.3 |
| | 71.5 |
| 56.2 |
| | 54.2 |
|
| | 3,007.1 |
| | 2,803.2 |
| 4,002.8 |
| | 3,899.6 |
|
| Accumulated depreciation | 1,040.0 |
| | 887.2 |
| |
| | $ | 1,967.1 |
| | $ | 1,916.0 |
| |
| Less: Accumulated depreciation | | 1,431.0 |
| | 1,227.5 |
|
| Total Property, plant and equipment, net | | $ | 2,571.8 |
| | $ | 2,672.1 |
|
Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2015, 20142017, 2016 and 20132015 totaled approximately $3.7$1.1 million, $9.4$5.4 million and $3.6$3.7 million, respectively. Land, buildingbuildings and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million at both December 31, 20152017 and 2014, respectively.2016. Amortization of assets held under capital leases is included in depreciation expense.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(6)(7) Equity Method Investments
VPP Joint Venture
OnSeptember 19, 2016, Coffeyville Resources Pipeline, LLC ("CRPLLC"), an indirect wholly-owned subsidiary of CVR Refining, entered into an agreement with Velocity Central Oklahoma Pipeline LLC ("Velocity") related to their joint ownership of Velocity Pipeline Partners, LLC ("VPP"), which is a pipeline company that operates a 12-inch crude oil pipeline with a capacity of approximately 65,000 barrels per day and an estimated length of 25 miles with a connection to the Refining Partnership's Wynnewood refinery and a trucking terminal at Lowrance, Oklahoma. CRPLLC holds a 40% interest in VPP. Velocity holds a 60% interest in VPP and serves as the day-to-day operator of VPP. As of December 31, 2017, the carrying value of CRPLLC's investment in VPP was $6.1 million, which is recorded in equity method investments in affiliates on the Consolidated Balance Sheets. Contributions by CRPLLC to VPP during the pipeline construction totaled $7.0 million, of which $1.4 million was contributed in the first quarter of 2017.
The pipeline commenced operations in mid-April 2017 following completion of construction. Equity income from VPP for the nine months ended December 31, 2017 was $0.2 million, which is recorded in other income, net on the Consolidated Statements of Operations. For the nine months ended December 31, 2017, CRPLLC received cash distributions from VPP of $1.1 million.
Coffeyville Resources Refining & Marketing, LLC ("CRRM") is party to a transportation agreement with VPP for an initial term of 20 years under which VPP provides CRRM with crude oil transportation services for crude oil purchased within a defined geographic area, and CRRM entered into a terminalling services agreement with Velocity under which it receives access to Velocity’s terminal in Lowrance, Oklahoma to unload and pump crude oil into VPP's pipeline for an initial term of 20 years. For the nine months ended December 31, 2017, CRRM incurred costs of $1.8 million, under the transportation agreement with VPP. CRRM's crude shipments on the pipeline for the nine months ended December 31, 2017 averaged approximately 16,000 barrels per day. As of December 31, 2017, the Consolidated Balance Sheets included a liability of $0.3 million to VPP.
Midway Joint Venture
On October 31, 2017, subsidiaries of CVR Refining and Plains All American Pipeline, L.P. ("Plains") formed a 50/50 joint venture, Midway Pipeline LLC ("Midway"), which acquired the approximately 100-mile, 16-inch Cushing to Broome pipeline system from Plains. The Cushing to Broome pipeline system connects CVR Refining’s Coffeyville, Kansas, refinery to the Cushing, Oklahoma oil hub. Midway has a contract with Plains pursuant to which Plains will continue its role as operator of the pipeline. In November 2017, CVR Refining contributed $76.0 million to Midway and for the two months ended December 31, 2017 CVR Refining's equity income from Midway was $0.7 million, which is recorded in other income, net on the Consolidated Statements of Operations. As of December 31, 2017, the carrying value of CVR Refining's investment in Midway was $76.7 million, which is recorded in equity method investments in affiliates on the Consolidated Balance Sheets.
For the two months ended December 31, 2017, CVR Refining incurred costs of $3.0 million with Midway for crude oil transportation services. Crude shipments on the pipeline for the two months ended December 31, 2017 averaged approximately 103,000 barrels per day. As of December 31, 2017, the Consolidated Balance Sheets included a liability of $0.0 million to Midway.
(8) Goodwill
The Nitrogen Fertilizer Partnership completes its annual test for impairmentevaluates the carrying value of goodwill annually as of November 1 each year.and between annual evaluations if events occur or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. The Nitrogen Fertilizer Partnership's goodwill reporting unit is the Coffeyville Fertilizer Facility. No impairment of goodwill was recorded for any of the periods presented.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
August 31, 2017 Interim Impairment Test
Based on a significant decline in market capitalization and lower cash flow forecasts resulting from weakened fertilizer pricing trends that occurred during the third quarter of 2017, the Nitrogen Fertilizer Partnership identified a triggering event and therefore performed an interim goodwill impairment test as of August 31, 2017. The quantitative goodwill impairment analysis compares the fair value of the reporting unit to its carrying value. The Coffeyville Fertilizer Facility reporting unit fair value is based upon consideration of various valuation methodologies, including guideline public company multiples and projected future cash flows discounted at rates commensurate with the risk involved. The carrying amount of the reporting unit was less than its fair value; therefore, no impairment was recorded.
The fair value of the reporting unit exceeded its carrying value by approximately 12% based upon the results of the interim goodwill impairment test as of August 31, 2017. Judgments and assumptions are inherent in management’s estimates used to determine the fair value of the reporting unit. Assumptions used in the discounted cash flows ("DCF") included estimating appropriate discount rates and growth rates, and estimating the amount and timing of expected future cash flows. The discount rates used in the DCF, which are intended to reflect the risks inherent in future cash flow projections, are based on estimates of the weighted-average cost of capital of a market participant. Such estimates are derived from analysis of peer companies and consider the industry weighted average return on debt and equity from a market participant perspective. The most significant assumption to determining the fair value of the reporting unit was forecasted fertilizer pricing. The Nitrogen Fertilizer Partnership also calculated fair value estimates derived from the market approach utilizing the public company market multiple method, which required assumptions about the applicability of those multiples to the Coffeyville Facility reporting unit.
November 1, 2017 Annual Impairment Test
Due to the short length of time since the August 31, 2017 interim impairment test, the Nitrogen Fertilizer Partnership elected to perform a qualitative evaluation foras of November 1, 2017. The qualitative analysis included an analysis of the years ended December 31, 2015key drivers and 2014other external factors that may impact the results of operations of the Nitrogen Fertilizer Partnership's Coffeyville Facility to determine whether itif any significant events, transactions or other factors had occurred or are expected to occur that would indicate the fair value of the reporting unit was necessary to perform the quantitative two step goodwill analysis described in ASC 350, "Intangibles - Goodwill and Other." less than its carrying value. After assessing the totality of events and circumstances, it was determined that there were no events or circumstances that would have a significant negative impact to management’s estimates used in the August 31, 2017 goodwill analysis, and therefore, it was not more likely than not that the fair value of the Nitrogen Fertilizer PartnershipPartnership's Coffeyville Facility was less than the carrying value, and sovalue. Based on the results of the tests, it was not necessary to perform the two-stepquantitative goodwill impairment analysis. Based on the results of the tests, no impairment of goodwill was recorded for any of the periods presented.
(7)(9) Insurance Claims
On July 29, 2014, the Refining Partnership's Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employee who was fatally injured. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System, which was directly caused by the fire. The Coffeyville refinery returned to operations in mid-August, with all units except the isomerization unit in operation by August 23, 2014. The isomerization unit started operating on October 12, 2014. This interruption adversely impacted production of refined products for the 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, 2014 were approximately $6.3 million.
The Refining Partnership is covered byhad property damage insurance policies at the time of the incident, which had an associated deductible of $5.0 million for the Coffeyville refinery. The Refining Partnership anticipates amounts in excess of the $5.0 million deductible related to the isomerization unit fire incident will be recoverable under the property insurance policies. As of December 31, 2015 and 2014, the Refining Partnership had an insurance receivable related to the incidentreceived net indemnity of approximately $1.2 million and $1.3 million, respectively, which is included in prepaid expenses and other current assetsfrom insurers for this incident in the Consolidated Balance Sheet.first quarter of 2016. The recording of the receivable resulted in a reduction ofinsurance indemnity reduced direct operating expenses (exclusive of depreciation and amortization).
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
During the outage at the Coffeyville refinery as discussed above, the Refining Partnership accelerated certain planned turnaround activities scheduled for 2015 and incurred approximately $5.5 million in turnaround expenses for the year ended December 31, 2014.
(8)(10) Income Taxes
On May 19, 2012, CVR became a member of the consolidated federal tax group of AEPC,American Entertainment Properties Corporation ("AEPC"), a wholly-owned subsidiary of IEP, and subsequently entered into a tax allocation agreement with AEPC (the "Tax Allocation Agreement"). The Tax Allocation Agreement provides that AEPC will pay all consolidated federal 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, that it would have paid if it were to file as a consolidated group separate and apart from AEPC.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of December 31, 20152017 and 2014,2016, the Company's Consolidated Balance Sheets reflected a receivable of $11.6$5.1 million and $44.5a payable of $10.6 million, respectively, for an overpayment of federal income taxes due toto/from AEPC. The overpayment for 2015 will be applied as a credit against the Company's estimated tax to be paid 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 due to/from parent in the Consolidated Balance Sheets. During the years ended December 31, 2015, 20142017, 2016 and 2013,2015, the Company paid $57.5$15.0 million, $120.1$45.0 million and $260.0$57.5 million, respectively, to AEPC under the Tax Allocation Agreement.
Income tax expense (benefit) is comprised of the following:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Current | | | | | | | | | | |
| Federal | $ | 74.9 |
| | $ | 76.1 |
| | $ | 265.8 |
| $ | (0.7 | ) | | $ | 67.2 |
| | $ | 74.9 |
|
| State | 14.5 |
| | 16.6 |
| | 21.5 |
| (22.1 | ) | | (7.0 | ) | | 14.5 |
|
| Total current | 89.4 |
| | 92.7 |
| | 287.3 |
| (22.8 | ) | | 60.2 |
| | 89.4 |
|
| Deferred | | | | | | | | | | |
| Federal | 2.7 |
| | 8.3 |
| | (93.5 | ) | (181.4 | ) | | (61.0 | ) | | 2.7 |
|
| State | (7.6 | ) | | (3.3 | ) | | (10.1 | ) | (12.7 | ) | | (19.0 | ) | | (7.6 | ) |
| Total deferred | (4.9 | ) | | 5.0 |
| | (103.6 | ) | (194.1 | ) | | (80.0 | ) | | (4.9 | ) |
| Total income tax expense | $ | 84.5 |
| | $ | 97.7 |
| | $ | 183.7 |
| |
| Total income tax expense (benefit) | | $ | (216.9 | ) | | $ | (19.8 | ) | | $ | 84.5 |
|
The following is a reconciliation of total income tax expense (benefit) to income tax expense (benefit) computed by applying the statutory federal income tax rate (35%) to pretax income (loss):
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Tax computed at federal statutory rate | $ | 133.8 |
| | $ | 142.5 |
| | $ | 247.0 |
| $ | 0.0 |
| | $ | (3.8 | ) | | $ | 133.8 |
|
| State income taxes, net of federal tax benefit | 11.7 |
| | 14.0 |
| | 16.5 |
| (15.7 | ) | | (8.0 | ) | | 11.7 |
|
| State tax incentives, net of federal tax expense | (7.2 | ) | | (5.4 | ) | | (9.0 | ) | (6.9 | ) | | (8.8 | ) | | (7.2 | ) |
| Domestic production activities deduction | (5.9 | ) | | (5.5 | ) | | (18.5 | ) | — |
| | (4.3 | ) | | (5.9 | ) |
| Non-deductible share-based compensation | — |
| | 0.2 |
| | 1.5 |
| |
| Noncontrolling interest | (44.9 | ) | | (47.4 | ) | | (53.0 | ) | 6.1 |
| | 5.5 |
| | (44.9 | ) |
| Other, net | (3.0 | ) | | (0.7 | ) | | (0.8 | ) | 0.1 |
| | (0.4 | ) | | (3.0 | ) |
| Total income tax expense | $ | 84.5 |
| | $ | 97.7 |
| | $ | 183.7 |
| |
| Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate | | (200.5 | ) | | — |
| | — |
|
| Total income tax expense (benefit) | | $ | (216.9 | ) | | $ | (19.8 | ) | | $ | 84.5 |
|
The 2017 state benefit is higher than expected due to the release of a portion of the reserve for uncertain tax positions on state credits and the related interest and the change in the value of the deferred tax assets and liabilities due to the reduced state tax rate. The impact of these items on the state income tax benefit, net of federal tax expense is $(14.3) million and $(1.7) million, respectively.
The 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$5.7 million
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
and $7.8$4.3 million on a credit of approximately $6.7$6.6 million, $4.3$8.7 million and $12.0$6.7 million for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively, with respect to the HPIP credits. The Company earns Oklahoma Investment credits for qualified manufacturing facility investment within the state of Oklahoma. CVR recognized a net income tax benefit of approximately $2.9$2.6 million, $2.5$3.1 million and $1.2$2.9 million on a credit of approximately $4.4$4.0 million, $3.9$4.8 million and $1.8$4.4 million for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively, with respect to the Oklahoma Investment credits.
As discussed in Note 2 ("Summary
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of December 31, 2015. 2017, CVR has Kansas state income tax credits of approximately $9.3 million, which are available to reduce future Kansas state income taxes. These credits, if not used, will expire beginning in 2032. Additionally, CVR has Oklahoma state income tax credits of approximately $29.8 million which are available to reduce future Oklahoma state income taxes. These credits have an indefinite life.
The new standard requiresCompany also has a net operating loss carryforward of $27.5 million. The loss, if not used, will expire in 2037.
The income tax benefit for the year ended December 31, 2017 was favorably impacted as a result of the Tax Cuts and Jobs Act (“TCJA”) legislation that allwas signed into law in December 2017, reducing the federal income tax rate from 35% to 21% beginning in 2018. The Company is required to reflect the impact of tax law changes in its consolidated financial statements in the period of enactment. As a result, our net deferred tax liabilities at December 31, 2017 were remeasured to reflect the lower tax rate that will be in effect for the years in which the deferred tax assets and liabilities along with any related valuation allowance,will be classifiedrealized. A benefit of approximately $200.5 million was recognized as noncurrent ona result of the balance sheet. The Company applied the new standard prospectively to the Consolidated Balance Sheet as of December 31, 2015. The reclassification of current deferred income taxes to noncurrent deferred income taxes was not material. The Consolidated Balance Sheet as of December 31, 2014 was not retrospectively adjusted.remeasurement.
The income tax effect of temporary differences that give rise to significant portions of the deferred income tax assets and deferred income tax liabilities at December 31, 20152017 and 20142016 are as follows:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2015 | | 2014 |
| | (in millions) |
| Deferred income tax assets: | | | |
| Personnel accruals | $ | 1.5 |
| | $ | 1.8 |
|
| State tax credit carryforward, net | 11.0 |
| | 12.6 |
|
| Contingent liabilities | 0.1 |
| | 0.1 |
|
| Other | — |
| | 2.1 |
|
| Total gross deferred income tax assets | 12.6 |
| | 16.6 |
|
| Deferred 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. |
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (in millions) |
| Deferred income tax assets: | | | |
| Personnel accruals | $ | — |
| | $ | 1.3 |
|
| State tax credit carryforward, net | 11.3 |
| | 10.5 |
|
| Net operating loss carryforward | 7.2 |
| | — |
|
| Other | — |
| | 0.1 |
|
| Total gross deferred income tax assets | 18.5 |
| | 11.9 |
|
| Deferred income tax liabilities: | | | |
| Personnel accruals | (1.2 | ) | | — |
|
| Property, plant, and equipment | (2.1 | ) | | (3.8 | ) |
| Investment in CVR Partners | (54.6 | ) | | (89.2 | ) |
| Investment in CVR Refining | (345.3 | ) | | (497.8 | ) |
| Prepaid expenses | (0.2 | ) | | (0.3 | ) |
| Other | (1.0 | ) | | (0.7 | ) |
| Total gross deferred income tax liabilities | (404.4 | ) | | (591.8 | ) |
| Net deferred income tax liabilities | $ | (385.9 | ) | | $ | (579.9 | ) |
In assessing the realizability of deferred tax assets including net operating loss and credit carryforwards, management considers whether it is more likely than not that some portion 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 taxable income 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 is more likely than not that all of the deferred tax assets will be realized and thus, no valuation allowance was provided as of December 31, 20152017 and 2014.2016.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
A reconciliation of the unrecognized tax benefits for the years ended December 31, 2015, 20142017, 2016 and 20132015 is as follows:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Balance beginning of year | $ | 55.5 |
| | $ | 45.2 |
| | $ | 36.9 |
| $ | 44.1 |
| | $ | 49.0 |
| | $ | 55.5 |
|
| Increase based on prior year tax positions | — |
| | 0.5 |
| | — |
| — |
| | — |
| | — |
|
| Decrease based on prior year tax positions | — |
| | — |
| | (6.4 | ) | — |
| | — |
| | — |
|
| Increases in current year tax positions | 9.8 |
| | 9.8 |
| | 14.7 |
| — |
| | — |
| | 9.8 |
|
| Settlements | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Reductions related to expirations of statute of limitations | (16.3 | ) | | — |
| | — |
| (15.4 | ) | | (4.9 | ) | | (16.3 | ) |
| Balance end of year | $ | 49.0 |
| | $ | 55.5 |
| | $ | 45.2 |
| $ | 28.7 |
| | $ | 44.1 |
| | $ | 49.0 |
|
Included in the balance of unrecognized tax benefits as of December 31, 2017, 2016 and 2015 2014 and 2013 are $31.8$22.7 million, $25.6$28.7 million and $19.1$31.8 million, respectively, of tax benefits that, if recognized, would affect the effective tax rate. Approximately $15.4 million of the unrecognized tax positions relating to state tax credits were recognized in 2017 as a result of a lapse of statute of limitations. Approximately $4.9 million of the unrecognized tax positions relating to state tax credits were recognized in 2016 as a result of a lapse of statute of limitations. Approximately $16.3 million of the unrecognized tax positions relating to the 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$5.8 million of its unrecognized tax positions relating to state tax credits may be recognized by the end of 20162018 as a result of a lapse of the statute of limitations. Under ASU 2013-11, approximately $25.9Approximately $25.8 million and $13.5$25.7 million of unrecognized tax benefits were netted with deferred tax asset carryforwards as of December 31, 20152017 and 2014,2016, respectively. The remaining unrecognized tax benefits 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. CVR recognized interest expensebenefit of approximately $1.0$7.0 million during 2015. No penalties were recognized during 2015. As of December 31, 2015, CVR2017 and has recognized a liability for interest of approximately $7.5 million. No liability was recognized for penalties in 2015.$1.0 million as of December 31, 2017. In 2014,2016, CVR recognized interest expense of approximately $3.8 million. No penalties were recognized during 2014. As of December 31, 2014, CVR$0.5 million and had recognized a liability for interest of approximately $6.5 million. No liability was recognized for penalties in 2014.$8.0 million as of December 31, 2016. In 2013,2015, CVR recognized interest expense of approximately $2.2 million.$1.0 million and had recognized a liability for interest of approximately $7.5 million as of December 31, 2015. No penalties were recognized during 2013.2017, 2016 or 2015.
At December 31, 2015,2017, the Company's tax filings are generally open to examination in the United States for the tax years ended December 31, 20122014 through December 31, 20142016 and in various individual states for the tax years ended December 31, 20112013 through December 31, 2014.2016.
(9)(11) Long-Term Debt
Long-term debt was as follows:consisted of the following:
| | | | December 31, 2015 | | December 31, 2014 | December 31, 2017 | | December 31, 2016 |
| | (in millions) | (in millions) |
| 6.5% Senior Notes due 2022 | $ | 500.0 |
| | $ | 500.0 |
| $ | 500.0 |
| | $ | 500.0 |
|
| CRNF credit facility | 125.0 |
| | 125.0 |
| |
| 9.25% Senior Secured Notes due 2023 | | 645.0 |
| | 645.0 |
|
| 6.5% Senior Notes due 2021 | | 2.2 |
| | 2.2 |
|
| Capital lease obligations | 48.5 |
| | 49.9 |
| 45.0 |
| | 46.9 |
|
| Total debt | 673.5 |
| | 674.9 |
| 1,192.2 |
| | 1,194.1 |
|
| Current portion of long-term debt and capital lease obligations | (126.6 | ) | | (1.4 | ) | |
| Unamortized debt issuance cost | | (12.2 | ) | | (14.2 | ) |
| Unamortized debt discount | | (13.5 | ) | | (15.3 | ) |
| Current portion of capital lease obligations | | (2.1 | ) | | (1.8 | ) |
| Long-term debt, net of current portion | $ | 546.9 |
| | $ | 673.5 |
| $ | 1,164.4 |
| | $ | 1,162.8 |
|
Old Senior Secured Notes
On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, completed a private offering of $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the "Old Second Lien
CVR Energy, Inc. and Subsidiaries
NOTES 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 the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase 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 Notes
On October 23, 2012, CVR Refining, LLC ("Refining LLC") and Coffeyville Finance Inc. ("Coffeyville Finance") completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party feesare unsecured and expenses associated with the offering. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Old Second Lien Notes, subject to exceptions, until such time that the then outstanding Old Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes are no longer secured. The 2022 Notes 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 and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, the Nitrogen Fertilizer PartnershipCVR Partners and CRNF, a wholly owned subsidiary of the Nitrogen Fertilizer Partnership,their respective subsidiaries 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 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 interest expense using the effective-interest amortization method. On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered exchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Refining Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership incurred approximately $0.4 million of debt registration costs 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 as interest 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-annually on May 1 and November 1 of each year, commencing on May 1, 2013.
The indenture governing the 2022 Notes contain customaryimposes covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets,restrict the ability of the issuers and subsidiary guarantors to dispose(i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, the ability to(iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain payments on contractually subordinated debt, the ability toinvestments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and the ability to(vii) enter into certain affiliate transactions. Thetransactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes provide thatare rated investment grade by both Standard & Poor's Financial Services LLC and Moody's Investors Service, Inc. However, such covenants would be reinstituted if the 2022 Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would result in, 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 other available remedies.
The indenture governing the 2022 Notes prohibits the Refining Partnership can makefrom making distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio and there is nounitholders 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 will apply differently depending on the Refining Partnership'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 Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Refining Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the 2022 Notes. As of December 31, 2015, theindenture. The Refining Partnership was in compliance with the covenants contained inas of December 31, 2017, and the 2022 Notes.ratio was satisfied (not less than 2.5 to 1.0).
Included in other current liabilities on the Consolidated Balance Sheets is accrued interest payable totaling approximately $5.4 million as of both December 31, 20152017 and 20142016 related to the 2022 Notes. At December 31, 2015,2017, the estimated fair value of the 2022 Notes was approximately $485.0$515.0 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.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
Amended and Restated Asset Based (ABL) Credit Facility
On December 20, 2012,November 14, 2017, 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 "AmendedAmendment No. 1 to the Amended and Restated ABL Credit Facility"Agreement (the "Amendment") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amendment amends certain provisions of the Amended and Restated ABL Credit Agreement, dated December 20, 2012, by and among Wells Fargo, the group of lenders party thereto and the Credit Parties (the "Existing Credit Agreement" and as amended by the Amendment, the "Amended and Restated ABL Credit Facility"), which was otherwise schedule to mature on December 20, 2017. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017. Under the Amended and Restated ABL Credit Facility, the Refining Partnership assumed the Company's position as borrower and 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").November 14, 2022.
The Amended and Restated ABL Credit Facility is a senior secured$400.0 million asset-based revolving credit facility, in an aggregate principal amountwith sub-limits for letters of up to $400.0credit and swingline loans of $60.0 million with an incremental facility, which permits an increase in borrowings of up to $200.0and $40.0 million, subject to additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit Parties and their subsidiaries.respectively. The Amended and Restated ABL Credit Facility provides for loansalso includes a $200.0 million uncommitted incremental facility. The Amended and lettersRestated ABL Credit Facility permits the payment of credit in an amount updistributions, subject to the aggregatefollowing conditions: (i) no default or event of default exists, (ii) excess availability underexceeds 15% of the facility, subject to meeting certainlesser of the borrowing base conditions, with sub-limits of 10% ofand the total facility commitmentcommitments, and (iii) the fixed charge coverage ratio for swingline loansthe immediately preceding twelve-month period shall be equal to or greater than 1.00 to 1.00. The Amended and 90% of the total facility commitmentRestated ABL Credit Facility has a five-year maturity and may be used for letters of credit.working capital and other general corporate 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 applicable margin is (i) (a) 1.75%1.50% for LIBOR borrowings and (b) 0.75%0.50% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00%1.75% for LIBOR borrowings and (b) 1.00%0.75% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40%0.375% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30%0.25% 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, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.
The lenders under the Amended and Restated ABL Credit Facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investmentinvestments and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amendedAmended and restated facilityRestated ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. The Credit Parties were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2015.2017.
In connection with the Amended and Restated ABL Credit Facility, CRLLC and its subsidiaries incurred lender and other third-party costs of approximately $2.1$1.6 million for the year ended December 31, 2012,2017, which are being deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. Additionally, in accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $2.8$0.1 million of unamortized deferred financing costs associated with the prior ABL credit facility will continue to be amortized over the term of the Amended and Restated ABL Credit Facility.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
As of December 31, 2015,2017, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $290.1$337.7 million and had letters of credit outstanding of approximately $27.8$28.4 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of December 31, 2015.2017. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of December 31, 2015.2017.
2023 Senior Secured Notes
On June 10, 2016, CVR Partners and CVR Nitrogen Finance Corporation ("CVR Nitrogen Finance"), an indirect wholly-owned subsidiary of CVR Partners (together the "2023 Notes Issuers"), certain subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral trustee, completed a private offering of $645.0 million aggregate principal amount of 9.25% Senior Secured Notes due 2023 (the "2023 Notes"). The 2023 Notes mature on June 15, 2023, unless earlier redeemed or repurchased by the issuers. Interest on the 2023 Notes is payable semi-annually in arrears on June 15 and December 15 of each year. The 2023 Notes are guaranteed on a senior secured basis by all of the Nitrogen Fertilizer Partnership’s existing subsidiaries.
The 2023 Notes were issued at a $16.1 million discount, which is being amortized over the term of the 2023 Notes as interest expense using the effective-interest method. The Nitrogen Fertilizer Partnership received approximately $622.9 million of cash proceeds, net of the original issue discount and underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The net proceeds from the sale of the 2023 Notes were used to: (i) repay all amounts outstanding under the senior term loan credit facility with CRLLC; (ii) finance the repurchase of substantially all of the 2021 Notes (discussed below) and (iii) to pay related fees and expenses.
The debt issuance costs of the 2023 Notes totaled approximately $9.4 million and are being amortized over the term of the 2023 Notes as interest expense using the effective-interest amortization method.
The 2023 Notes contain customary covenants for a financing of this type that, among other things, restrict the Nitrogen Fertilizer Partnership’s ability and the ability of certain of its subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Nitrogen Fertilizer Partnership’s units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the Nitrogen Fertilizer Partnership’s restricted subsidiaries to the Nitrogen Fertilizer Partnership; (vii) consolidate, merge or transfer all or substantially all of the Nitrogen Fertilizer Partnership’s assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. In addition, the indenture contains customary events of default, the occurrence of which would result in, or permit the trustee or the holders of at least 25% of the 2023 Notes to cause, the acceleration of the 2023 Notes, in addition to the pursuit of other available remedies.
The indenture governing the 2023 Notes prohibits the Nitrogen Fertilizer Partnership from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits the Nitrogen Fertilizer Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on the Partnership's fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 1.75 to 1.0, the Nitrogen Fertilizer Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 1.75 to 1.0, the Nitrogen Fertilizer Partnership will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $75.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. As ofDecember 31, 2017, the ratio was less than 1.75 to 1.0. Restricted payments have been made, and $72.7 million of the basket was available as of December 31, 2017. As of December 31, 2017, the Nitrogen Fertilizer Partnership was in compliance with the covenants contained in the 2023 Notes.
Included in other current liabilities on the Consolidated Balance Sheets is accrued interest payable totaling approximately $2.7 million as of December 31, 2017 related to the 2023 Notes. At December 31, 2017, the estimated fair value of the 2023 Notes was approximately $694.2 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.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
2021 Notes
The $320.0 million aggregate principal amount of 6.5% Senior Notes due 2021 (the "2021 Notes") were issued by CVR Nitrogen and CVR Nitrogen Finance (the "2021 Notes Issuers") prior to the East Dubuque Merger. The 2021 Notes bear interest at a rate of 6.5% per annum, payable semi-annually in arrears on April 15 and October 15 of each year. The 2021 Notes are scheduled to mature on April 15, 2021, unless repurchased or redeemed earlier in accordance with their terms. The substantial majority of the 2021 Notes were repurchased in 2016. During year ended December 31, 2016, the Nitrogen Fertilizer Partnership recognized a loss on debt extinguishment of $4.9 million. As of December 31, 2017 and 2016, $2.2 million of principal amount of the 2021 Notes remained outstanding and accrued interest was nominal.
Asset Based (ABL) Credit Facility
On September 30, 2016, the Nitrogen Fertilizer Partnership entered into a senior secured asset based revolving credit facility (the "ABL Credit Facility") with a group of lenders and UBS AG, Stamford Branch ("UBS"), as administrative agent and collateral agent. The ABL Credit Facility has an aggregate principal amount of availability of up to $50.0 million with an incremental facility, which permits an increase in borrowings of up to $25.0 million in the aggregate subject to additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Nitrogen Fertilizer Partnership and its subsidiaries. The ABL Credit Facility provides for loans and standby letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of the lesser of 10% of the total facility commitment and $5.0 million for swingline loans and $10.0 million for letters of credit. The ABL Credit Facility is scheduled to mature on September 30, 2021.
At the option of the borrowers, loans under the ABL Credit Facility initially bear interest at an annual rate equal to (i) 2.00% plus LIBOR or (ii) 1.00% plus a base rate, subject to a 0.50% step-down based on the previous quarter’s excess availability. The borrowers must also pay a commitment fee on the unutilized commitments and also pay customary letter of credit fees.
The ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Nitrogen Fertilizer Partnership and its subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments and loans, enter into affiliate transactions, issue equity interests or create subsidiaries and unrestricted subsidiaries. The ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Nitrogen Fertilizer Partnership was in compliance with the covenants of the ABL Credit Facility as of December 31, 2017.
In connection with the ABL Credit Facility, the Partnership incurred lender and other third party costs of approximately $1.2 million, which are being deferred and amortized to interest expense and other financing costs using the straight line method over the term of the facility.
As of December 31, 2017, the Nitrogen Fertilizer Partnership and its subsidiaries had availability under the ABL Credit Facility of $43.8 million. There were no borrowings outstanding under the ABL Credit Facility as of December 31, 2017. Availability under the ABL Credit Facility was limited by borrowing base conditions as of December 31, 2017.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nitrogen Fertilizer Partnership Credit Facility
The Nitrogen Fertilizer PartnershipOn April 13, 2011, CRNF, as borrower, and CVR Partners, as guarantor, entered into a credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent (the "Credit Agreement"). The Credit Agreement includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. No amounts were outstanding underAt March 31, 2016, the revolving credit facility at December 31, 2015. There is no scheduled amortization. The credit facility matures on April 13, 2016; therefore, the principal portioneffective rate 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 fair value. 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 for Eurodollar 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 the assets of CRNF and the Nitrogen Fertilizer Partnership. At December 31, 2015 the effective rate was approximately 4.60%, inclusive of3.98%. On April 1, 2016, the impact of interest rate 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 contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, sale-leaseback transactions and affiliate 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 there is 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 credit facility and there were no borrowingsrepaid all amounts outstanding under the credit facility.Credit Agreement and the Credit Agreement was terminated.
In connection with the credit facility, the Nitrogen Fertilizer Partnership incurred lender and other third-party costs of approximately $4.8 million for the year 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 as interest 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 the indebtedness outstanding under the Nitrogen Fertilizer Partnership's credit facility. If the credit facility becomes due prior to a refinancing by the Nitrogen Fertilizer Partnership, CRLLC is required to pay the indebtedness pursuant to this guaranty. The Nitrogen Fertilizer Partnership's obligation to repay CRLLC for 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 term will 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 on terms acceptable to the Nitrogen Fertilizer Partnership with a term of greater than one year from the inception of the New Debt.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Deferred Financing Costs
For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, amortization of deferred financing costs reported as interest expense and other financing costs totaled approximately $4.8 million, $3.6 million and $2.8 million, $2.8 million and $2.9 million, respectively.
Estimated amortization of deferred financing costs is as follows:
|
| | | |
| | |
| Year Ending December 31, | Deferred Financing |
| | (in millions) |
| 2016 | $ | 2.2 |
|
| 2017 | 1.8 |
|
| 2018 | 0.9 |
|
| 2019 | 0.9 |
|
| 2020 | 0.9 |
|
| Thereafter | 1.7 |
|
| | $ | 8.4 |
|
Capital Lease Obligations
The Refining Partnership maintains two leases, accounted for as a capital lease and a financefinancial obligation, relatedwhich relate to the Magellan Pipeline Terminals, L.P. ("Magellan Pipeline") and Excel Pipeline LLC ("Excel Pipeline"). The underlying assets and related depreciation wereare included in property, plant and equipment. The capital lease, which relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The leasePipeline, has 166142 months remaining throughof its term and will expire in September 2029. The financing agreementarrangement, which relates to the Magellan Pipeline terminals, bulk terminal and loading facility. Thefacility, has 141 months remaining of its lease has 165 months remainingterm and will expire in September 2029. As of December 31, 2015,2017, the outstanding obligation associated with these arrangements totaled approximately $48.5$45.0 million, of which $46.9$42.9 million is included in long-term liabilities and $1.6$2.1 million is included in current liabilities in the Consolidated Balance Sheets.
Future payments required under capital lease at December 31, 20152017 are as follows:
| | | Year Ending December 31, | Capital Lease | Capital Lease |
| | (in millions) | (in millions) |
| 2016 | $ | 6.4 |
| |
| 2017 | 6.5 |
| |
| 2018 | 6.5 |
| $ | 6.5 |
|
| 2019 | 6.5 |
| 6.5 |
|
| 2020 | 6.5 |
| 6.5 |
|
| 2021 and thereafter | 57.2 |
| |
| 2021 | | 6.5 |
|
| 2022 | | 6.5 |
|
| Thereafter | | 44.2 |
|
| Total future payments | 89.6 |
| 76.7 |
|
| Less: amount representing interest | 41.1 |
| 31.7 |
|
| Present value of future minimum payments | 48.5 |
| 45.0 |
|
| | | |
| Less: current portion | 1.6 |
| 2.1 |
|
| Long-term portion | $ | 46.9 |
| $ | 42.9 |
|
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
(10)(12) Dividends
On January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Dividends are subject to change at the discretion of the board of directors. The Company began paying regular quarterly dividends in the second quarter of 2013. Additionally, the Company declared and paid 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, 20152017 and 2014:2016:
| | | | December 31, 2014 | | March 31, 2015 | | June 30, 2015 | | September 30, 2015 | | Total Dividends Paid in 2015 | December 31, 2016 | | March 31, 2017 | | June 30, 2017 | | September 30, 2017 | | Total Dividends Paid in 2017 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Dividend type | Quarterly |
| | Quarterly |
| | Quarterly |
| | Quarterly |
| | | Quarterly |
| | Quarterly |
| | Quarterly |
| | Quarterly |
| | |
| Amount paid to IEP | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 142.4 |
| $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 142.4 |
|
| Amounts paid to public stockholders | 7.8 |
| | 7.8 |
| | 7.8 |
| | 7.8 |
| | 31.3 |
| 7.8 |
| | 7.8 |
| | 7.8 |
| | 7.8 |
| | 31.3 |
|
| Total amount paid | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 173.7 |
| $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 173.7 |
|
| Per common share | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 2.00 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 2.00 |
|
| Shares outstanding | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | |
| | | | December 31, 2013 | | March 31, 2014 | | June 30, 2014 | | July 17, 2014 | | September 30, 2014 | | Total Dividends
Paid in 2014 | December 31, 2015 | | March 31, 2016 | | June 30, 2016 | | September 30, 2016 | | Total Dividends
Paid in 2016 |
| | (in millions, except per share data) | (in millions, except per share data) |
| Dividend type | Quarterly |
| | Quarterly |
| | Quarterly |
| | Special |
| | Quarterly |
| | | Quarterly |
| | Quarterly |
| | Quarterly |
| | Quarterly |
| | |
| Amount paid to IEP | $ | 53.4 |
| | $ | 53.4 |
| | $ | 53.4 |
| | $ | 142.4 |
| | $ | 53.4 |
| | $ | 356.0 |
| $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 35.6 |
| | $ | 142.4 |
|
| Amounts paid to public stockholders | 11.7 |
| | 11.7 |
| | 11.7 |
| | 31.3 |
| | 11.7 |
| | 78.2 |
| 7.8 |
| | 7.8 |
| | 7.8 |
| | 7.8 |
| | 31.2 |
|
| Total amount paid | $ | 65.1 |
| | $ | 65.1 |
| | $ | 65.1 |
| | $ | 173.7 |
| | $ | 65.1 |
| | $ | 434.2 |
| $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 43.4 |
| | $ | 173.6 |
|
| Per common share | $ | 0.75 |
| | $ | 0.75 |
| | $ | 0.75 |
| | $ | 2.00 |
| | $ | 0.75 |
| | $ | 5.00 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 2.00 |
|
| Shares outstanding | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | |
(11)(13) Earnings Per Share
The computations of the basic and diluted earnings per share for the years ended December 31, 2015, 20142017, 2016 and 20132015 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 - Basic | 86.8 |
| | 86.8 |
| | 86.8 |
|
| Weighted-average shares of common stock outstanding - Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
|
| | | | | | |
| Basic earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
|
| Diluted earnings per share | $ | 1.95 |
| | $ | 2.00 |
| | $ | 4.27 |
|
|
| | | | | | | | | | | |
| | For the Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (in millions, except per share data) |
| Net income attributable to CVR Energy stockholders | $ | 234.4 |
| | $ | 24.7 |
| | $ | 169.6 |
|
| | | | | | |
| Weighted-average shares of common stock outstanding - Basic and Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
|
| | | | | | |
| Basic and Diluted earnings per share | $ | 2.70 |
| | $ | 0.28 |
| | $ | 1.95 |
|
There were no dilutive awards outstanding during the years ended December 31, 2015, 20142017, 2016 and 20132015 as all unvested awards under the LTIP were liability-classified awards. See Note 34 ("Share-Based Compensation").
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
(12)(14) Benefit Plans
CVR sponsors and administers two defined-contribution 401(k) plans, the CVR Energy 401(k) Plan and the CVR Energy 401(k) Plan for Represented Employees (the "Plans"), in which CVR employees may participate. Participants in the Plans may elect to contribute a designated percentage of their eligible compensation in accordance with the Plans, subject to statutory limits. CVR provides a matching contribution of 100% of the first 6% of eligible compensation 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 matching contributions and contain a provision to count service with predecessor organizations. CVR's contributions under the Plans were approximately $7.3$8.5 million, $6.6$8.1 million and $6.1$7.3 million for the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively.
Beginning April 1, 2016 as a result of the East Dubuque Merger, the Nitrogen Fertilizer Partnership acquired the
Rentech Nitrogen GP, LLC Union 401(k) Plan (the "Union Plan"), which was sponsored by CVR Nitrogen GP, LLC. On May 1, 2017, the Union Plan was merged into the CVR Energy 401(k) Plan for Represented Employees. Contributions under the Union Plan were not material.
(13)(15) Commitments and Contingencies
The minimum required payments for CVR's operating lease agreements and unconditional purchase obligations are as follows:
| | | Year Ending December 31, | Operating Leases | | Unconditional Purchase Obligations(1) | Operating Leases | | Unconditional Purchase Obligations(1) |
| | (in millions) | (in millions) |
| 2016 | $ | 8.0 |
| | $ | 141.0 |
| |
| 2017 | 5.5 |
| | 125.6 |
| |
| 2018 | 3.9 |
| | 124.3 |
| $ | 7.4 |
| | $ | 165.0 |
|
| 2019 | 2.1 |
| | 123.5 |
| 6.5 |
| | 124.3 |
|
| 2020 | 1.5 |
| | 107.8 |
| 5.9 |
| | 100.6 |
|
| 2021 | | 5.3 |
| | 89.8 |
|
| 2022 | | 4.8 |
| | 84.7 |
|
| Thereafter | 2.5 |
| | 727.4 |
| 2.4 |
| | 542.7 |
|
| | $ | 23.5 |
| | $ | 1,349.6 |
| $ | 32.3 |
| | $ | 1,107.1 |
|
| |
| (1) | This amount includes approximately $781.5$698.6 million payable ratably over fifteen13 years pursuant to petroleum transportation service agreements between Coffeyville Resources Refining Marketing, LLC ("CRRM")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, 2015,2017, where applicable. 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 twenty20 years on TransCanada's Keystone pipeline system. CRRM began receiving crude 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.dates through 2035. For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, lease expense totaled approximately $8.7$7.6 million, $9.3$8.2 million and $9.4$8.7 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR's option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.
Additionally, in the normal course of business, the Company has long-term commitments to purchase oxygen, nitrogen, electricity, storage capacity, water and pipeline transportation services. For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, total expense of $135.9$209.4 million, $137.8$150.5 million and $126.1$135.9 million, respectively, was incurred related to long-term commitments.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Crude Oil Supply Agreement
On August 31, 2012, CRRM and Vitol Inc. ("Vitol"), entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Refining Partnership's inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2016.2018.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Litigation
From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under, "Environmental, Health, and Safety ("EHS") Matters." Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. It is possible that management's estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management's beliefs or opinions with respect to liability for potential litigation matters will prove to be accurate.
Proxy Matters
On June 21, 2012, Goldman, Sachs & Co. ("GS") filed suit against CVR in state court inThe U.S. Attorney’s office for the Southern District of New York alleging thatcontacted CVR failedEnergy in September 2017 seeking production of information pertaining to pay GS fees allegedly due to GS byour, CVR pursuant to an engagement letter dated March 21, 2012, which accordingRefining’s and Mr. Carl C. Icahn’s activities relating to the RFS and Mr. Icahn’s role as an advisor to the President. We are cooperating with the request and are providing information in response to the subpoena. The U.S. Attorney’s office has not made any claims or allegations set forth in the complaint, provided that GS was engaged by CVR to assist CVRagainst us or Mr. Icahn. We maintain a strong compliance program and, the CVR board of directors in connection with a tender offer for CVR's stock,while no assurances can be made, by Carl C. Icahn and certain of his affiliates. On September 8, 2014, the court (in its decision granting GS's motion for summary judgment against CVR) directed the court clerk to enter judgment 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 paid the 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 to which (i) CVR received settlement proceeds, (ii) the parties executed a mutual release and (iii) CVR’s appeal has been dismissed. The settlement didwe do not believe this inquiry will have a material effectimpact on the consolidatedour business, 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 to DB by CVR pursuant to an engagement letter dated March 23, 2012, which according to the allegations set forth in the complaint, provided that DB was engaged by CVR to assist CVR and the CVR boardcondition, results of directors in connection with a tender offer for CVR's stock made by Carl C. Icahn and certain of his affiliates. On September 8, 2014, the court (in its decision granting DB's motion for summary judgment against CVR) directed the court clerk to enter judgment 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 the judgment 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 to which (i) CVR received settlement proceeds, (ii) the parties executed a mutual release and (iii) CVR’s appeal has been dismissed. The settlement did not have a material effect on the consolidated financial statements.
Rentech Nitrogen Mergers Litigation
On August 29, 2015, Mike Mustard, a purported unitholder of Rentech Nitrogen, filed a class action complaint on behalf of the public unitholders of Rentech Nitrogen against Rentech Nitrogen, Rentech Nitrogen GP, Rentech Nitrogen Holdings, Inc., Rentech, Inc., CVR Partners, DSHC, LLC, Merger Sub 1 and 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 of Delaware (the "Mustard Lawsuit"). The Mustard Lawsuit alleges, among other things, that the consideration offered by CVR Partners is unfair and inadequate and 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 to the unitholders of Rentech Nitrogen, and are engaging in self-dealing. Specifically, the lawsuit alleges that the director defendants: (i) failed to take steps to maximize the value of Rentech Nitrogen to its public shareholders, (ii) failed to properly value Rentech Nitrogen, and (iii) ignoredoperations or did not protect against the 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 their purported 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 of Rentech Nitrogen against Rentech Nitrogen, Rentech Nitrogen GP, CVR Partners, Merger Sub 1 and Merger Sub 2, and the members of the Rentech Nitrogen Board, in the United States District Court for the Central District of California (the "Sloan Lawsuit"). The Sloan Lawsuit alleges, among other things, that the attempted sale of Rentech Nitrogen to
CVR Energy, Inc. and Subsidiaries
NOTES 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 the Rentech Nitrogen Board breached their obligations under the partnership agreement and their implied duty of good faith and fair dealing by causing Rentech Nitrogen to enter into the merger agreement and failing to disclose material information to unitholders of Rentech Nitrogen, (ii) the Rentech Nitrogen Board violated fiduciary duties owed to the unitholders of Rentech Nitrogen based primarily on allegations of inadequate consideration, restrictive deal protection devices and improper disclosure, (iii) each of the defendants aided and abetted in the foregoing breaches described in items (i) and (ii), and (iv) Rentech Nitrogen 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 on improper disclosure contained in the Registration Statement on Form S-4 (Registration No. 333-206982), which was originally filed with the SEC by CVR Partners 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 preliminary state, 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, which could cause the Nitrogen Fertilizer Partnership not to realize some or all of the anticipated benefits of the mergers. No amounts have been recognized in these consolidated 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 the proposed settlement of the lawsuits. While the defendants believe that no supplemental disclosure is required under applicable laws, in order to avoid the burden and expense of further litigation, they have agreed, pursuant to the terms of the MOU, to make certain supplemental disclosures related to the proposed mergers. The MOU contemplates that the parties will enter into a stipulation of settlement. The stipulation of settlement will be subject to customary conditions, including court approval following notice to Rentech Nitrogen's unitholders. In the event that the parties enter into a stipulation of settlement, 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 by unitholders 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 proposed settlement. In addition, in connection with the proposed settlement, the parties contemplate that plaintiffs' counsel will file a petition in the Court for an award 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 the MOU. In the event that the proposed settlement is not approved and such conditions are not satisfied, the defendants will continue to vigorously defend against the allegations in the lawsuits.cash flows.
Property Tax Matter
CRNF received a ten-year property tax abatement from Montgomery County, Kansas (the "County") in connection with the construction of the nitrogen fertilizer plantCoffeyville Fertilizer Facility that expired on December 31, 2007. In connection with the expiration of the abatement, the County reclassified and reassessed CRNF's nitrogen fertilizer plant for property tax purposes. The reclassification and reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 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 the classification and resulting valuation for each of those years to the Kansas Board of Tax Appeals ("BOTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2008 through 2012. The Kansas Court of Appeals, in a memorandum opinion dated August 9, 2013, reversed the BOTA decision in part and remanded the case to BOTA, instructing BOTA 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 been denied.
In March 2015, BOTA concluded that based upon an asset by asset determination, a substantial majority of the assets in dispute will be classified as personal property for the 2008 tax year. CRNF andThe parties stipulated to the County next will submit evidencevalue of valuation to BOTA with respect to the real property, following which BOTA will issueissued its final decision. The County has appealed the decision with respect to classification to the Kansas Court of Appeals. No amounts have been received or recognized in these consolidated financial statements related to the 2008 property tax matter or BOTA'sBOTA’s decision.
CVR Energy, Inc. and Subsidiaries
NOTES 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 property taxes 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, the settlement provides the County will support CRNF's application before BOTA for a ten-year tax exemption for the UAN expansion. Finally, the settlement provides that CRNF will continue its appeal of the 2008 reclassification and reassessment discussed above.
SEC Matter
CVR Energy, Inc. and Subsidiaries
The SEC is conducting an investigation in connection with the Company's disclosures following the announcement of a tender offer for the Company's stock initiated in February 2012. The Company is cooperating with the SEC and has produced, at the SEC's request, documents pertaining to the tender offer and the Company's disclosures.NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Flood, Crude Oil Discharge and Insurance
Crude 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 in preparation 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 of the EPAU.S. Environmental Protection Agency ("EPA") seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard's claim for oversight costs. On September 23, 2011, the United States Department of Justice ("DOJ"), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act's Risk Management Program ("RMP"), the Clean Water Act ("CWA") and the OPA.Oil Pollution Act of 1990 ("OPA"). CRRM reached an agreement with the DOJ resolving its claims 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 and March 25, 2013, respectively (the "2013 Consent Decree"). On April 19, 2013, CRRM paid a civil penalty (including accrued interest) in the amount of $0.6 million 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 Decree also requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training, the majorityall 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 separate consent 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 $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP claims. In 2015, CRRM continued to implementhas completed the implementation of the recommendations of several audits 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 insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. The Court issued summary judgment opinions that eliminated the majority of the insurance defendants' reservations and defenses. CRRM has received $25.0 million of insurance proceeds under its primary environmental liability insurance policy, which constitutes full payment of the primary pollution liability policy limit. During the second quarter of 2015, CRRM entered into a settlement agreement and release with the insurance carriers involved in the lawsuit, pursuant to which (i) CRRM received settlement proceeds of approximately $31.3 million, (ii) the parties mutually released each other from all claims relating to the flood and crude oil discharge and (iii) all pending appeals have been dismissed. Of the settlement proceeds received, $27.3 million were recorded as a flood insurance recovery in the Consolidated Statements of Operations for the year ended December 31, 2015. The remaining $4.0 million of settlement proceeds reduced CVR Refining's $4.0 million receivable related to this matter, which was included in other assets on the Consolidated Balance Sheets as of December 31, 2014.
Environmental, Health, and Safety ("EHS") Matters
The petroleum and nitrogen fertilizer businesses are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
CRRM, CRNF, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Wynnewood Refining Company, LLC ("WRC"), East Dubuque Nitrogen Fertilizers, LLC ("EDNF") and Coffeyville Resources Terminal, LLC ("CRT") own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT, WRC, EDNF and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the OPA generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.
CRRM, CRNF, CRCT, WRC, EDNF and CRT are subject to extensive and frequently changing federal, state and local environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, and the storage, handling, use and transportation of petroleum and nitrogen fertilizer products, and the characteristics and composition of gasoline and diesel fuels. The ultimate impact of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that the Company'sour operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
On August 1, 2016, CRCT received a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (the "NOPV") from the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (the "PHMSA"). The NOPV alleges violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The alleged violations include alleged failures (during various time periods) to (i) conduct quarterly notification drills, (ii) maintain certain required records, (iii) utilize certain required safety equipment (including line markers), (iv) take certain pipeline integrity management activities, (v) conduct certain cathodic protection testing, and (vi) make certain atmospheric corrosion inspections. The preliminary assessed civil penalty is approximately $0.5 million and the NOPV contained a compliance order outlining remedial compliance steps to be undertaken by CRCT. CRCT paid approximately $0.2 million of the preliminary assessed civil penalty in September 2016, and contested and requested mitigation of the remainder, and also requested reconsideration of the proposed compliance order. In November 2017, CRCT received a final order from PHMSA assessing a revised civil penalty of approximately $0.5 million. CRCT paid the remaining $0.3 million in civil penalty and has completed all items required by the compliance order.
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-20 and 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 wastewater conveyance. As of December 31, 20152017 and 2014,2016, environmental accruals of approximately $3.6$3.9 million and $1.1$4.8 million, respectively, were reflected in the Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the ODEQ Consent Order, for which approximately $2.0$1.3 million and $0.2 million, respectively, are included in other current liabilities. Accruals were determined based on an estimate of payment costs through 2026, for which the scope of remediation was arranged with the EPA and ODEQ, and were discounted at the appropriate risk free rates at December 31, 20152017 and 2014,2016, respectively. The accruals include estimated closure and post-closure costs of approximately $0.4 million and $0.9 million for two landfills at December 31, 20152017 and 2014, respectively. 2016.
The estimated future payments for these required obligations are as follows:
| | | Year Ending December 31, | Amount | Amount |
| | (in millions) | (in millions) |
| 2016 | $ | 2.0 |
| |
| 2017 | 0.5 |
| |
| 2018 | 0.5 |
| $ | 2.9 |
|
| 2019 | 0.1 |
| 1.1 |
|
| 2020 | 0.1 |
| — |
|
| 2021 | | — |
|
| 2022 | | — |
|
| Thereafter | 0.5 |
| — |
|
| Undiscounted total | 3.7 |
| 4.0 |
|
| Less amounts representing interest at 1.87% | 0.1 |
| |
| Accrued environmental liabilities at December 31, 2015 | $ | 3.6 |
| |
| Less amounts representing interest at 1.98% | | 0.1 |
|
| Accrued environmental liabilities at December 31, 2017 | | $ | 3.9 |
|
Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Mobile Source Air Toxic II Emissions
In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires the reduction of benzene in gasoline by 2011. The MSAT II projects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. The projects were completed at a total cost of approximately $48.3 million and $89.0 million, excluding capitalized interest, by CRRM and WRC, respectively.
Tier 3 Motor Vehicle Emission and Fuel Standards
In April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which will require that gasoline contain no more than ten parts per million of sulfur on an annual average basis. Refineries mustwere required to be in compliance with the more stringent emission standards byas of January 1, 2017; however, compliance with the rule iswas extended until January 1, 2020 for approved small volume refineries and small refiners. In March 2015, the EPA approved the Wynnewood refinery's application requesting "small volume refinery" status; therefore, itsstatus. In June 2016, because it exceeded the EPA’s specified throughput limit for a “small volume refinery.” the Wynnewood refinery became disqualified as a “small volume refinery.” Therefore, the Wynnewood refinery’s compliance deadline is January 1, 2020.was accelerated to December 21, 2018. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Renewable Fuel Standards
CVR Refining is subject to the Renewable Fuel Standard ("RFS") which requires refiners to either blend "renewable fuels" in with their transportation fuels or purchase renewable fuel credits, known as RINs in lieu of blending. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. transportation fuel market, there may be a decrease in demand for petroleum products. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its transportation fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinery was 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 the open 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 and exceeded the "blend wall." The blend wall refers to the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.
OnIn December 14, 2015, 2016 and 2017, the EPA published in the Federal Register a final rulerules establishing the renewable fuel volume mandates for 2014, 20152016, 2017 and 2016,2018, and the biomass-based diesel mandatevolume mandates for 2017.2017, 2018 and 2019, respectively. The volumes included in the EPA's final rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authorityauthorities to lower the volumes in each rulemaking, but its decision to do so has beenfor the 2014-2016 compliance years was challenged in the U.S. Court of Appeals for the District of Columbia Circuit.Circuit ("D.C. Circuit"). In a July 2017 decision, the D.C. Circuit rejected all challenges to the 2014-2016 compliance years rule except for one, vacated the EPA’s decision to reduce the total renewable fuel volume requirements for 2016 through use of its “inadequate domestic supply” waiver authority, and remanded the rule to the EPA for further consideration. The EPA has not yet proposed a new rule establishing the volume requirements for 2016 following the D.C. Circuit’s opinion. In addition to establishing the renewable volume obligations, the EPA has articulated a policy that high RINs prices incentivize additional investments in renewable fuel blending and distribution infrastructure.
The cost of RINs expense for the years ended December 31, 2015, 20142017, 2016 and 20132015 was approximately $123.9$249.0 million, $127.2$205.9 million and $180.5$123.9 million, respectively. As of December 31, 20152017 and 2014,2016, CVR Refining's biofuel blending obligation was approximately $9.5$28.3 million and $52.3$186.3 million, respectively, which is recorded in other current liabilities in the Consolidated Balance Sheets. 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 difficult to 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 RINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed at its refineries and downstream terminals, all of which can vary significantly from period to period.
Coffeyville Second Consent Decree
In March 2004, CRRM and CRT entered into a Consent Decree (the "2004 Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.'s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, ("SO2"), nitrogen oxides and particulate matter from its FCCUfluid catalytic cracking unit ("FCCU") by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities.
CVR Energy, Inc. and Subsidiaries
NOTES 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 Consent Decree (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second Consent Decree 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 the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a "global settlement" under the EPA's "National Petroleum Refining Initiative." Under the National Petroleum Refining Initiative, the EPA 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.National Emission Standard for Hazardous Air Pollutants ("NESHAP"). The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90%95% of the U.S. refining capacity) entering into consent decrees requiring the payment of civil penalties and the installation of air pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, CRRM was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costsIn March 2016, the United States District Court for the District of complying withKansas approved a modification to the Second Consent Decree are expected to be approximately $44.0 million. Additional incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a several year timeframe.
CRRM has entered intomemorializing an agreement with the EPA and KDHE to modify provisions in the Second Consent Decree relating to the installation of controls to reduce air emissions of sulfur dioxide from the refinery's FCCU. Pursuant to the terms of the modification, CRRM will beis permitted to use alternative means of control to those currently specified in the Second Consent Decree provided it can meet the limits specified in the modification. In consideration for the 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 takeThe additional steps to avoid negative impacts to the Verdigris Riverincremental capital expenditures associated with the original controls. The modification has been signed by CRRM, the EPA and KDHE, and on February 10, 2016, the modification was lodged with the United States District 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 Compliance
WRC entered into aSecond Consent Order with ODEQ in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses certain historic 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 portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costsDecree are expected to be $3.0approximately $0.7 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.
RCRA Compliance Matters
In January 2014, the EPA issued an inspection report to the Wynnewood refinery related to a RCRA compliance evaluation inspection conducted in March 2013. In February 2014, ODEQ notified WRC that it concurred with the EPA's inspection findings and would be pursuing enforcement. WRC and ODEQ entered into a Consent Order in June 2015 resolving all alleged non-compliance associated with the RCRA compliance evaluation inspection, as well as issues related to possible soil and groundwater contamination associated with the prior owner's operation of the refinery. The Consent Order requires WRC to take certain corrective actions, including specified groundwater remediation and monitoring measures pursuant to a work plan and replacement of a wastewater conveyance to be approved by ODEQ. CVR Refining does not anticipate thatODEQ approved the work plan submitted by WRC on February 1, 2016 and the replacement of a wastewater conveyance on August 15, 2016. WRC is in the process of implementing the specified groundwater remediation and monitoring measures. The costs of complying with the Consent Order willare estimated to be material.approximately $4.2 million.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, capital expenditures were approximately $35.7$15.6 million, $100.6$17.2 million and $111.3$35.7 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.
CRRM, CRNF, CRCT, WRC, EDNF and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Wynnewood Refinery Incident
On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit during startup after a short outage as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler. Additionally, there has beenwas no evidence of environmental impact. The refinery was in the final stages of shutdown for turnaround maintenance at the time of the incident. The petroleum businessWRC completed an internal investigation of the incident and cooperated with OSHAthe Occupational Safety and Health Administration ("OSHA") in its investigation. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its Severe Violators Enforcement Program ("SVEP"). WRC is vigorously contesting the citations and OSHA's placement of WRC in the SVEP. Any penalties associated with OSHA's citations are not expected to have a material adverse effect on the consolidated financial statements. In addition to the above, the spouses
CVR Energy, in Fort Bend County, Texas. The companies will vigorously defend the suit. It is currently too early to assess a potential outcome in the matter.Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Affiliate Pension Obligations
Mr. Carl C. 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 for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability 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 may result 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 the controlled 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 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 of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of December 31, 2015.2017. If the ACF and Federal-Mogul plans were voluntarily terminated, they would be collectively underfunded by approximately $589.2$423.7 million and $473.8$613.4 million as of December 31, 20152017 and 2014,2016, respectively. These results are based on the most recent information provided by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate the liability. As members of the controlled group, CVR Energy would be liable for any failure of ACF and Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes CVR Energy may have pension plan obligations that are, or may become, underfunded, and the Company would be liable for any failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain "reportable events," such as if CVR Energy were to cease to be a member of the controlled group, or if CVR Energy makes certain extraordinary dividends or stock redemptions. The obligation to report could cause the Company to seek to delay or reconsider the occurrence of such reportable events. Based on the contingent nature of potential exposure related to these affiliate pension obligations, no liability has been recorded in the consolidated financial statements.
(14)(16) Fair Value Measurements
In accordance with FASB ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820") established a single authoritative definition of fair value when accounting rules require, the use of fair value, set out a framework for measuring fair value and required additional disclosures about fair value measurements. ASC 820 clarifies that fair value is an exit price, representing the amount from the perspective of a market participant that holds the asset or owes the liability at the measurement date.
ASC 820 discusses valuation techniques, such asCompany utilizes the market approach (pricesto measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets andor liabilities, such as a business), the income approach (techniques to convert future amounts to a single current amount based on market expectations about those future amounts including present value techniques and option pricing), and the cost approach (amount that would be
CVR Energy, Inc. and Subsidiaries
NOTES 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 that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
Level 1 — Quoted prices in active markets for identical assets andor 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)
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of December 31, 20152017 and 2014:2016:
| | | | December 31, 2015 | December 31, 2017 |
| | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
| | (in millions) | (in millions) |
| Location and Description | | | | | | | | | | | | | | |
| Cash equivalents | $ | 15.7 |
| | $ | — |
| | $ | — |
| | $ | 15.7 |
| $ | 15.2 |
| | $ | — |
| | $ | — |
| | $ | 15.2 |
|
| Other current assets (investments) | 0.1 |
| | — |
| | — |
| | 0.1 |
| 0.1 |
| | — |
| | — |
| | 0.1 |
|
| Other current assets (other derivative agreements) | — |
| | 44.7 |
| | — |
| | 44.7 |
| |
| Total Assets | $ | 15.8 |
| | $ | 44.7 |
| | $ | — |
| | $ | 60.5 |
| $ | 15.3 |
| | $ | — |
| | $ | — |
| | $ | 15.3 |
|
| Other 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 | ) | |
| Other current liabilities (derivative agreements) | | $ | — |
| | $ | (64.3 | ) | | $ | — |
| | $ | (64.3 | ) |
| Other current liabilities (biofuel blending obligation) | | — |
| | (1.0 | ) | | — |
| | (1.0 | ) |
| Total Liabilities | $ | — |
| | $ | (2.9 | ) | | $ | — |
| | $ | (2.9 | ) | $ | — |
| | $ | (65.3 | ) | | $ | — |
| | $ | (65.3 | ) |
| | | | December 31, 2014 | December 31, 2016 |
| | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
| | (in millions) | (in millions) |
| Location and Description | | | | | | | | | | | | | | |
| Cash equivalents | $ | 69.0 |
| | $ | — |
| | $ | — |
| | $ | 69.0 |
| $ | 15.8 |
| | $ | — |
| | $ | — |
| | $ | 15.8 |
|
| Other current assets (investments) | 73.9 |
| | 2.7 |
| | — |
| | 76.6 |
| 0.1 |
| | — |
| | — |
| | 0.1 |
|
| Other current assets (other derivative agreements) | — |
| | 25.0 |
| | — |
| | 25.0 |
| |
| Other long-term assets (other derivative agreements) | — |
| | 22.3 |
| | — |
| | 22.3 |
| |
| Total Assets | $ | 142.9 |
| | $ | 50.0 |
| | $ | — |
| | $ | 192.9 |
| $ | 15.9 |
| | $ | — |
| | $ | — |
| | $ | 15.9 |
|
| Other 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 | ) | |
| Other current liabilities (derivative agreements) | | $ | — |
| | $ | (11.1 | ) | | $ | — |
| | $ | (11.1 | ) |
| Other current liabilities (biofuel blending obligation & benzene obligation) | | — |
| | (187.0 | ) | | — |
| | (187.0 | ) |
| Total Liabilities | $ | — |
| | $ | (50.6 | ) | | $ | — |
| | $ | (50.6 | ) | $ | — |
| | $ | (198.1 | ) | | $ | — |
| | $ | (198.1 | ) |
As of December 31, 20152017 and 2014,2016, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company's cash equivalents, investments, derivative instruments, and uncommitted biofuel blending obligation.obligation and benzene obligations. Additionally, the fair value of the Company's debt issuances is disclosed in Note 911 ("Long-Term Debt"). The Refining Partnership's commodity derivative contracts, andthe uncommitted biofuel blending obligation and the benzene obligation, which use fair value measurements and are valued using broker quoted market prices of similar instruments, are considered Level 2 inputs. The Nitrogen Fertilizer Partnership 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 swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives,
CVR Energy, Inc. and Subsidiaries
NOTES 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 liabilities between any of the above levels during the year ended December 31, 2015.2017.
AsIn March 2016, CVR Energy purchased 400,000 CVR Nitrogen common units in the public market. During the first quarter of December 31, 2014,2016, the aggregate cost basisfair value of the common units was based on quoted prices for the Company's available-for-saleidentical securities (Level 1 inputs). As a result of the East Dubuque Merger, the carrying amount of the investment in the CVR Nitrogen common units was approximately $73.6 million followingreclassified as an other-than-temporary impairment of $4.7 millioninvestment in consolidated subsidiary and is eliminated in consolidation. Subsequent to the East Dubuque Merger, the Nitrogen Fertilizer Partnership purchased the 400,000 CVR Nitrogen common units from CVR Energy during the year ended December 31, 2014.second quarter of 2016. During the year ended December 31, 2015,2016, the Company purchased shares of an unaffiliated public company's common units in the public market at an aggregate cost basis of $14.4 million. During 2016, the Company received proceeds of $68.0$19.3 million for the sale of a portion of itsthis investment in available-for-sale securities. The aggregate cost basis for the available-for-sale securities sold was approximately $47.9 million. Upon the sale of the available-for-sale securities, the Company reclassified an unrealized gain of $20.1$0.5 million from AOCIaccumulated other comprehensive income ("AOCI") and recognized a realized gain of $4.9 million in other income in the Consolidated Statements of Operations for the year ended December 31, 2015. At the 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 were reclassified 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 of Operations 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.2016.
During the year ended December 31, 2013, the Company received proceeds
CVR Energy, Inc. 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.Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(15)(17) Derivative Financial Instruments
Gain (loss) on derivatives, net and currentCurrent period settlements on derivative contracts and Loss on derivatives, net were as follows:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Current period settlement on derivative contracts | $ | (26.0 | ) | | $ | 122.2 |
| | $ | 6.4 |
| $ | (16.6 | ) | | $ | 36.4 |
| | $ | (26.0 | ) |
| Gain (loss) on derivatives, net | (28.6 | ) | | 185.6 |
| | 57.1 |
| |
| Loss on derivatives, net | | (69.8 | ) | | (19.4 | ) | | (28.6 | ) |
The Refining Partnership and Nitrogen Fertilizer Partnership are subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, 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 derivative financial 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 for GAAP purposes.under GAAP. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Consolidated Statements of Operations. There are no premiums paid or received at inception of the derivative contracts and upon settlement, 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 funds available for withdrawal. These funds are included in cash and cash equivalents within the Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Consolidated Balance Sheets. Dependent upon the position of the open commodity derivatives, the amounts are accounted for as other current assets or other current liabilities within the Consolidated Balance Sheets. From time to time, the Refining Partnership may be required to deposit additional funds into this margin account. There were no open commodity positions as of December 31, 20152017 or 2014.2016. For the years ended December 31, 2017, 2016 and 2015, 2014 and 2013, the CompanyRefining Partnership recognized a net gainsloss of $3.2$0.5 million, and $0.3a net loss of $0.5 million, and a net lossgain of $2.9$3.2 million, respectively, which are recorded in gain (loss)loss on derivatives, net in the Consolidated Statements of Operations.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
Commodity Swaps
The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, the Refining Partnership 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 are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheets with 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, 20152017, the Refining Partnership had open commodity swap instruments consisting of 7.1 million barrels of 2-1-1 crack spreads, 3.6 million barrels of distillate crack spreads, and 2014,3.6 million barrels of gasoline crack spreads. Additionally, as of December 31, 2017, CVR Refining had open forward purchase and sale commitments for 5.8 million barrels of Canadian crude oil priced at fixed differentials that are not considered probable of physical settlement and are accounted for as derivatives at December 31, 2017. At December 31, 2016, the Refining Partnership had open commodity hedging instruments consisting of 2.5 million and 9.14.0 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 had open 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 a portion of its future product sales. The fair value of the outstanding contracts at December 31, 20152017 was a net unrealized gainloss of $44.6$64.3 million, of which $44.7 million is included in current assets and $0.1 millionthe entire balance is included in other current liabilities. The fair value of the outstanding contracts at December 31, 20142016 was a net unrealized gainloss of $47.3$11.1 million, of which $25.0 million is included in current assets and $22.3 millionentire balance is included in other long-term assets.current liabilities. For the years ended December 31, 2015, 20142017, 2016 and 2013,2015, the Refining Partnership recognized a net loss of $36.4$69.3 million, $18.9 million and net gains of $187.4 million and $60.1$36.4 million, respectively, which are recorded in gain (loss)loss on derivatives, net in the Consolidated Statements of Operations.
Nitrogen Fertilizer Partnership Interest Rate Swaps
CRNF has two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer 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 of the 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 a fixed 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 of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit facility. The agreements were designated 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, and will be reclassified into interest expense when the interest rate swap transaction affects earnings. Any ineffective portion of the gain or loss will be recognized immediately 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 of Operations 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, the Nitrogen 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 Risk
The Refining Partnership's exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. The Refining Partnership manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. The Refining Partnership also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Consolidated Balance Sheets. As of December 31, 2015,2017, the counterparty credit risk adjustment was not material to the consolidated financial statements. Additionally, the Refining Partnership does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Offsetting Assets and Liabilities
The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which the Refining Partnership has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by the Refining Partnership. As a result of the right to setoff, the Refining Partnership's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Consolidated Balance Sheets. The interest rate swap agreements held by the Nitrogen Fertilizer Partnership 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 Consolidated Balance Sheets as of December 31, 2015 and 2014. In accordance with guidance issued by the FASB related to "Disclosures about Offsetting Assets and Liabilities," the tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Consolidated Balance Sheets for the various types of open derivative positions at the Refining Partnership.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 20152017 and 2016 are recorded as current assets and current liabilities in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively, in the Consolidated Balance Sheets as follows:
| | | | As of December 31, 2015 | As of December 31, 2017 |
| Description | Gross Current Assets | | Gross Amounts Offset | | Net Current Assets Presented | | Cash Collateral Not Offset | | Net Amount | Gross Current Assets | | Gross Amounts Offset | | Net Current Assets Presented | | Cash Collateral Not Offset | | Net Amount |
| | (in millions) | (in millions) |
| Commodity Swaps | $ | 44.8 |
| | $ | (0.1 | ) | | $ | 44.7 |
| | $ | — |
| | $ | 44.7 |
| $ | 7.0 |
| | $ | (7.0 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Total | $ | 44.8 |
| | $ | (0.1 | ) | | $ | 44.7 |
| | $ | — |
| | $ | 44.7 |
| $ | 7.0 |
| | $ | (7.0 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | | | | | |
| | As of December 31, 2015 |
| Description | Gross Current Liabilities | | Gross Amounts Offset | | Net Current Liabilities Presented | | Cash Collateral Not Offset | | Net Amount |
| | (in millions) |
| Commodity Swaps | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
|
| Total | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
| | $ | — |
| | $ | 0.1 |
|
The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2014 are recorded as current assets and non-current assets in prepaid expenses and other current assets and other long-term assets, respectively, in the Consolidated Balance Sheets as follows:
| | | | As of December 31, 2014 | As of December 31, 2017 |
| Description | Gross Current Assets | | Gross Amounts Offset | | Net Current Assets Presented | | Cash Collateral Not Offset | | Net Amount | Gross Current Liabilities | | Gross Amounts Offset | | Net Current Liabilities Presented | | Cash Collateral Not Offset | | Net Amount |
| | (in millions) | (in millions) |
| Commodity Swaps | $ | 25.3 |
| | $ | (0.3 | ) | | $ | 25.0 |
| | $ | — |
| | $ | 25.0 |
| $ | 71.3 |
| | $ | (7.0 | ) | | $ | 64.3 |
| | $ | — |
| | $ | 64.3 |
|
| Total | $ | 25.3 |
| | $ | (0.3 | ) | | $ | 25.0 |
| | $ | — |
| | $ | 25.0 |
| $ | 71.3 |
| | $ | (7.0 | ) | | $ | 64.3 |
| | $ | — |
| | $ | 64.3 |
|
| | | | As of December 31, 2014 | As of December 31, 2016 |
| Description | Gross Non-Current Assets | | Gross Amounts Offset | | Net Non-Current Assets Presented | | Cash Collateral Not Offset | | Net Amount | Gross Current Liabilities | | Gross Amounts Offset | | Net Current Liabilities Presented | | Cash Collateral Not Offset | | Net Amount |
| | (in millions) | (in millions) |
| Commodity Swaps | $ | 22.3 |
| | $ | — |
| | $ | 22.3 |
| | $ | — |
| | $ | 22.3 |
| $ | 11.1 |
| | $ | — |
| | $ | 11.1 |
| | $ | — |
| | $ | 11.1 |
|
| Total | $ | 22.3 |
| | $ | — |
| | $ | 22.3 |
| | $ | — |
| | $ | 22.3 |
| $ | 11.1 |
| | $ | — |
| | $ | 11.1 |
| | $ | — |
| | $ | 11.1 |
|
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(16)(18) Related Party Transactions
In 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 the Company's common stock. As of December 31, 2015,2017, IEP owned approximately 82% of all common shares outstanding. See Note 1 ("Organization and History of the Company") for additional discussion.
American Railcar EntitiesLease Agreements and Maintenance
From March 2009 until June 2013, the Company, through theThe Nitrogen Fertilizer Partnership leased 199has agreements to lease a total of 115 UAN railcars from American Railcar Leasing, LLC ("ARL"), a company controlled by IEP,IEP. The lease agreements will expire in 2023. In the Company's majority stockholder. On June 13, 2013,second quarter of 2017, the Nitrogen Fertilizer Partnership purchased theentered into an agreement to lease an additional 70 UAN railcars under the lease from ARL for approximately $5.0 million.which will expire in 2022. The Nitrogen Fertilizer Partnership received the additional 70 leased railcars during the second half of 2017. For the year ended December 31, 2013,2017 and 2016, rent expense of $0.4approximately $1.0 million and $0.3 million, respectively, was recorded related to this agreement and was included in cost of product sold (exclusive of depreciationmaterials and amortization)other in the Consolidated Statements of Operations.Operations related to these agreements.
In 2014, the Nitrogen Fertilizer Partnership purchased 50 new UAN railcars from American Railcar Industries, Inc. ("ARI"), an affiliate ofa company controlled by IEP, for approximately $6.7 million and 12 used UAN railcars from ARL for approximately $1.1 million. Also, ARI performed railcar maintenance for the Nitrogen Fertilizer Partnership and the expensesexpense associated with this maintenance werewas approximately $50,000$0.2 million for the year ended December 31, 2014.2017 and was included in cost of materials and other in the Consolidated Statement of Operations.
International Truck Purchase
During the year ended December 31, 2013, the Refining Partnership purchased seven trucks from a subsidiary of Navistar International Corporation for approximately $0.8 million.
Tax Allocation Agreement
CVR 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 810 ("Income Taxes") for a discussion of related party transactions under the Tax Allocation Agreement.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Insight Portfolio Group
Insight 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 with which 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 and agreed to pay a portion of Insight Portfolio Group's operating expenses in 2013. The Company paid Insight Portfolio Group approximately $0.1$0.2 million, $0.4$0.2 million and $0.1 million during the years ended December 31, 2015, 20142017, 2016 and 2013,2015, respectively. The Company may purchase a variety of goods and services as members of the buying group at prices and terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.
CRLLC GuarantyFacility with the Nitrogen Fertilizer Partnership
On February 9,April 1, 2016, CRLLC andin connection with the closing of the East Dubuque Merger, the Nitrogen Fertilizer Partnership entered into a guaranty, pursuant$300.0 million senior term loan credit facility (the "CRLLC Facility") with CRLLC as the lender, the proceeds of which were used by the Nitrogen Fertilizer Partnership (i) to which CRLLC agreedfund the repayment of amounts outstanding under the Wells Fargo Credit Agreement discussed in Note 3 ("Acquisition") (ii) to guarantypay the indebtednesscash consideration and to pay fees and expenses in connection with the East Dubuque Merger and related transactions and (iii) to repay all of the loans outstanding under the Nitrogen Fertilizer Partnership'sPartnership credit facility. The CRLLC Facility had a term of two years and an interest rate of 12.0% per annum. Interest was calculated on the basis of the actual number of days elapsed over a 360-day year and payable quarterly. In April 2016, the Nitrogen Fertilizer Partnership borrowed $300.0 million under the CRLLC Facility. On June 10, 2016, the Nitrogen Fertilizer Partnership paid off the $300.0 million outstanding under the CRLLC Facility, paid $7.0 million in interest and terminated the CRLLC Facility.
Joint Venture Agreements
The Refining Partnership holds a 40% and 50% interest in the VPP and Midway joint ventures, respectively. The joint ventures provide the Refining Partnership with crude oil transportation services. Refer to Note 97 ("Long-Term Debt"Equity Method Investments") for furtheradditional discussion of the guaranty terms.joint ventures.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(17)(19) Business Segments
Operating segments are defined in FASB ASC Topic 280 - Segment Reporting, as components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker, or decision-making group, in deciding how to allocate resources and in assessing performance. The Company measures segment profit as operating income for petroleum and nitrogen fertilizer, CVR's two reporting segments, based onsegments. All intercompany transactions are eliminated in the definitions provided in ASC Topic 280 — Segment Reporting.other segment as described below. All operations of the segments are located within the United States.
Petroleum
Principal products of the petroleum segment are refined fuels, propane,include gasoline, diesel fuel, jet fuel, natural gas liquids, asphalt and petroleum refining by-products, including pet coke.petroleum coke, which are sold to retailers, petroleum jobbers, railroads and other refiners/marketers. The petroleum segment's Coffeyville refinerysegment also sells pethydrogen and petroleum coke to the Nitrogen Fertilizer Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For the petroleum segment, a per-ton transfer price is used to record intercompany sales on the part of the petroleum segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the nitrogen fertilizer segment. The per ton transfer price paid, pursuant to the 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 the nitrogen fertilizer segment for UAN (subjectpursuant to a UAN based price ceiling and floor) or a pet coke price index for pet coke. Theseparate intercompany transactions are eliminated in the other segment.agreements. Intercompany sales included in petroleum net sales were approximately $6.8 million, $8.7 million and $9.6 million for the years ended December 31, 2015, 2014 and 2013, respectively.are eliminated in consolidation.
The petroleum segment recordedmay also purchase hydrogen from the nitrogen fertilizer segment under an intercompany feedstock and shared services agreement. Receipts of hydrogen from the nitrogen fertilizer segment are reported in petroleum cost of product sold (exclusivematerials and other and are eliminated in consolidation.
CVR Energy, Inc. and amortization) for the hydrogen purchases described below 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.Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nitrogen Fertilizer
The principal product of the nitrogen fertilizer segment is nitrogen fertilizer. Intercompany costNitrogen fertilizer is used by farmers to improve the yield and quality of product sold (exclusive of depreciationtheir crops, primarily corn and amortization) 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 andwheat. The nitrogen fertilizer plant. Sales of hydrogensegment principally produces UAN. The nitrogen fertilizer segment’s product sales are sold on a wholesale basis in North America. Intercompany sales to the petroleum segment have been reflected asare primarily hydrogen sales pursuant to the feedstock and shared services agreement. The nitrogen fertilizer segment also receives income from subleasing railcars to the petroleum segment’s refineries. All intercompany sales included in nitrogen fertilizer net sales forare eliminated in consolidation.
As described above, the nitrogen fertilizer segment purchases hydrogen and petroleum coke from the petroleum segment. Receipts of hydrogen and petroleum coke from the petroleum segment have been reflectedare reported in nitrogen fertilizer cost of product sold (exclusive of depreciationmaterials and amortization) for the nitrogen fertilizer segment. For the years ended December 31, 2015, 2014other 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 sold related to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated there is no financial statement impact on the consolidated financial statements.in consolidation.
Other Segment
The other segment reflects intercompany eliminations, corporate cash and cash equivalents, income tax activities and other corporate activities that are not allocated to the operating segments.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
The following table summarizes certain operating results and capital expenditures information by segment:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Net sales | | | | | | | | | | |
| Petroleum | $ | 5,161.9 |
| | $ | 8,829.7 |
| | $ | 8,683.5 |
| $ | 5,664.2 |
| | $ | 4,431.3 |
| | $ | 5,161.9 |
|
| Nitrogen Fertilizer | 289.2 |
| | 298.7 |
| | 323.7 |
| 330.8 |
| | 356.3 |
| | 289.2 |
|
| Intersegment elimination | (18.6 | ) | | (18.9 | ) | | (21.4 | ) | (6.6 | ) | | (5.2 | ) | | (18.6 | ) |
| Total | $ | 5,432.5 |
| | $ | 9,109.5 |
| | $ | 8,985.8 |
| $ | 5,988.4 |
| | $ | 4,782.4 |
| | $ | 5,432.5 |
|
| Cost of product sold (exclusive of depreciation and amortization) | | | | | | |
| Cost of materials and other | | | | | | |
| Petroleum | $ | 4,143.6 |
| | $ | 8,013.4 |
| | $ | 7,526.7 |
| $ | 4,804.7 |
| | $ | 3,759.2 |
| | $ | 4,143.6 |
|
| Nitrogen Fertilizer | 65.2 |
| | 72.0 |
| | 58.1 |
| 84.9 |
| | 93.7 |
| | 65.2 |
|
| Intersegment elimination | (18.4 | ) | | (19.4 | ) | | (21.6 | ) | (6.7 | ) | | (5.4 | ) | | (18.4 | ) |
| Total | $ | 4,190.4 |
| | $ | 8,066.0 |
| | $ | 7,563.2 |
| $ | 4,882.9 |
| | $ | 3,847.5 |
| | $ | 4,190.4 |
|
| Direct operating expenses (exclusive of depreciation and amortization) | | | | | | | | | | |
| Petroleum | $ | 478.5 |
| | $ | 416.0 |
| | $ | 361.7 |
| $ | 443.8 |
| | $ | 393.4 |
| | $ | 478.5 |
|
| Nitrogen Fertilizer | 106.1 |
| | 98.9 |
| | 94.1 |
| 155.5 |
| | 148.3 |
| | 106.1 |
|
| Other | 0.1 |
| | 0.2 |
| | — |
| 0.2 |
| | 0.1 |
| | 0.1 |
|
| Total | $ | 584.7 |
| | $ | 515.1 |
| | $ | 455.8 |
| $ | 599.5 |
| | $ | 541.8 |
| | $ | 584.7 |
|
| Depreciation and amortization | | | | | | | | | | |
| Petroleum | $ | 130.2 |
| | $ | 122.5 |
| | $ | 114.3 |
| $ | 133.1 |
| | $ | 129.0 |
| | $ | 130.2 |
|
| Nitrogen Fertilizer | 28.4 |
| | 27.3 |
| | 25.6 |
| 74.0 |
| | 58.2 |
| | 28.4 |
|
| Other | 5.5 |
| | 4.6 |
| | 2.9 |
| 6.9 |
| | 5.9 |
| | 5.5 |
|
| Total | $ | 164.1 |
| | $ | 154.4 |
| | $ | 142.8 |
| $ | 214.0 |
| | $ | 193.1 |
| | $ | 164.1 |
|
| Operating income | | | | | | |
| Operating income (loss) | | | | | | |
| Petroleum | $ | 361.7 |
| | $ | 207.2 |
| | $ | 603.0 |
| $ | 203.8 |
| | $ | 77.8 |
| | $ | 361.7 |
|
| Nitrogen Fertilizer | 68.7 |
| | 82.8 |
| | 124.9 |
| (9.2 | ) | | 26.8 |
| | 68.7 |
|
| Other | (8.8 | ) | | (25.7 | ) | | (17.4 | ) | (16.8 | ) | | (13.7 | ) | | (8.8 | ) |
| Total | $ | 421.6 |
| | $ | 264.3 |
| | $ | 710.5 |
| $ | 177.8 |
| | $ | 90.9 |
| | $ | 421.6 |
|
| Capital expenditures | | | | | | | | | | |
| Petroleum | $ | 194.7 |
| | $ | 191.3 |
| | $ | 204.5 |
| $ | 99.7 |
| | $ | 102.3 |
| | $ | 194.7 |
|
| Nitrogen fertilizer | 17.0 |
| | 21.1 |
| | 43.8 |
| 14.5 |
| | 23.2 |
| | 17.0 |
|
| Other | 7.0 |
| | 6.0 |
| | 8.2 |
| 4.4 |
| | 7.2 |
| | 7.0 |
|
| Total | $ | 218.7 |
| | $ | 218.4 |
| | $ | 256.5 |
| $ | 118.6 |
| | $ | 132.7 |
| | $ | 218.7 |
|
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| | (in millions) | (in millions) |
| Total assets | | | | | | | | | | |
| Petroleum | $ | 2,195.2 |
| | $ | 2,417.8 |
| | $ | 2,533.3 |
| $ | 2,269.9 |
| | $ | 2,331.9 |
| | $ | 2,189.0 |
|
| Nitrogen Fertilizer | 536.5 |
| | 578.8 |
| | 593.5 |
| 1,234.3 |
| | 1,312.2 |
| | 536.3 |
|
| Other | 574.1 |
| | 465.9 |
| | 539.0 |
| 302.5 |
| | 406.1 |
| | 574.1 |
|
| Total | $ | 3,305.8 |
| | $ | 3,462.5 |
| | $ | 3,665.8 |
| $ | 3,806.7 |
| | $ | 4,050.2 |
| | $ | 3,299.4 |
|
| Goodwill | | | | | | | | | | |
| Petroleum | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | — |
|
| Nitrogen Fertilizer | 41.0 |
| | 41.0 |
| | 41.0 |
| 41.0 |
| | 41.0 |
| | 41.0 |
|
| Other | — |
| | — |
| | — |
| — |
| | — |
| | — |
|
| Total | $ | 41.0 |
| | $ | 41.0 |
| | $ | 41.0 |
| $ | 41.0 |
| | $ | 41.0 |
| | $ | 41.0 |
|
(18)(20) Major Customers and Suppliers
Sales to major customers as a percentage of the respective segment's sales were as follows:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Petroleum | | | | | | | | | | |
| Customer A | 14 | % | | 13 | % | | 12 | % | 19 | % | | 15 | % | | 14 | % |
| Nitrogen Fertilizer | | | | | | | | | | |
| Customer B | 10 | % | | 17 | % | | 15 | % | 5 | % | | 10 | % | | 10 | % |
| Customer C | 14 | % | | 10 | % | | 13 | % | 11 | % | | 10 | % | | 14 | % |
| | 24 | % | | 27 | % | | 28 | % | 16 | % | | 20 | % | | 24 | % |
The petroleum segment obtained crude oil from one third-party supplier under a long-term supply agreement during 2015, 20142017, 2016 and 2013. The crude oil purchased from this supplier is governed by a long-term contract.2015. Volume contracted as a percentage of the total crude oil purchases (in barrels) for each of the periods was as follows:
| | | | Year Ended December 31, | Year Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2017 | | 2016 | | 2015 |
| Petroleum | | | | | | | | | | |
| Supplier A | 61 | % | | 67 | % | | 69 | % | 55 | % | | 61 | % | | 61 | % |
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
(19)(21) Selected Quarterly Financial Information (unaudited)
Summarized quarterly financial data for December 31, 20152017 and 2014.2016 is as follows:
| | | | Year Ended December 31, 2015 | Year Ended December 31, 2017 |
| | Quarter | Quarter |
| | First | | Second | | Third | | Fourth | First | | Second | | Third | | Fourth |
| | (in millions, except per share data) | (in millions, except per share data) |
| Net sales | $ | 1,388.9 |
| | $ | 1,624.2 |
| | $ | 1,408.8 |
| | $ | 1,010.6 |
| $ | 1,507.1 |
| | $ | 1,434.4 |
| | $ | 1,453.8 |
| | $ | 1,593.1 |
|
| Operating costs and expenses: | | | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | 1,073.6 |
| | 1,192.2 |
| | 1,076.7 |
| | 847.9 |
| |
| Direct operating expenses (exclusive of depreciation and amortization) | 111.4 |
| | 115.4 |
| | 145.8 |
| | 212.1 |
| |
| Flood insurance recovery | — |
| | (27.3 | ) | | — |
| | — |
| |
| Selling, general and administrative (exclusive of depreciation and amortization) | 25.3 |
| | 27.2 |
| | 26.1 |
| | 20.4 |
| |
| Cost of materials and other | | 1,221.2 |
| | 1,228.6 |
| | 1,132.4 |
| | 1,300.7 |
|
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | | 138.1 |
| | 124.2 |
| | 161.1 |
| | 176.1 |
|
| Depreciation and amortization | | 48.6 |
| | 51.7 |
| | 51.3 |
| | 51.7 |
|
| Cost of sales | | 1,407.9 |
| | 1,404.5 |
| | 1,344.8 |
| | 1,528.5 |
|
| Selling, general and administrative (exclusive of depreciation and amortization as reflected below) | | 29.1 |
| | 26.3 |
| | 27.3 |
| | 31.5 |
|
| Depreciation and amortization | 42.0 |
| | 42.5 |
| | 38.7 |
| | 40.9 |
| 2.5 |
| | 2.3 |
| | 2.8 |
| | 3.1 |
|
| Total operating costs and expenses | 1,252.3 |
| | 1,350.0 |
| | 1,287.3 |
| | 1,121.3 |
| 1,439.5 |
| | 1,433.1 |
| | 1,374.9 |
| | 1,563.1 |
|
| Operating income (loss) | 136.6 |
| | 274.2 |
| | 121.5 |
| | (110.7 | ) | |
| Operating income | | 67.6 |
| | 1.3 |
| | 78.9 |
| | 30.0 |
|
| Other income (expense): | | | | | | | | | | | | | | |
| Interest expense and other financing costs | (12.7 | ) | | (11.9 | ) | | (11.9 | ) | | (11.9 | ) | (27.0 | ) | | (27.6 | ) | | (27.6 | ) | | (27.9 | ) |
| Interest income | 0.2 |
| | 0.3 |
| | 0.3 |
| | 0.2 |
| 0.2 |
| | 0.3 |
| | 0.2 |
| | 0.4 |
|
| Gain (loss) on derivatives, net | (51.4 | ) | | (12.6 | ) | | 11.8 |
| | 23.6 |
| 12.2 |
| | — |
| | (17.0 | ) | | (65.0 | ) |
| Other income, net | 36.0 |
| | 0.2 |
| | 0.3 |
| | 0.2 |
| — |
| | 0.1 |
| | — |
| | 0.9 |
|
| Total other income (expense) | (27.9 | ) | | (24.0 | ) | | 0.5 |
| | 12.1 |
| |
| Total other expense | | (14.6 | ) | | (27.2 | ) | | (44.4 | ) | | (91.6 | ) |
| Income (loss) before income taxes | 108.7 |
| | 250.2 |
| | 122.0 |
| | (98.6 | ) | 53.0 |
| | (25.9 | ) | | 34.5 |
| | (61.6 | ) |
| Income tax expense (benefit) | 24.0 |
| | 58.1 |
| | 23.1 |
| | (20.7 | ) | 14.8 |
| | (6.6 | ) | | 9.2 |
| | (234.3 | ) |
| Net income (loss) | 84.7 |
| | 192.1 |
| | 98.9 |
| | (77.9 | ) | 38.2 |
| | (19.3 | ) | | 25.3 |
| | 172.7 |
|
| Less: Net income (loss) attributable to noncontrolling interest | 29.8 |
| | 90.2 |
| | 41.0 |
| | (32.9 | ) | 16.0 |
| | (8.8 | ) | | 3.1 |
| | (27.8 | ) |
| Net income (loss) attributable to CVR Energy stockholders | $ | 54.9 |
| | $ | 101.9 |
| | $ | 57.9 |
| | $ | (45.0 | ) | $ | 22.2 |
| | $ | (10.5 | ) | | $ | 22.2 |
| | $ | 200.5 |
|
| | | | | | | | | | | | | | | |
| 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 | ) | |
| Basic and diluted earnings (loss) per share | | $ | 0.26 |
| | $ | (0.12 | ) | | $ | 0.26 |
| | $ | 2.31 |
|
| Dividends declared per share | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
|
| | | | | | | | | | | | | | | |
| Weighted-average common shares outstanding | | | | | | | | |
| Basic | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| |
Weighted-average common shares outstanding - basic and diluted
| | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
|
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
| | | | Year Ended December 31, 2014 | Year Ended December 31, 2016 |
| | Quarter | Quarter |
| | First | | Second | | Third | | Fourth | First | | Second | | Third | | Fourth |
| | (in millions, except per share data) | (in millions, except per share data) |
| Net sales | $ | 2,447.4 |
| | $ | 2,540.3 |
| | $ | 2,279.9 |
| | $ | 1,841.8 |
| $ | 905.5 |
| | $ | 1,283.2 |
| | $ | 1,240.3 |
| | $ | 1,353.4 |
|
| Operating costs and expenses: | | | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | 2,076.9 |
| | 2,189.0 |
| | 2,066.7 |
| | 1,733.4 |
| |
| Direct operating expenses (exclusive of depreciation and amortization) | 123.4 |
| | 120.1 |
| | 136.8 |
| | 134.7 |
| |
| Selling, general and administrative (exclusive of depreciation and amortization) | 26.3 |
| | 28.0 |
| | 31.8 |
| | 23.5 |
| |
| Cost of materials and other | | 736.8 |
| | 976.9 |
| | 1,005.7 |
| | 1,128.1 |
|
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | | 141.4 |
| | 138.3 |
| | 129.5 |
| | 132.6 |
|
| Depreciation and amortization | | 37.9 |
| | 48.5 |
| | 48.2 |
| | 49.9 |
|
| Cost of sales | | 916.1 |
| | 1,163.7 |
| | 1,183.4 |
| | 1,310.6 |
|
| Selling, general and administrative (exclusive of depreciation and amortization as reflected below) | | 27.2 |
| | 26.6 |
| | 27.8 |
| | 27.5 |
|
| Depreciation and amortization | 37.3 |
| | 38.6 |
| | 37.8 |
| | 40.8 |
| 2.1 |
| | 2.2 |
| | 1.9 |
| | 2.4 |
|
| Total operating costs and expenses | 2,263.9 |
| | 2,375.7 |
| | 2,273.1 |
| | 1,932.4 |
| 945.4 |
| | 1,192.5 |
| | 1,213.1 |
| | 1,340.5 |
|
| Operating income (loss) | 183.5 |
| | 164.6 |
| | 6.8 |
| | (90.6 | ) | (39.9 | ) | | 90.7 |
| | 27.2 |
| | 12.9 |
|
| Other income (expense): | | | | | | | | | | | | | | |
| Interest expense and other financing costs | (10.1 | ) | | (9.3 | ) | | (9.4 | ) | | (11.2 | ) | (12.1 | ) | | (18.5 | ) | | (26.2 | ) | | (27.1 | ) |
| Interest income | 0.2 |
| | 0.2 |
| | 0.3 |
| | 0.2 |
| 0.2 |
| | 0.1 |
| | 0.2 |
| | 0.2 |
|
| Gain on derivatives, net | 109.4 |
| | 35.9 |
| | 25.7 |
| | 14.5 |
| |
| Other income (expense), net | 0.1 |
| | (2.2 | ) | | 2.1 |
| | (3.6 | ) | |
| Total other income (expense) | 99.6 |
| | 24.6 |
| | 18.7 |
| | (0.1 | ) | |
| Loss on derivatives, net | | (1.2 | ) | | (1.9 | ) | | (1.7 | ) | | (14.6 | ) |
| Gain (loss) on extinguishment of debt | | — |
| | (5.1 | ) | | — |
| | 0.2 |
|
| Other income, net | | 0.3 |
| | 0.1 |
| | 5.0 |
| | 0.3 |
|
| Total other expense | | (12.8 | ) | | (25.3 | ) | | (22.7 | ) | | (41.0 | ) |
| Income (loss) before income taxes | 283.1 |
| | 189.2 |
| | 25.5 |
| | (90.7 | ) | (52.7 | ) | | 65.4 |
| | 4.5 |
| | (28.1 | ) |
| Income tax expense (benefit) | 69.4 |
| | 45.2 |
| | 4.2 |
| | (21.0 | ) | (21.8 | ) | | 21.6 |
| | 2.5 |
| | (22.1 | ) |
| Net income (loss) | 213.7 |
| | 144.0 |
| | 21.3 |
| | (69.7 | ) | (30.9 | ) | | 43.8 |
| | 2.0 |
| | (6.0 | ) |
| Less: Net income (loss) attributable to noncontrolling interest | 87.0 |
| | 60.3 |
| | 13.4 |
| | (25.3 | ) | (14.7 | ) | | 15.4 |
| | (3.4 | ) | | (13.1 | ) |
| Net income (loss) attributable to CVR Energy stockholders | $ | 126.7 |
| | $ | 83.7 |
| | $ | 7.9 |
| | $ | (44.4 | ) | $ | (16.2 | ) | | $ | 28.4 |
| | $ | 5.4 |
| | $ | 7.1 |
|
| | | | | | | | | | | | | | | |
| 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 | ) | |
| Basic and diluted earnings (loss) per share | | $ | (0.19 | ) | | $ | 0.33 |
| | $ | 0.06 |
| | $ | 0.08 |
|
| Dividends declared per share | $ | 0.75 |
| | $ | 0.75 |
| | $ | 2.75 |
| | $ | 0.75 |
| $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
| | $ | 0.50 |
|
| | | | | | | | | | | | | | | |
| Weighted-average common shares outstanding | | | | | | | | | | | | | | |
| Basic | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Diluted | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
| |
| Basic and diluted | | 86.8 |
| | 86.8 |
| | 86.8 |
| | 86.8 |
|
Factors Impacting the Comparability of Quarterly Results of Operations
As discussed in Note 2 ("Summary of Significant Accounting Policies"), the CoffeyvilleRefining Partnership's Wynnewood refinery completed the first phase of its currentmost recent major scheduled turnaround in mid-November 2015the fourth quarter of 2017. The second phase of the Wynnewood refinery turnaround is expected to occur in 2019. In addition to the two phase turnaround, the Refining Partnership accelerated certain planned turnaround activities of the Wynnewood refinery in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. The Refining Partnership incurred approximately $80.4 million of major scheduled turnaround expenses during 2017, of which approximately $13.0 million, $2.7 million, $21.7 million and $43.0 million were incurred in the first, second, third and fourth quarters of 2017, respectively. The Refining Partnership's Coffeyville refinery completed the second phase of its most recent major scheduled turnaround during the first quarter of 2016 at a total cost of approximately $101.5 million. Additionally, the Coffeyville refinery incurred approximately $0.7$31.5 million in turnaround costs related to the second phase scheduled to begin in late February 2016. In total, the Coffeyville refinery incurred $102.2 million of major scheduled turnaround expenses for the year ended December 31, 2015,2016, of which approximately $1.7 million, $15.6$29.4 million and $84.9$2.1 million were includedincurred in the second, thirdfirst and fourthsecond quarters of 2015,2016, respectively. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS —- (Continued)
As discussed in Note 13 ("Commitments and Contingencies"), CRRM received an insurance recovery from its environmental insurance carriers in the second 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 72 ("Insurance Claims"Summary of Significant Accounting Policies"), the fire at the Coffeyville refinery's isomerization unit adversely impacted production of refined products for the petroleum business induring the third quarter of 2014. Total gross repair2017 and other costs recorded related toduring the incident forsecond quarter of 2016, the year ended December 31, 2014 were approximately $6.3 million and are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.Nitrogen Fertilizer Partnership's East Dubuque facility completed major scheduled turnarounds.
DuringOn April 1, 2016, the fourth quarter of 2014,Nitrogen Fertilizer Partnership completed the FCCU atEast Dubuque Merger, whereby the Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a resultNitrogen Fertilizer Partnership acquired the East Dubuque Facility. The consolidated financial statements include the results of the FCCU outage, crude throughput and production atEast Dubuque Facility beginning on April 1, 2016, the Wynnewood refinery was significantly reduced duringdate of the fourth quarterclosing of 2014. Additionally, the Refining Partnership incurred approximately $8.5 million in costs to repair the FCCUacquisition. See Note 3 ("Acquisition") for the year ended December 31, 2014. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.further discussion.
As discussed in Note 4 ("Inventories"), the Refining Partnership recorded a lower of FIFO cost or market inventory adjustment of approximately $36.8 million during the fourth quarter of 2014, which is included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
(20)(22) Subsequent Events
Dividend
On February 17, 2016,21, 2018, the board of directors of the Company declared a cash dividend for the fourth quarter of 20152017 to the Company's stockholders of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on March 7, 201612, 2018 to stockholders of record at the close of business on February 29, 2016.March 5, 2018. IEP will receive $35.6 million in respect of its 82% ownership interest in the Company's shares.
Nitrogen Fertilizer Partnership Distribution
On February 17, 2016, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the fourth quarter of 2015 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, 2016 to unitholders of record at the close of business on February 29, 2016. The Company will receive $10.5 million in respect of its Nitrogen Fertilizer Partnership common units.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of December 31, 2015,2017, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC'sSecurities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management's Report On Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, the Company conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the Company's internal control over financial reporting was effective as of December 31, 2015.2017. Our independent registered public accounting firm, that audited the consolidated financial statements included herein under Item 8, has issued a report on the effectiveness of our internal control over financial reporting. This report 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, 20152017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Information required by this Item regarding our directors, executive officers and corporate governance will be included under the captions "Corporate Governance," "Proposal 1 — Election of Directors," "Members and Nominees of the Board," "Executive Officers," "Information Concerning Executive Officers Who are Not Directors," "Section 16(a) Beneficial Ownership Reporting Compliance," and "Stockholder Proposals" 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 11. Executive Compensation
Information about executive and director compensation will be included under the captions "Corporate Governance — Compensation Committee Interlocks and Insider Participation," "Proposal 1 — Election of Directors," "Director Compensation for 2015,2017," "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 Matters
Information about security ownership of certain beneficial owners and management will be included under the captions "Compensation of Executive Officers," "Securities Ownership of Certain Beneficial Owners and Officers and Directors" and "Equity Compensation Plans" 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 13. Certain Relationships and Related Transactions, and Director Independence
Information about related party transactions between CVR Energy and its directors, executive officers and 5% stockholders that occurred during the year ended December 31, 20152017 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 information is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services
Information about principal accounting fees and services will be included under the captions "Proposal 2 — Ratification of Selection of Independent Registered Public Accounting Firm" and "Fees Paid to the Independent Registered Public Accounting Firm" 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.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
See "Index to Consolidated Financial Statements" Contained in Part II, Item 8 of this Report.
(a)(2) Financial Statement Schedules
All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission (the "SEC") are not required under the related instructions or are inapplicable and therefore have been omitted.
(a)(3) Exhibits
|
| |
| Exhibit Number | Exhibit Title |
| Agreement and Plan of Merger, dated as of August 9, 2015, by and among CVR Partners, LP, Lux Merger Sub 1, LLC, Lux Merger Sub 2, LLC, Rentech Nitrogen Partners, L.P., and Rentech Nitrogen GP, LLC (incorporated by reference to Exhibit 2.1 to the Form 8-K filed by CVR Partners, LP on August 13, 2015 (Commission File No. 001-35120)). |
| |
2.2** | |
| | |
| |
| | |
| |
| | |
| |
| | |
| |
| | |
| |
| | |
| |
| | |
| Indenture, dated June 10, 2016, by and among CVR Partners, LP, CVR Nitrogen Finance Corporation, the Guarantors (as defined therein) and Wilmington Trust, National Association, as Trustee and Collateral Trustee (incorporated by reference to Exhibit 4.1 of the Form 8-K filed by CVR Partners, LP on June 16, 2016 (Commission File No. 001-35120)). |
| |
| |
| |
| Indenture, dated as April 12, 2013, among Rentech Nitrogen Partners, L.P., Rentech Nitrogen Finance Corporation, the guarantors named therein, Wells Fargo Bank, National Association, as Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by Rentech Nitrogen Partners, L.P. on April 16, 2013 (Commission File No. 001-35334)). |
| |
| |
| |
| First Supplemental Indenture, dated as of June 10, 2016, among CVR Nitrogen, LP, CVR Nitrogen Finance Corporation, the guarantors party thereto, Wells Fargo Bank, National Association, as Trustee, and Wilmington Trust, National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.3 of the Form 8-K filed by CVR Partners, LP on June 16, 2016 (Commission File No. 001-35120)). |
| |
|
| |
| Amended and Restated ABL Credit Agreement, dated as of December 20, 2012, among Coffeyville Resources, LLC, CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, the lenders from time to time party thereto, Wells Fargo Bank, National Association, as collateral agent and administrative agent (incorporated by reference to Exhibit 1.1 to the Company's Form 8-K filed on December 27, 2012). |
| | |
| Amendment No. 1 to Amended and Restated ABL Credit Agreement, dated November 14, 2017, by and among CVR Refining, LP, Coffeyville Finance Inc., CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC, CVR Logistics, LLC, a group of lenders and Wells Fargo, National Association, as administrative agent and collateral agent (incorporated by reference as Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on November 17, 2017).
|
| |
| Amended and Restated ABL Pledge and Security Agreement, dated as of December 20, 2012, among CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, and Wells Fargo Bank, National Association, as collateral agent (incorporated by reference to Exhibit 1.2 to the Company's Form 8-K filed on December 27, 2012). |
| | |
| 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 Resources Refining & 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). |
| | |
|
| | | Exhibit Number | Exhibit Title | 10.4** | ABL Intercreditor Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Finance Inc., Deutsche Bank Trust Company Americas, as collateral agent for the ABL secured parties, Wells Fargo Bank, National Association, as collateral trustee for the secured parties in respect of the outstanding first lien obligations, and the outstanding second lien notes and certain subordinated liens, respectively, and the Guarantors (as defined therein) (incorporated by reference to Exhibit 1.3 to the Company's Form 8-K filed on February 28, 2011). | | | | | 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 administrative agent, Wells Fargo Bank, National Association, as indenture agent, J. Aron & Company, as hedging counterparty, each additional first lien representative and Wells Fargo Bank, National Association, as collateral trustee (incorporated by reference to Exhibit 10.33 to the Company's Form 10-K for the year ended December 31, 2011, filed on February 29, 2012). | | | | | Omnibus Amendment Agreement and Consent under the Intercreditor Agreement, dated as of April 6, 2010, by and among Coffeyville Resources, LLC, Coffeyville Finance Inc., Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, and certain subsidiaries of the foregoing as Guarantors, the Requisite Lenders, Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, Collateral Agent and Revolving Issuing Bank, J. Aron & Company, as a hedge counterparty and Wells Fargo Bank, National Association, as Collateral Trustee (incorporated by reference to Exhibit 1.4 to the Company's Form 8-K filed on April 12, 2010). | | | | | 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 by reference 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 Power Systems, dated as of May 30, 1997 by and between GE Energy (USA), LLC (as successor in interest to Texaco Development Corporation) 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 on April 18, 2007) (Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment which has been granted by the SEC.). | | | | 10.9† | | | | |
10.9.1** | | | | | | | | 10.10† | | | | |
| | | | | | | | | | | | | 10.11† | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, by and between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.14 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007). | | | 10.12** | | | | | 10.13* | | | | | 10.14* | Third Amended and Restated Employment Agreement, dated as of JanuaryNovember 1, 2011,2017, by and between CVR Energy, Inc. and Robert W. HaugenDavid L. Lamp (incorporated by reference toas Exhibit 10.510.20 to the Company's Form 10-Q for the quarter ended March 31, 2011,10-K filed by CVR Partners, LP on May 10, 2011)February 23, 2018 (Commission File No. 001-35120)).
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| | | Exhibit Number | Exhibit Title | 10.14.1**++ | Amendment Number 1 to Third Amended and Restated Employment
| | | | 10.14.2* | Amendment Number 2 to Third Amended and Restated Employment
| | | | 10.15* | | | | | 10.16* | | | | | 10.17* | Amended and Restated Contribution, Conveyance and Assumption Agreement, dated as of April 7, 2011, among Coffeyville Resources, LLC, CVR GP, LLC, Coffeyville Acquisition III LLC, CVR Special GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K/A filed on May 23, 2011). | | | | 10.18* | | | | | 10.18.1* | | | | | 10.18.2* | | | | | 10.19* | Second Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011,January 1, 2017, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.410.2 to the Company's Form 8-K/A10-Q filed by CVR Partners, LP on May 23, 2011)April 27, 2017). |
| | | | | | 10.19.1* | Amendment to the Second Amended and Restated Feedstock and Shared Services Agreement, dated as of December 30, 2013,November 1, 2017, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.21.110.7.1 to the Company's Form 10-K filed by CVR Partners, LP on February 26, 2014)23, 2018). | | | | 10.20* | | | | | 10.21* | SecondThird Amended and Restated Services Agreement, dated as of May 4, 2012,January 1, 2017, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.210.3 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, amongby 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)April 27, 2017).
| | | | 10.22* | | | | | 10.23* | | | | | 10.24* | | | | |
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| | | Exhibit Number | Exhibit Title | 10.25** | 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 on February 24, 2012 (Commission File No. 001-35120)). | | | | 10.25.1* | | | | | 10.26* | | | | | 10.27* | | | | | 10.28* | | | | | 10.29* | | | | | 10.29.1* | | | | | 10.29.2* | | | | | 10.29.3* | | | | | 10.29.4* | | | | | 10.29.5* | | | | | 10.29.6* | | | | | 10.30* | | | | | | | | |
10.31* | | | | | | | | 10.32* | | | | | 10.32.1* | Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.4 to 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 10.18.5 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)). | | | 10.32.3**++ | | | | | 10.33* | | | | | | | | | | | | | 10.34* | CVR Partners, LP Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LP on 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 reference to Exhibit 3.4 to the Form 10-K for the year ended December 31, 2011 filed by CVR Partners, LP on February 24, 2012 (Commission File No. 001-35120)). | | |
| | | Exhibit Number | Exhibit Title | 10.36** | First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, dated as of January 23, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). | | | | | | | | | | | | | | | Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.41.1 to the Company's Form 10-K filed on February 26, 2014). | | | 10.38.2**++ | | | | | | | | | | Amended and Restated Services Agreement, dated December 31, 2012,as of January 1, 2017, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.210.3 to the Form 8-K10-Q filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781))May 1, 2017). | | | | 10.39.1* | Amendment to Services Agreement, dated as of February 17, 2014, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, 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 and CVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on August 1, 2014). | | | 10.40** | | | | | | | | | | | | | | | | Reorganization Agreement, dated as of January 16, 2013, by and among CVR Refining, LP, CVR Refining GP, LLC, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 23, 2013 (Commission File No. 001-35781)). | | | | | | | | | | Registration Rights Agreement, dated as of January 23, 2013, by and among CVR Refining, LP, Icahn Enterprises Holdings L.P., CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)). | | | | | Registration Rights Agreement, dated as of August 9, 2015, by and among CVR Partners, Coffeyville Resources, LLC, Rentech Nitrogen Holdings, Inc., and DSHC, LLC (incorporated by reference to Exhibit 4.1 to the Form 8-K filed by CVR Partners, LP on August 13, 2015 (Commission File No. 001-35120)). | | |
| | | | | | | | 10.46* | Voting and SupportParity Lien Security Agreement, dated as of August 9, 2015, by andJune 10, 2016, among CVR Partners, LP, Rentech, Inc., RentechCVR Nitrogen Finance Corporation, the Guarantors (as defined therein) and Wilmington Trust, National Association, as Trustee and Collateral Trustee(incorporated by reference to Exhibit 10.2 of the Form 8-K filed by CVR Partners on June 16, 2016 (Commission File No. 001-35120)). | | | | ABL Credit Agreement, dated as of September 30, 2016, among CVR Partners, LP, CVR Nitrogen, LP, East Dubuque Nitrogen Fertilizers, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, CVR Nitrogen Holdings, Inc.,LLC, CVR Nitrogen Finance Corporation, CVR Nitrogen GP, LLC, certain of their affiliates from time to time party thereto, the lenders from time to time party thereto, UBS AG, Stamford Branch, as administrative agent and DSHC, LLCcollateral agent (incorporated by reference to Exhibit 10.1 toof the Form 8-K filed by CVR Partners, LP on August 13, 2015October 6, 2016 (Commission File No. 001-35120)). | | | | 10.47* | TransactionSecurity Agreement, dated as of August 9, 2015, by andSeptember 30, 2016, among CVR Partners, LP, CVR Nitrogen, LP, East Dubuque Nitrogen Fertilizers, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Rentech, Inc., RentechCVR Nitrogen Holdings, Inc.,LLC, CVR Nitrogen Finance Corporation, CVR Nitrogen GP, LLC, certain of their affiliates from time to time party thereto, and DSHC, LLCUBS AG, Stamford Branch, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.2 toof the Form 8-K filed by CVR Partners, LP on August 13, 2015October 6, 2016 (Commission File No. 001-35120)). | | | |
| | | Exhibit Number | Exhibit Title | 10.48** | TransactionIntercreditor Agreement, dated as of August 9, 2015, by andSeptember 30, 2016, among CVR Partners, LP, GSO Special Situations Overseas Master Fund Ltd., GSO Special Situations FundCVR Nitrogen, LP, GSO Palmetto Opportunistic Investment Partners LP, GSO Credit-A Partners LP, Steamboat Credit Opportunities Master Fund LP, GSO Coastline Credit Partners LP, GSO Cactus Credit Opportunities Fund LPEast Dubuque Nitrogen Fertilizers, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, CVR Nitrogen Holdings, LLC, CVR Nitrogen Finance Corporation, CVR Nitrogen GP, LLC, certain of their affiliates from time to time party thereto, UBS AG, Stamford Branch, as administrative agent and GSO Aiguille des Grands Montets Fund II LPcollateral agent for the secured parties, Wilmington Trust, National Association, as trustee and GSO Capital Partners LPcollateral trustee for the secured parties in respect of the outstanding senior secured notes and other parity lien obligations and other parity lien representative from time to time party thereto (incorporated by reference to Exhibit 10.3 toof the Form 8-K filed by CVR Partners, LP on August 13, 2015October 6, 2016 (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 by reference 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** | | | | | | | | | | | | | | | | | | | | 32.1* | | | | | | 101* | The following financial information for CVR Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2015,2017, formatted in XBRL ("Extensible Business Reporting Language") includes: (1) Consolidated Balance Sheets, (2) Consolidated Statements 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 been granted by the SEC.Furnished herewith. | | | | | ++ | | 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 of the 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 we file with or furnish to the SEC. The agreements are filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company's public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant 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 on its behalf by the undersigned, thereunto duly authorized. | | | | | | | CVR Energy, Inc. | | | By: | /s/ JOHN J. LIPINSKIDAVID L. LAMP | | | | Name: | John J. LipinskiDavid L. Lamp | | | | Title: | President and Chief Executive Officer and President |
Date: February 19, 201626, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report had been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated. | | | | | Signature | Title | Date | | | | | /s/ JOHN J. LIPINSKIDAVID L. LAMP | President, Chief Executive Officer President and Director (Principal Executive Officer) | February 19, 201626, 2018 | John J. LipinskiDavid L. Lamp | | | | | | | | /s/ SUSAN M. BALL | Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) | February 19, 201626, 2018 | | Susan M. Ball | | | | | | | | | Chairman of the Board of Directors | February 19, 201626, 2018 | | Carl C. Icahn | | | | | | | | /s/ BOB G. ALEXANDER | Director | February 19, 201626, 2018 | | Bob G. Alexander | | | | | | | | /s/ SUNGHWAN CHO | Director | February 19, 201626, 2018 | | SungHwan Cho | | | | | | | /s/ ANDREW LANGHAMJONATHAN FRATES | Director | February 19, 201626, 2018 | Andrew Langham | | | | | | /s/ COURTNEY MATHER | Director | February 19, 2016 | Courtney MatherJonathan Frates | | | | | | | | /s/ STEPHEN MONGILLO | Director | February 19, 201626, 2018 | | Stephen Mongillo | | | | | | | /s/ LOUIS J. PASTOR | Director | February 26, 2018 | | Louis J. Pastor | | | | | | | | /s/ JAMES M. STROCK | Director | February 19, 201626, 2018 | | James M. Strock | | |
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