2017
FORM 10-K
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________________________
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to .
OR
Commission file number: 001-33492
_____________________________________________________________
CVR Energy, Inc.
(Exact name of registrant as specified in its charter)
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
2277 Plaza Drive, Suite 500
Sugar Land, Texas
(Address of Principal Executive Offices)
61-1512186
(I.R.S. Employer
Identification No.)
77479
(Zip Code)
Registrant's Telephone Number, including Area Code:
(281) 207-3200
_____________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, $0.01 par value per share
Name of Each Exchange on Which Registered
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
No
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
No
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
No
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
No
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.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See
the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
(Do not check if a smaller reporting company)
Smaller reporting company
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
Emerging growth company
standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
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, 2017 (the last business day of the registrant's second fiscal quarter) was $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, 2017 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.
Class
Common Stock, par value $0.01 per share
Outstanding at February 20, 2018
86,831,050 shares
Documents Incorporated By Reference
Document
Proxy Statement for the 2018 Annual Meeting of Stockholders
Parts Incorporated
Items 10, 11, 12, 13 and 14 of Part III
[THIS PAGE INTENTIONALLY LEFT BLANK]
TABLE OF CONTENTS
PART I
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1.
Item 1A. Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Item 3.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4. Mine Safety Disclosures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART II
Item 5. Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . .
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. . . . .
Item 9.
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10. Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Item 12.
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13. Certain Relationships and Related Transactions, and Director Independence . . . . . . . . . . . . . . . .
Principal Accounting Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
PART IV
Exhibits, Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Form 10-K Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 15.
Item 16.
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1
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, 2017 (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.
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 the 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.
Coffeyville Fertilizer Facility — CVR Partners' nitrogen fertilizer manufacturing facility located in
Coffeyville, Kansas.
2
Coffeyville Finance — Coffeyville Finance Inc., a wholly-owned subsidiary of Refining LLC and an indirect
wholly-owned subsidiary of the 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.
3
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 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 throughputs 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.
Merger Agreement — The Agreement and Plan of Merger, dated as of August 9, 2015, whereby the Nitrogen
Fertilizer Partnership acquired CVR Nitrogen and 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, as well as products of the refining process. Common NGLs used include propane,
isobutane, normal butane and natural gasoline.
Nitrogen Fertilizer Partnership credit facility — CRNF'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 lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent,
which was repaid in full and terminated on April 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 or railcars.
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a
refinery.
4
Refining LLC — 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 the Refining Partnership, which closed on January 23, 2013 (which includes the underwriters'
subsequently exercised option to purchase additional common units).
RFS — Renewable Fuel Standard of the EPA.
RINs — 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.
Velocity — Velocity Central Oklahoma Pipeline LLC.
Vitol — Vitol Inc.
Vitol Agreement — The 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.
Wells Fargo Credit Agreement — CVR Nitrogen's credit agreement with Wells Fargo, as successor-in-interest
by assignment from General Electric Company, as administrative agent, which was repaid in April 2016 and
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.
yield — The percentage of refined products that is produced from crude oil and other feedstocks.
5
Item 1. Business
Overview
PART I
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 approximately 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, 2017, 2016 and 2015, we generated consolidated net sales of $6.0
billion, $4.8 billion and $5.4 billion, respectively, and operating income of $177.8 million, $90.9 million and $421.6
million, respectively. The petroleum business generated $5.7 billion, $4.4 billion and $5.2 billion of net sales and the
nitrogen fertilizer business generated $330.8 million, $356.3 million and $289.2 million of net sales, in each case,
for the years ended December 31, 2017, 2016 and 2015, respectively. The petroleum business generated operating
income of $203.8 million, $77.8 million and $361.7 million and the nitrogen fertilizer business generated operating
income (loss) of $(9.2) million, $26.8 million and $68.7 million, in each case, for the years ended December 31,
2017, 2016 and 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
CVR Energy was formed in September 2006 as a subsidiary of Coffeyville Acquisition LLC ("CALLC") in
order to consummate an initial public offering of its businesses previously acquired through a bankruptcy court
auction. CVR Energy consummated its initial public offering on October 26, 2007.
On April 13, 2011, the Nitrogen Fertilizer Partnership completed the Nitrogen Fertilizer Partnership 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.
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 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.
6
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the East Dubuque Merger as contemplated by
the Agreement and Plan of Merger, 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.
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.
As of December 31, 2017, public security holders held approximately 34% of the total Refining Partnership
common units (including units owned by affiliates of IEP, representing 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.
7
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.
8
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 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.
For the year ended December 31, 2017, the Coffeyville refinery's product yield included gasoline (50%), diesel
fuel (primarily ultra-low sulfur diesel ("ULSD")) (42%), and pet coke and other refined products such as natural gas
liquids ("NGL") (propane and butane), slurry, sulfur and gas oil (8%). The Wynnewood refinery's product yield
included gasoline (51%), diesel fuel (primarily 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 Winfield, Kansas and Denver, Colorado. The
gathering system includes approximately 570 miles of active owned, leased and joint venture pipelines
and approximately 130 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 80,000 bpd currently. Gathered crude oil provides an attractive and competitive base
supply of crude oil for the Coffeyville and Wynnewood refineries. During 2017, the petroleum
business gathered approximately 86,000 bpd of 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 crude 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, 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, 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 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. The petroleum business also leases additional crude oil storage capacity of
approximately 2.3 million barrels in Cushing and 0.2 million barrels in Duncan, Oklahoma. The
Duncan storage supports CVR Refining's Wynnewood refinery while the Cushing storage supports
both its Wynnewood and Coffeyville refineries. In addition to crude oil storage, the petroleum
business owns over 4.6 million barrels of combined refined products and feedstocks storage capacity.
9
•
Marketing and Product Supply. The petroleum business also has a rack marketing division supplying
product through tanker trucks directly to customers located in 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 North Dakota Bakken and other similarly sourced
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 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 2017 and it now has the capacity of supplying
over 80,000 bpd of crude oil to the refineries. For the year ended December 31, 2017, the gathering system supplied
approximately 44% and 49% of the Coffeyville and Wynnewood refineries' crude oil 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 by various pipelines
including the Keystone and Spearhead pipelines, and subsequently to the Broome Station facility via the Midway
joint venture pipeline. The petroleum business' current contracted capacity includes 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 through 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, 2017, the Coffeyville refinery's crude oil supply blend was comprised of
approximately 92% light sweet crude oil and 8% heavy sour crude oil. For the year ended December 31, 2017, the
Wynnewood refinery's crude oil supply blend was comprised of entirely of light sweet crude oil. The light sweet
crude oil supply blend includes its locally gathered crude oil.
10
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
Refer 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, 2017, the Coffeyville refinery
processed approximately 132,000 bpd and 9,000 bpd of crude oil and feedstocks 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 Coffeyville refinery, the Wynnewood refinery benefits from unit redundancies,
including two crude oil distillation and vacuum towers and four hydrotreating units. During the year ended
December 31, 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.
11
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, 2017, only one customer accounted for 10% or more of the
petroleum business' consolidated revenues. Its largest customer accounted for approximately 19% of its net sales and
approximately 52% of 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.
12
Nitrogen Fertilizer Business
The nitrogen fertilizer business, operated by the Nitrogen Fertilizer Partnership, consists of two nitrogen
fertilizer manufacturing facilities which are located in Coffeyville, 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 principal 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 plant 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 liquid and granulated urea each season, depending on market demand, pricing and storage
availability. The East Dubuque Facility's product sales are heavily weighted toward sales of ammonia and UAN.
Raw Material Supply
Coffeyville Fertilizer Facility
The Coffeyville Fertilizer Facility was built in 2000 and uses a gasification process to convert pet coke to high
purity hydrogen for subsequent conversion to ammonia. The Coffeyville nitrogen fertilizer facility's pet coke
gasification process results in a higher percentage of fixed costs than a natural gas-based fertilizer plant. During the
past five years, over 70% of the Coffeyville nitrogen fertilizer 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 plant 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 that ends December 2018, and has historically renewed
this agreement annually. If necessary, there 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 is licensed from an affiliate of General Electric Company. The license grants
the Coffeyville Fertilizer Facility perpetual rights to use the pet coke gasification process on specified terms and
conditions, and the 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 Coffeyville Fertilizer Facility gasifiers.
East Dubuque Facility
The East Dubuque Facility uses natural gas to produce nitrogen fertilizer. The East Dubuque Facility is able to
purchase natural gas at competitive prices due to the plant’s connection to the Northern Natural Gas interstate
pipeline system, which is within one mile of the facility, and the ANR Pipeline Company pipeline. The pipelines are
connected to Nicor Inc.’s distribution system at the Chicago 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 East Dubuque Facility's financial position and results of 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 enters into forward contracts with
fixed delivery prices to purchase portions of its natural gas requirements. As of December 31, 2017, the nitrogen
business segment had commitments to purchase approximately 1.8 million MMBtus of natural gas supply for
planned use in its East Dubuque Facility in January and February 2018 at a weighted average rate per MMBtu of
approximately $3.20, exclusive of transportation cost.
13
Distribution, Sales and Marketing
The primary geographic markets for the nitrogen fertilizer business' fertilizer products are Illinois, Iowa,
Kansas, Nebraska and Texas. The nitrogen fertilizer business' primarily market the UAN products to agricultural
customers and ammonia products to agricultural and industrial customers. UAN and 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, 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'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 customers. The East
Dubuque Facility primarily sells its product to customers located within 200 miles of the facility. In most instances,
customers take delivery of nitrogen products at the East Dubuque Facility and arrange and pay to transport them to
their final destinations by truck.
The nitrogen fertilizer business has the capacity to store approximately 160,000 tons of UAN and 80,000 tons of
ammonia. The nitrogen 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 sold to customers throughout the 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. 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.
Customers
The nitrogen fertilizer business sells UAN products to retailers and distributors. In addition, it sells ammonia to
agricultural and industrial customers. 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 agricultural
customers. Some of our industrial sales include long-term purchase contracts.
For the year ended December 31, 2017, the top five customers in the aggregate represented 31% of the nitrogen
fertilizer business' net sales. The nitrogen fertilizer business' top customer on a consolidated basis accounted for
approximately 11% of its net sales. While the nitrogen fertilizer 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
14
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 CF Industries Holdings, Inc., including its majority
owned subsidiary Terra Nitrogen Company, L.P.; Koch Fertilizer Company, LLC; and Nutrien Ltd. (formerly known
as Agrium, Inc. and Potash Corporation of Saskatchewan, Inc.). 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.
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. In 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 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
experiences higher net sales in the first half of the 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, 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;
liability for the investigation and remediation of contaminated soil and groundwater at current and
former facilities (if any) and 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.
These laws and regulations could result in increased capital, operating and compliance costs.
15
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 15 ("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 resources 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").
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 are material.
On December 1, 2015, the EPA published in the Federal Register the petroleum refining sector 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 the costs
of complying with the rule are material.
Refer to Part II, Item 8, Note 15 ("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."
16
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 water during certain water shortage conditions,
but these conditions could change over time if water becomes scarce.
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 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.
From time to time, the EPA has conducted inspections and issued information requests to us with respect to our
compliance with reporting requirements under the Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA") and the Emergency Planning and Community Right-to-Know Act. 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 were
required to be in compliance with the more stringent emission standards as of January 1, 2017; however, compliance
with the rule has been extended until January 1, 2020 for approved small volume refineries and small refiners. 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 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 required 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 refineries are in compliance with the EPA's MSAT II rule.
17
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
RFS mandates, the petroleum business' financial condition and results of operations could be materially adversely
affected, and Part II, Item 8, Note 15 ("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.
Resource Conservation and Recovery Act ("RCRA")
Our operations are subject to the RCRA requirements for the generation, transportation, treatment, storage and
disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being
disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes.
Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past
waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing
regulated substances. Refer to Part II, Item 8, Note 15 ("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 fourteen other
solid 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. In March 2004, CRRM and Coffeyville Resources Terminal, LLC ("CRT")
entered into a Consent Decree ("2004 Consent Decree") 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 required investigation and 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. 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 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, the Oklahoma Department of Environmental Quality ("ODEQ") and WRC have entered into a
consent order requiring further investigations of groundwater conditions and enhancements of existing remediation
systems. The Wynnewood refinery has completed the groundwater investigation and ODEQ has approved our
corrective action recommendations.
18
The anticipated investigation and remediation costs through 2021 were estimated, as of December 31, 2017, to
be as follows:
Facility
Site
Investigation
Costs
Capital
Costs
Total Operation &
Maintenance Costs
Through 2021
Total Estimated
Costs Through
2021
Coffeyville Refinery . . . . . . . . . . . . . . . . . . . . $
Phillipsburg Terminal . . . . . . . . . . . . . . . . . . .
Wynnewood Refinery . . . . . . . . . . . . . . . . . . .
Total Estimated Costs . . . . . . . . . . . . . . . . . . . $
0.1
0.3
—
0.4
$
$
(in millions)
— $
—
2.7
2.7
$
— $
—
0.9
0.9
$
0.1
0.3
3.6
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 2018, we will spend approximately $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 $2.0 million in 2017 associated with related remediation.
Financial Assurance. We are required under the 2004 Consent Decree to establish financial assurance to
secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event
we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decree as modified by a 2010
agreement between CRRM, CRT, the EPA and the KDHE, this financial assurance is currently provided by a bond in
the amount of $3.0 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of
$0.3 million for estimated costs to close regulated hazardous waste management units at the Coffeyville refinery.
Additional self-funded financial assurance of approximately $5.6 million and $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 $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
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. There 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 15 ("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. The policy includes business interruption
coverage. The policy insures any location owned, leased or rented or operated by the Company, including the
Coffeyville and Wynnewood refineries 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.
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In addition to the site pollution legal liability insurance policy, we maintain umbrella and excess casualty
insurance policies which include sudden and accidental pollution coverage. This insurance provides coverage due to
named perils for claims involving pollutants where the discharge is sudden and accidental and first commences at a
specific day and time during the policy period.
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.
Refer to Part II, Item 8, Note 15 ("Commitments and Contingencies"), "Wynnewood Refinery Incident" of this
Report for further discussion of OSHA matters related to the Wynnewood refinery boiler explosion.
Employees
As of December 31, 2017, 959 employees were employed by the petroleum business, 308 employees were
employed by the nitrogen fertilizer business and 173 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, 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, 2017, (i) the Coffeyville refinery employed 353 of the petroleum business' employees,
about 66% of whom are covered by a collective bargaining agreement with five unions of the Metal Trades
Department of the AFL-CIO ("Metal Trade Unions"), 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"), which expires in March 2019 and
automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the
relevant expiration date, and (iii) the Wynnewood refinery employed 300 of the petroleum business' employees,
about 59% of whom are covered by a collective bargaining agreement with the International Union of Operating
Engineers, which expires in June 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.
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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.
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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 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.
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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, 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, 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 2017. In 2017, the
Coffeyville refinery purchased approximately 75,000 to 80,000 bpd of crude oil while the Wynnewood refinery
purchased approximately 35,000 to 40,000 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. In 2017, the
Coffeyville refinery obtained a portion of its non-gathered crude oil, approximately 12%, 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
23
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 RFS mandates, the
petroleum business' financial condition and results of operations could be materially adversely affected.
The EPA has promulgated the Renewable Fuel Standard ("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 by the EPA. The
petroleum business is not able to blend the substantial majority of its transportation fuels, so 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.
In December 2015, 2016, and 2017, the EPA published in the Federal Register final rules establishing the
renewable fuel volume mandates for 2016, 2017, and 2018, and the biomass-based diesel volume mandates for
2017, 2018, and 2019, respectively. The volumes included in the EPA's final rules increased each year, but were
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 authorities to lower the volumes, but its decision to do so for the 2014-2016 compliance
years was challenged in the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit"). In July
2017, the D.C. Circuit vacated the EPA’s decision to reduce the renewable volume obligation for 2016 under one of
its waiver authorities, and remanded the rule to the EPA for further reconsideration. The EPA has not yet re-
proposed the 2016 renewable volume obligations. The EPA also has articulated a policy that high RINs prices
incentivize additional investments in renewable fuel blending and distribution infrastructure.
The petroleum business cannot predict the future prices of RINs or waiver credits. The price of RINs has been
extremely volatile 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 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
24
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 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 may 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.
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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
26
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
non-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.
These refineries generally require facility turnaround every four to five years. The length of the turnaround is
contingent upon the scope of work to be completed. The first phase of the Coffeyville refinery's most recent
turnaround was completed in November 2015 at a total cost of approximately $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 November 2017 at a total cost of approximately $67.4
million. The second phase of the Wynnewood turnaround is expected to occur in 2019. In addition to the two phase
turnaround, the petroleum business accelerated certain planned turnaround activities in 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 turnaround expenses for the 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
27
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 federal 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.
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The costs associated with operating the nitrogen fertilizer 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 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 Coffeyville 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 would have a material adverse effect on the nitrogen fertilizer business' results of operations,
financial condition and ability to make cash distributions.
Continued low natural gas prices could impact the 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.
Although 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
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 distributions.
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 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.
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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.
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.
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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.
In late 2013, the EPA recognized that the transportation fuels market had reached the “blend wall” for ethanol.
The blend wall refers to the aggregate limit to which ethanol can be blended into gasoline, and is generally
considered to be reached when a gallon of transportation fuel contains 10% ethanol by volume. As a result, since
2013, the EPA has used its waiver authorities to set lower renewable volume obligations than those mandated by the
RFS, though those volumes still 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 result in renewable fuel being blended
in volumes that exceed the ethanol blend wall, forcing the use of higher ethanol fuel blends or non-ethanol
renewable fuel. The EPA continues to articulate a policy to incentivize additional investments in renewable fuel
blending and distribution 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 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
RFS requires that a portion of the overall RFS renewable fuel mandate comes from advanced biofuels, including
cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste, 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 make 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,
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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.
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. 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.
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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 the
Coffeyville Fertilizer Facility; the City of Coffeyville, which supplies the Coffeyville 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.
Operations of the nitrogen fertilizer business' 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 Coffeyville 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, our nitrogen fertilizer business is party to an
electric services agreement with the City of Coffeyville, Kansas, which allows 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 our 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 our nitrogen fertilizer
business' operations (or a portion of our operations), even for a limited period, could have a material adverse effect
on our nitrogen fertilizer business' results of operations, financial condition and ability to make cash distributions.
The nitrogen fertilizer business' results of operations, financial condition and ability to make cash distributions
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 business' 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 Coffeyville 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.
Based 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.
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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 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 ability to make distributions.
The nitrogen fertilizer business relies on railroad and trucking companies to ship finished products to 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 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 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 distributions. The Coffeyville 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.
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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
hazardous 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 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
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used 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 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 Coffeyville Fertilizer Facility. If this license or any other license agreement 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.
The 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 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.
Our nitrogen fertilizer business' 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 our 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.
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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 ABL
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.
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 facilities 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;
37
•
•
•
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 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.
We are insured under casualty, environmental, property and business interruption insurance policies. The
property and business interruption policies insure real and personal property, including property located at our
Coffeyville and Wynnewood refineries and our 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. These policies are subject to limits, sub-limits, retention (financial and time-based) and
deductibles. The application of these and other policy conditions 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 resulting 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 low 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 process, there may
38
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 plants 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 plants or transportation of products or hazardous
substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and
potential cleanup responsibility) to governmental entities or private parties under federal, state or local
environmental laws, as well as under common law. For example, we could be held strictly liable under CERCLA,
and similar state statutes for past or future spills without regard to fault or whether our actions were in compliance
with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for
contamination associated with facilities we currently own or operate (whether or not such contamination occurred
prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we
transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment,
storage, or disposal.
The potential penalties and cleanup costs for past or future releases or spills, liability to third parties for damage
to their property or exposure to hazardous substances, or the need to address newly discovered information or
conditions that may require response actions could be significant and could have a material adverse effect on our
results of operations, financial condition and 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
cleanup 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 15 ("Commitments and Contingencies") of this Report). 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
39
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.
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 to regulate GHG from petroleum refineries at this time but that it may do so in the future.
The current administration has sought to implement a new or modified policy with respect to climate change.
For example, the administration announced its intention to withdraw the United States from 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 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 GHG 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 that implement the trading scheme before it becomes effective. To date, Kansas has taken no meaningful
action to implement the accord, and it is unclear whether Kansas intends to do so in the future.
Alternatively, the EPA may take further steps to regulate GHG 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.
40
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, 2017. The five largest customers of the nitrogen fertilizer business also represented approximately
31% of its net sales for the year ended December 31, 2017. The top petroleum customer accounts for approximately
19% of petroleum net sales and the top nitrogen fertilizer customer accounts for approximately 11% of nitrogen
fertilizer net 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.
41
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 could 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, future debt facilities and instruments incurred at our subsidiaries may impose significant
42
limitations on the ability of our subsidiaries to make distributions to us and 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, 2017, approximately 66% of the employees at the Coffeyville refinery, 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 unionized employees who work in crude transportation) expires in March 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 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
43
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 affect their
ability to operate their businesses, and may have a material adverse effect on their financial condition and
results of operations.
The Refining Partnership and the Nitrogen Fertilizer Partnership have incurred indebtedness and they may be
able to incur significant additional indebtedness in the future. If new indebtedness is added to their current
indebtedness, the risks described below could increase. Their level of indebtedness could 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 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 substantial portion of these funds to service debt;
limiting their ability to compete 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 instruments 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 react to changing market conditions in their respective industries and in their
respective customers' industries.
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In addition to their debt service obligations, the 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 their 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 business, depends on their financial and operating performance, which,
in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors.
In addition, the Refining Partnership and the Nitrogen Fertilizer Partnership are and will be subject to covenants
contained in agreements governing their present and future indebtedness. These covenants include, and will likely
include, restrictions on certain payments (including restrictions on distributions to 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 their
control; and
•
their future ability to obtain other financing.
We cannot offer any assurance that our businesses will generate sufficient cash flow from operations, that the
Refining Partnership will be able to draw under its Amended and Restated ABL Credit Facility, the intercompany
credit facility or otherwise, or that the Nitrogen Fertilizer Partnership will be able to draw under its ABL 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 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. Market or business conditions may limit their ability to avail themselves of some or all of
these options. Furthermore, any proceeds that they 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.
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The borrowings under the Refining Partnership's Amended and Restated ABL Credit Facility and intercompany
credit facility and the Nitrogen Fertilizer Partnership's ABL 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.
The debt agreements of the Refining Partnership and the Nitrogen Fertilizer Partnership 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 covenants that impose
significant operating and financial restrictions on them, including restrictions on their and their respective
subsidiaries' ability to, among other 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;
• make certain investments;
•
•
•
•
•
sell certain assets;
create liens on certain assets;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
enter into certain transactions with our affiliates; and
designate our subsidiaries as unrestricted subsidiaries.
Any of these restrictions could limit their ability to plan for or react to market conditions and could otherwise
restrict partnership activities. Any failure to comply with these covenants could result in a default under their debt
facilities and instruments. Upon a default, unless waived, the lenders under such debt facilities and instruments
would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making
further loans, institute foreclosure proceedings against their assets, and force them into bankruptcy or liquidation,
subject to any applicable intercreditor agreements. In addition, a default under their debt facilities and instruments
would trigger a cross default under their other agreements and could trigger a cross default under the agreements
governing their future indebtedness. The Refining Partnership's or Nitrogen Fertilizer Partnership's operating results
may not be sufficient to service their indebtedness or to fund their other expenditures and they may not be able to
obtain financing to meet these requirements.
46
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 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.
47
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, 2017. If the ACF and
Federal-Mogul plans were voluntarily terminated, they would be collectively underfunded by approximately $423.7
million and $613.4 million as of December 31, 2017 and 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-
48
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.
49
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
50
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 for
U.S. federal income tax purposes or if they 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.
The anticipated after-tax economic benefit of an investment in common units of the Refining Partnership or the
Nitrogen Fertilizer Partnership depends largely on each being treated as a partnership for 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
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. Distributions to their common unitholders (including us) would generally be taxed again as
corporate distributions, and no income, gains, losses or deductions would flow through to such common unitholders.
Because a tax would be imposed upon them as 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 us), likely causing a substantial reduction in the value of such
common 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
51
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 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 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 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 own 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
52
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
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.
53
Item 2. Properties
The following table contains certain information regarding our principal properties:
Location
Acres
Own/Lease
Use
Coffeyville, KS . . . . . . . . . . . . . . . . . . .
440 Own
Wynnewood, OK . . . . . . . . . . . . . . . . . .
400 Own
210 Own
East Dubuque, IL . . . . . . . . . . . . . . . . . .
Montgomery County, KS (Coffeyville
Station). . . . . . . . . . . . . . . . . . . . . . . . . .
Montgomery County, KS (Broome
Station). . . . . . . . . . . . . . . . . . . . . . . . . .
Cowley County, KS (Hooser Station) . .
Cushing, OK . . . . . . . . . . . . . . . . . . . . .
Refining Partnership: oil refinery and office
buildings
Nitrogen Fertilizer Partnership: fertilizer plant
Refining Partnership: oil refinery, office buildings,
refined oil storage
Nitrogen Fertilizer Partnership: fertilizer plant and
fertilizer storage
30 Own
Refining Partnership: crude oil storage
20 Own
70 Own
138 Own
Refining Partnership: crude oil storage
Refining Partnership: crude oil storage
Refining 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 administrative office space is leased in Kansas City, Kansas.
As of December 31, 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. The petroleum business leases additional crude oil
storage capacity of approximately 2.3 million barrels in Cushing, and 0.2 million barrels in Duncan, Oklahoma. In
addition to crude oil storage, the petroleum business owns over 4.6 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 15 ("Commitments and Contingencies") to our Consolidated Financial Statements as set
forth in Part II, Item 8 of this Report. In accordance with accounting 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.
54
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:
2017
First Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
High
Low
25.91
$
23.20
26.35
38.25
18.88
17.53
16.75
25.35
2016
First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Second Quarter. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
High
Low
38.98
$
26.57
16.39
25.41
22.05
14.87
13.01
12.03
Holders of Record
As of February 20, 2018, there were 124 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 following is a summary of the quarterly and special dividends paid to stockholders during the years ended
December 31, 2017 and 2016:
December 31,
2016
March 31, 2017
June 30, 2017
September 30,
2017
Total Dividends
Paid in 2017
(in millions, except per share data)
Dividend type . . . . . . . . . . . . . . . . . .
Amount paid to IEP . . . . . . . . . . . . . $
Amount paid to public
stockholders . . . . . . . . . . . . . . . . . . .
Total amount paid. . . . . . . . . . . . . . . $
Per common share . . . . . . . . . . . . . . $
Shares outstanding . . . . . . . . . . . . . .
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
142.4
31.3
173.7
2.00
55
December 31,
2015
March 31, 2016
June 30, 2016
September 30,
2016
Total Dividends
Paid in 2016
(in millions, except per share data)
Dividend type . . . . . . . . . . . . . . . . .
Amount paid to IEP . . . . . . . . . . . . $
Amounts paid to public
stockholders . . . . . . . . . . . . . . . . . .
Total amount paid . . . . . . . . . . . . . . $
Per common share. . . . . . . . . . . . . . $
Shares outstanding . . . . . . . . . . . . .
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
142.4
31.2
173.6
2.00
On February 21, 2018, the board of directors of the Company declared a cash dividend for the fourth quarter of
2017 to the Company's stockholders of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on
March 12, 2018 to stockholders of record at the close of business on 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 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 generated 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 will be determined by the board of directors of the Nitrogen Fertilizer
Partnership's general partner following the end of such quarter. Available cash for each 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, 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
expenses associated with the 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 and available cash is increased by the business interruption insurance
proceeds and the impact of purchase accounting. Actual distributions are set by the Nitrogen Fertilizer Partnership's
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. Adjusted EBITDA is defined as EBITDA (net income before interest expense, net, income tax expense,
depreciation and amortization) further adjusted for the impact of non-cash share-based compensation, and, where
applicable, major scheduled turnaround expenses, gain or loss on extinguishment of debt, loss on disposition of
assets, expenses associated with the East Dubuque Merger and business interruption insurance recovery.
56
The following is a summary of cash distributions paid by the Nitrogen Fertilizer Partnership to unitholders
during the years ended December 31, 2017 and 2016 for the respective quarters to which the distributions relate:
December 31,
2016
March 31, 2017
June 30, 2017
September 30,
2017
Total Dividends
Paid in 2017
(in millions, except per common unit data)
Amount paid to CRLLC. . . . . $
Amounts paid to public
unitholders . . . . . . . . . . . . . . .
Total amount paid. . . . . . . . . . $
Per common unit . . . . . . . . . . $
Common units outstanding. . .
— $
—
— $
— $
113.3
0.8
$
1.5
2.3
0.02
113.3
$
$
— $
—
— $
— $
— $
—
— $
— $
0.8
1.5
2.3
0.02
113.3
113.3
Amount paid to CRLLC. . . . . $
Amounts paid to public
unitholders . . . . . . . . . . . . . . .
Total amount paid. . . . . . . . . . $
Per common unit . . . . . . . . . . $
Common units outstanding. . .
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)
10.5
$
10.5
$
6.6
$
9.2
19.7
0.27
73.1
$
$
20.1
30.6
0.27
113.3
$
$
12.6
19.2
0.17
113.3
$
$
— $
—
— $
— $
113.3
27.6
41.9
69.5
0.71
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 the Refining Partnership's quarterly distribution or to otherwise 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, 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.
On October 31, 2017, the board of 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 distribution 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 during 2016.
57
Stock Performance Graph
The following graph sets forth the cumulative return on our common stock between January 1, 2011 and
December 31, 2017, as compared to the cumulative return of the Russell 2000 Index and an industry peer group
consisting of CHS Inc., Delek US Holdings, Inc., HollyFrontier Corporation, Phillips 66, and Valero Energy
Corporation. The graph assumes an investment of $100 on 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, 2017 was $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, 2012 AND DECEMBER 31, 2017
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.
Dec '12
Dec '13
Dec '14
Dec '15
Dec '16
Dec '17
CVR
Energy, Inc. . .
Russell 2000
Index . . . . . . .
Peer Group. . .
314.57
358.04
354.60
378.31
244.10
439.48
106.36
264.52
145.72
346.24
150.86
324.45
142.24
378.74
169.95
343.43
192.28
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, 2017.
58
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, 2017, 2016 and 2015 and the selected consolidated
financial information presented below under the caption "Balance Sheet Data" as of December 31, 2017 and 2016
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, 2014 and 2013 and the selected consolidated financial
information presented below under the caption "Balance Sheet Data" at December 31, 2015, 2014 and 2013 is
derived from our audited consolidated financial statements that are not included in this Report.
59
Statements of Operations Data
Net sales . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses: . . . . . .
Cost of materials and other. . . . . . . . .
Direct operating expenses(1) . . . . . . .
Depreciation and amortization . . . . . .
Cost of sales. . . . . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . .
Selling, general and administrative
expenses(1). . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . .
Operating income . . . . . . . . . . . . .
Interest expense and other financing
costs . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . .
Gain (loss) on derivatives, net . . . . . .
Loss on extinguishment of debt . . . . .
Other income (expense), net. . . . . . . .
Income (loss) before income tax
expense . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit) . . . . . . .
Net income. . . . . . . . . . . . . . . . . . .
Less: Net income (loss)
attributable to noncontrolling
interest
. . . . . . . . . . . . . . . . . . . . . .
Net income attributable to CVR
Energy stockholders . . . . . . . . . . . $
Year Ended December 31,
2017
2016
2015
2014
2013
(in millions, except per share data)
5,988.4
$
4,782.4
$
5,432.5
$
9,109.5
$
8,985.8
4,882.9
3,847.5
4,190.4
8,066.0
7,563.2
599.5
203.3
541.8
184.5
5,685.7
4,573.8
—
114.2
10.7
177.8
(110.1)
1.1
(69.8)
—
1.0
—
(216.9)
216.9
—
109.1
8.6
90.9
(83.9)
0.7
(19.4)
(4.9)
5.7
(10.9)
(19.8)
8.9
584.7
156.4
4,931.5
(27.3)
99.0
7.7
421.6
(48.4)
1.0
(28.6)
—
36.7
382.3
84.5
297.8
515.1
148.1
455.8
139.5
8,729.2
8,158.5
—
109.7
6.3
264.3
(40.0)
0.9
185.6
—
(3.7)
407.1
97.7
309.4
—
113.5
3.3
710.5
(50.5)
1.2
57.1
(26.1)
13.5
705.7
183.7
522.0
(17.5)
(15.8)
128.2
135.5
151.3
234.4
$
24.7
$
169.6
$
173.9
$
370.7
Basic and Diluted earnings per share . $
Dividends declared per share . . . . . . . $
2.70
2.00
$
$
0.28
2.00
$
$
1.95
2.00
$
$
2.00
5.00
$
$
4.27
14.25
Weighted-average common shares
outstanding: . . . . . . . . . . . . . . . . . . . .
Basic and Diluted . . . . . . . . . . . . .
86.8
86.8
86.8
86.8
86.8
60
Balance Sheet Data
Cash and cash equivalents . . . . . . . . . $
Working capital . . . . . . . . . . . . . . . . .
Total assets . . . . . . . . . . . . . . . . . . . . .
Total debt, including current portion .
Total CVR stockholders' equity . . . . .
Cash Flow Data
Net cash flow provided by (used in):
Operating activities . . . . . . . . . . . . . $
Investing activities . . . . . . . . . . . . . .
Financing activities . . . . . . . . . . . . .
Net increase (decrease) in cash
and cash equivalents . . . . . . . . . . $
Capital expenditures for property,
plant and equipment . . . . . . . . . . . . . . $
_______________________________________
2017
2016
Year Ended December 31,
2015
(in millions)
2014
2013
481.8
$
735.8
$
765.1
$
753.7
$
550.5
3,806.7
1,166.5
918.8
749.6
4,050.2
1,164.6
858.1
789.0
3,299.4
667.1
984.1
1,031.3
3,454.3
666.7
988.1
842.1
1,228.5
3,655.9
666.3
1,188.6
166.9
$
(195.0)
(225.9)
$
267.5
(201.4)
(95.4)
$
536.8
(150.6)
(374.8)
$
640.3
(296.6)
(432.1)
440.1
(250.3)
(243.7)
(254.0) $
(29.3) $
11.4
$
(88.4) $
(53.9)
118.6
$
132.7
$
218.7
$
218.4
$
256.5
(1) Amounts are shown exclusive of depreciation and amortization.
61
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 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;
62
•
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 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 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 facilities' 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.
63
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 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, 2017, 2016 and 2015, we generated consolidated net sales of $6.0 billion, $4.8 billion and $5.4
billion, respectively, and operating income of $177.8 million, $90.9 million and $421.6 million, respectively. The
petroleum business generated net sales of $5.7 billion, $4.4 billion and $5.2 billion, and the nitrogen fertilizer
business generated net sales of $330.8 million, $356.3 million and $289.2 million, in each case, for the years ended
December 31, 2017, 2016 and 2015, respectively. The petroleum business generated operating income of $203.8
million, $77.8 million and $361.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. The
nitrogen fertilizer business generated operating (loss) income of $(9.2) million, $26.8 million and $68.7 million for
the years ended December 31, 2017, 2016 and 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.
East Dubuque Merger
On 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 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. 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 accounted for the East Dubuque Merger as an
acquisition of a business with the 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 3 ("Acquisition") of this Report for further discussion of the 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. 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. The
common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."
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.
64
As of December 31, 2017, public security holders held approximately 34% of all outstanding limited partner
interests of the Refining Partnership (including common units owned by affiliates of IEP, representing
approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings held approximately
66% of all outstanding limited partner interests of the Refining Partnership. In addition, CVR Refining Holdings
owns 100% of the Refining Partnership's general partner, CVR Refining GP, which holds a non-economic general
partner interest.
65
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 the 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 products are also affected by other factors, such as
product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs
and the prices of refined products have historically been subject to wide fluctuations. 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 volatile seasonal exports of
diesel from the 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 RFS, which requires it to either blend "renewable fuels" in with its transportation fuels or
purchase RINs, in lieu of 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 RFS
mandates, the petroleum business' financial condition and results of operations could be materially adversely
affected, and Part II, Item 8, Note 15 ("Commitments and Contingencies"), "Environmental, Health and Safety
("EHS") Matters" of this Report for further discussion of the RFS.
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. 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 $200.0 million for the year ending December 31, 2018.
In order to assess its operating performance, the petroleum business compares net sales, less cost of materials
and 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.
66
Although the 2-1-1 crack spread is a benchmark for the refining 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 refining 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 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 refining 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 2017 was $0.29 per barrel
compared to consumed crude oil cost discounts of $1.58 per barrel in 2016 and $1.12 per barrel in 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 expansions in recent years expanding the connectivity of Cushing and Permian Basin
markets to the gulf coast, along 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 has seen a downward movement in
refining margins as a result. The stabilization of oil 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, 2017, a $1.00 change in natural gas prices would have increased or
decreased the petroleum business' natural gas costs by approximately $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 from period to period.
67
Safe and reliable operations at the refineries are key to the petroleum business' financial performance and results
of operations. Unscheduled 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 scheduled downtime, such as major turnaround maintenance,
through a diligent planning process that takes into account the margin environment, the availability of resources to
perform the needed maintenance, feedstock logistics and other factors. 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. The first phase of the Coffeyville refinery's most recent turnaround was completed in November 2015 at
a total cost of approximately $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 November 2017 at a total cost of approximately $67.4 million. The second phase of the Wynnewood
turnaround is expected to occur in 2019. Turnaround expenses associated with the second phase of 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 in 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 turnaround
expenses for the hydrocracker.
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 operating costs and 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 came online in 2017. The nitrogen fertilizer business expects product
pricing may experience volatility as the new supply displaces imports into the 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.
While there is risk of shorter-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
68
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 its operating performance, 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") and
delivered to the customer's designated delivery site ("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.
The nitrogen fertilizer business' 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 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, 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 200 miles of the facility. In most instances, customers take delivery of
nitrogen products at the plant and arrange and pay to 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.
The nitrogen fertilizer business upgrades 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. For the years ended
December 31, 2017, 2016 and 2015, the nitrogen fertilizer business upgraded approximately 88%, 93% and 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 Coffeyville Fertilizer Facility's direct operating expense structure also directly affects
its profitability. Using a pet coke gasification process, the Coffeyville Fertilizer Facility results in a significantly
higher percentage of fixed costs than a natural gas-based fertilizer 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' 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, 2017, 2016 and 2015, the nitrogen fertilizer business incurred approximately $8.1
million, $7.8 million and $11.9 million, respectively, for pet coke, which equaled an average cost per ton of $17, $15
and $25, respectively.
The nitrogen fertilizer business' largest raw material expense used in the production of ammonia at its East
Dubuque Facility is natural gas, which it purchases from third parties. The East Dubuque Facility's natural gas
69
process results in a higher percentage of variable costs as compared to the Coffeyville Fertilizer Facility. For the
year ended December 31, 2017, and 2016 the East Dubuque Facility incurred approximately $26.3 million and $13.3
million for feedstock natural gas, which equaled an average cost of $3.26 and $2.87 per MMBtu.
Consistent, safe and reliable operations at the nitrogen fertilizer plants are critical to its financial performance
and results of operations. In 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
business 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.
Historically, the Coffeyville Fertilizer Facility has undergone a full facility turnaround approximately every two
to three years. The Coffeyville Fertilizer Facility underwent a full facility turnaround in the third quarter of 2015 and
the 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. The Coffeyville Facility is
planning to undergo the next scheduled full facility turnaround in the second quarter of 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 we
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; (vi) an easement agreement; (vii) an environmental agreement; and
(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.
70
In connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining
Partnership, including (i) a $150.0 million intercompany credit facility between CRLLC and the Refining
Partnership and (ii) a services agreement, pursuant to which we provide certain services to the petroleum business.
The intercompany credit facility matures in 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 8, Note 18 ("Related Party Transactions") of this Report for
further discussion of the CRLLC Facility.
Crude Oil Supply Agreement
Refer to Part II, Item 8, Note 15 ("Commitments and Contingencies") of this Report for information on the
crude oil 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.
Loss on extinguishment of debt(1) . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses(2) . . . . . . . . . . . . . . . . . . . . .
Flood insurance recovery(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
_______________________________________
Year Ended December 31,
2017
2016
2015
(in millions)
$
— $
4.9
$
69.8
83.0
—
19.4
38.1
—
—
28.6
109.2
(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 the unamortized purchase accounting adjustment.
(2) Represents expense associated with major scheduled turnaround activities performed at the Coffeyville and
Wynnewood refineries, the East Dubuque Facility and the Coffeyville Facility.
(3) Represents an insurance recovery from environmental insurance carriers as a result of the flood and crude oil
discharge at the Coffeyville refinery in June/July 2007. Refer to Part II, Item 8, Note 15 ("Commitments and
Contingencies") of this Report for further details.
71
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
The non-controlling interest related to the Refining Partnership reflected in our consolidated financial
statements is approximately 34%.
Immediately following the closing of the East Dubuque Merger and as of December 31, 2017, the
noncontrolling interest related to the Nitrogen Fertilizer Partnership reflected in our consolidated financial
statements is approximately 66%. Prior to April 1, 2016, the noncontrolling interest related to the Nitrogen 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, 2017 and 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, 2017 and 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, 2017 and 2016.
Petroleum Business
Industry Factors
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 advantaged crude to the mid-continent
72
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 6.4 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
Commodities
The nitrogen fertilizer business' products are globally traded commodities and are subject to price competition.
The customers for its 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 supply and demand.
Agricultural
The three primary forms of nitrogen fertilizer used in the 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.
73
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.
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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, 2017 with the year ended December 31, 2016 and the year ended December 31, 2016 with the year
ended December 31, 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 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.
75
The following table provides an overview of our results of operations during the past three fiscal years:
Consolidated Statements of Operations Data
Net sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses:
Cost of materials and other . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses(1). . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . .
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative expenses(1) . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense and other financing costs . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt. . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income tax expense. . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Net income (loss) attributable to
noncontrolling interest
. . . . . . . . . . . . . . . . . . . . . .
Net income attributable to CVR Energy
stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Basic and diluted earnings per share . . . . . . . . . . . . . . $
Dividends declared per share. . . . . . . . . . . . . . . . . . . . $
Adjusted EBITDA(2) . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
2015
(in millions, except per share data)
5,988.4
$
4,782.4
$
5,432.5
4,882.9
599.5
203.3
5,685.7
—
114.2
10.7
177.8
(110.1)
1.1
(69.8)
—
1.0
—
(216.9)
216.9
(17.5)
234.4
2.70
2.00
258.4
$
$
$
$
3,847.5
541.8
184.5
4,573.8
—
109.1
8.6
90.9
(83.9)
0.7
(19.4)
(4.9)
5.7
(10.9)
(19.8)
8.9
(15.8)
24.7
0.28
2.00
181.6
$
$
$
$
4,190.4
584.7
156.4
4,931.5
(27.3)
99.0
7.7
421.6
(48.4)
1.0
(28.6)
—
36.7
382.3
84.5
297.8
128.2
169.6
1.95
2.00
498.8
Weighted-average common shares outstanding: . . . . .
Basic and diluted. . . . . . . . . . . . . . . . . . . . . . . . . . .
_______________________________________
(1) Amounts are shown exclusive of depreciation and amortization.
86.8
86.8
86.8
76
(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; (ii) income tax
expense (benefit); and (iii) depreciation and amortization, less the portion of these adjustments attributable
to non-controlling interest. Adjusted EBITDA represents EBITDA adjusted for consolidated (i) FIFO
impact (favorable) unfavorable; (ii) loss on extinguishment of debt; (iii) major scheduled turnaround
expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and
Adjusted EBITDA); (iv) (gain) loss on derivatives, net; (v) current period settlements on derivative
contracts; (vi) flood insurance recovery; (vii) expenses associated with the 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. We 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. EBITDA and Adjusted EBITDA represent EBITDA and
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.
77
Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the years ended
December 31, 2017, 2016 and 2015:
Net income attributable to CVR Energy stockholders . . . $
Add:
Interest expense and other financing costs, net of
interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization. . . . . . . . . . . . . . . . . . . .
Adjustments attributable to noncontrolling interest. . . .
EBITDA. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add:
FIFO impact, (favorable) unfavorable . . . . . . . . . . . . . .
Share-based compensation(a) . . . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt(b) . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses. . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . .
Current period settlement on derivative contracts(c). . .
Flood insurance recovery(d) . . . . . . . . . . . . . . . . . . . . .
Expenses associated with the East Dubuque Merger(e)
Insurance recovery - business interruption(f) . . . . . . . .
Adjustments attributable to noncontrolling interest. . . .
Adjusted EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
_______________________________________
Year Ended December 31,
2017
2016
(in millions)
(unaudited)
2015
234.4
$
24.7
$
169.6
109.0
(216.9)
214.0
(151.2)
189.3
(29.6)
—
—
83.0
69.8
(16.6)
—
—
(1.1)
(36.4)
258.4
$
83.2
(19.8)
193.1
(127.3)
153.9
(52.1)
—
4.9
38.1
19.4
36.4
—
3.1
(2.1)
(20.0)
181.6
$
47.4
84.5
164.1
(75.2)
390.4
60.3
12.8
—
109.2
28.6
(26.0)
(27.3)
2.3
—
(51.5)
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 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.
(d) Represents an insurance recovery from environmental insurance carriers as a result of the flood and crude
oil discharge at the Coffeyville refinery in June/July 2007. Refer to Part II, Item 8, Note 15 ("Commitments
and Contingencies") of this Report for further details.
(e) Represents legal and other professional fees and other merger related expenses that are referred to herein as
transaction expenses associated with the East Dubuque Merger, which are included in selling, general and
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.
78
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016 (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
79
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. The decrease of $650.1 million was largely the result of a
decrease in our petroleum segment's net sales of $730.6 million due to significantly lower sales 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, 2016 of $1.34 for gasoline and $1.36 for distillate decreased by 16.8% and
16.0%, respectively, as compared to the year ended December 31, 2015. The nitrogen fertilizer segment net sales
increased by $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 the major scheduled
turn around at the Coffeyville Fertilizer Facility in 2015, partially offset by lower UAN and ammonia sales prices
attributable to pricing fluctuation in the market.
Cost of Materials and Other. Consolidated cost of materials and 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. The decrease of $342.9
million primarily resulted from a decrease of $384.4 million in cost of materials 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 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 decreases as a result of lower freight and distribution costs as well as lower
consumption and pet 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. The decrease of $42.9 million was primarily
due to a decrease of $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
an increase in labor costs. The nitrogen fertilizer segment increased primarily attributable to the inclusion of the nine
months of 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. The
increase of $10.1 million was primarily attributable to the inclusion of the nine months of the East Dubuque Facility.
80
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, a decrease of $330.7
million. Petroleum segment operating income decreased $283.9 million primarily as a result of a decrease in the
refining margin in 2016 and the 2015 flood insurance recovery, partially offset by decreases in direct operating
expenses, depreciation and amortization and selling, general and administrative expenses. Nitrogen fertilizer
segment operating income decreased $41.9 million primarily as a result of increases in direct operating expenses,
depreciation and amortization, cost of materials and other and selling, general and administrative expenses, partially
offset by increases in net sales.
Interest Expense. Consolidated interest expense for the year ended December 31, 2016 was $83.9 million as
compared to $48.4 million for the year ended December 31, 2015. The increase of $35.5 million resulted primarily
from the debt 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 2015.
Gain (Loss) on Derivatives, Net. For the year ended December 31, 2016, the petroleum segment recorded a
$19.4 million net loss on derivatives compared to a $28.6 million net loss on derivatives for the year ended
December 31, 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 benefit for the year ended December 31, 2016 was $19.8 million or 181.7%
of loss before income taxes, as compared to income tax expense for the year ended December 31, 2015 of $84.5
million or 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. Our 2016 effective tax rate varies 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 (loss), the benefits related to the domestic production activities
deduction (Section 199) and certain state income tax items.
81
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, 2017, 2016 and 2015:
Consolidated Petroleum Business Financial Results
Net sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses:
Cost of materials and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses(1)(2) . . . . . . . . . . . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative expenses(1) . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense and other financing costs . . . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income before income tax expense. . . . . . . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Gross profit(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Refining margin(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Adjusted Petroleum EBITDA(5). . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
(in millions)
2015
5,664.2
$
4,431.3
$
5,161.9
4,804.7
3,759.2
4,143.6
363.4
80.4
129.3
361.9
31.5
126.3
5,377.8
4,278.9
—
78.8
3.8
203.8
(47.2)
0.5
(69.8)
1.5
88.8
—
88.8
286.4
859.5
372.6
$
$
$
$
—
71.9
2.7
77.8
(43.4)
0.1
(19.4)
0.2
15.3
—
15.3
152.4
672.1
222.8
$
$
$
$
376.3
102.2
128.0
4,750.1
(27.3)
75.2
2.2
361.7
(42.6)
0.4
(28.6)
0.3
291.2
—
291.2
439.1
1,018.3
602.0
82
Year Ended December 31,
2017
2016
2015
(dollars per barrel)
Key Operating Statistics
Per crude oil throughput barrel:
Gross profit(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Refining margin(4) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FIFO impact, (favorable) unfavorable. . . . . . . . . . . . . . . . . . .
Refining margin adjusted for FIFO impact(4) . . . . . . . . . . . . .
Direct operating expenses and major scheduled turnaround
expenses(1)(2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses and major scheduled turnaround
expenses per barrel sold(1)(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Barrels sold (barrels per day)(6) . . . . . . . . . . . . . . . . . . . . . . . . . .
3.83
$
2.10
$
11.50
(0.40)
11.10
5.94
9.27
(0.72)
8.55
5.43
5.55
$
5.08
$
6.23
14.45
0.86
15.31
6.79
6.40
218,912
211,643
204,708
Year Ended December 31,
2017
%
2016
%
2015
%
Refining Throughput and
Production Data (bpd)
Throughput:
Sweet . . . . . . . . . . . . . . . . . . . . . .
Medium . . . . . . . . . . . . . . . . . . . .
Heavy sour . . . . . . . . . . . . . . . . . .
Total crude oil throughput . . . .
All other feedstocks and
blendstocks . . . . . . . . . . . . . . . . . .
Total throughput . . . . . . . . . . .
Production:
Gasoline . . . . . . . . . . . . . . . . . . . .
Distillate . . . . . . . . . . . . . . . . . . . .
Other (excluding internally
produced fuel) . . . . . . . . . . . . . . .
Total refining production
(excluding internally produced
fuel) . . . . . . . . . . . . . . . . . . . . .
Product price (dollars per gallon):
194,613
—
10,135
204,748
12,032
216,780
110,226
90,409
89.8
—
4.7
94.5
5.5
100.0
177,256
2,525
18,261
198,042
11,077
209,119
50.7
41.6
108,762
85,092
84.8
1.2
8.7
94.7
5.3
100.0
51.9
40.6
176,097
2,460
14,520
193,077
11,672
204,749
99,961
85,953
16,818
7.7
15,751
7.5
20,074
86.0
1.2
7.1
94.3
5.7
100.0
48.5
41.7
9.8
217,453
100.0
209,605
100.0
205,988
100.0
Gasoline . . . . . . . . . . . . . . . . . . . . $
Distillate . . . . . . . . . . . . . . . . . . . .
1.59
1.66
$
1.34
1.36
$
1.61
1.62
83
Market Indicators (dollars per barrel)
West Texas Intermediate (WTI) NYMEX. . . . . . . . . . . . . . . . . . . $
Crude Oil Differentials:
WTI less WTS (light/medium sour) . . . . . . . . . . . . . . . . . . . . .
WTI less WCS (heavy sour) . . . . . . . . . . . . . . . . . . . . . . . . . . .
NYMEX Crack Spreads:
Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Heating Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
NYMEX 2-1-1 Crack Spread . . . . . . . . . . . . . . . . . . . . . . . . . .
PADD II Group 3 Product Basis:
Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ultra-Low Sulfur Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PADD II Group 3 Product Crack Spread:
Gasoline . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ultra-Low Sulfur Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PADD II Group 3 2-1-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
_______________________________________
Year Ended December 31,
2017
2016
2015
50.85
$
43.47
$
48.76
0.97
12.69
17.46
18.93
18.19
(1.83)
(0.50)
15.63
18.42
17.03
0.85
13.95
15.42
13.89
14.66
(3.62)
(0.92)
11.82
12.96
12.39
(0.28)
13.20
19.89
20.93
20.41
(2.12)
(2.02)
17.76
18.91
18.34
(1)
(2)
(3)
(4)
Amounts are shown exclusive of depreciation and amortization.
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.
Gross profit, a GAAP measure, is calculated as the difference between net sales and cost of materials and
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.
Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net
sales and cost of materials and 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 their cost
of materials and other at which they are able to sell refined products. Each of the components used in this
calculation (net sales and cost of materials and 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 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.
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
84
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:
Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Cost of materials and other . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses (exclusive of depreciation
and amortization as reflected below) . . . . . . . . . . . . . . .
Major scheduled turnaround expenses . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add:
Direct operating expenses (exclusive of depreciation
and amortization as reflected below) . . . . . . . . . . . . . . .
Major scheduled turnaround expenses . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . .
Refining margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FIFO impact, (favorable) unfavorable . . . . . . . . . . . . . .
Refining margin adjusted for FIFO impact. . . . . . . . . . . $
2017
Year Ended
December 31,
2016
(in millions)
2015
5,664.2
$
4,431.3
$
4,804.7
3,759.2
5,161.9
4,143.6
363.4
80.4
—
129.3
286.4
363.4
80.4
—
129.3
859.5
(29.6)
829.9
$
361.9
31.5
—
126.3
152.4
361.9
31.5
—
126.3
672.1
(52.1)
620.0
376.3
102.2
(27.3)
128.0
439.1
376.3
102.2
(27.3)
128.0
1,018.3
60.3
$
1,078.6
85
Total crude oil throughput barrels per day . . . . . . . . . . .
Days in the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total crude oil throughput barrels . . . . . . . . . . . . . . .
Year Ended
December 31,
2016
198,042
366
2017
204,748
365
2015
193,077
365
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Divided by: crude oil throughput barrels . . . . . . . . . . . .
Refining margin per crude oil throughput barrel . . . . $
859.5
74.7
11.50
$
$
672.1
72.5
9.27
$
$
1,018.3
70.5
14.45
Refining margin adjusted for FIFO impact. . . . . . . . . . . $
Divided by: crude oil throughput barrels . . . . . . . . . . . .
Refining margin adjusted for FIFO impact per crude
oil throughput barrel. . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended
December 31,
2017
2016
2015
(in millions, except for $ per barrel data)
829.9
$
620.0
$
1,078.6
74.7
72.5
70.5
11.10
$
8.55
$
15.31
86
(5)
Petroleum EBITDA represents net income for the petroleum segment before (i) interest expense and other
financing costs, net of interest income; (ii) income tax expense; and (iii) depreciation and amortization.
Adjusted Petroleum EBITDA represents Petroleum EBITDA adjusted for (i) FIFO impact (favorable)
unfavorable; (ii) share-based compensation, non-cash; (iii) loss on extinguishment of debt; (iv) major
scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their
measures of EBITDA and Adjusted EBITDA); (v) (gain) loss on derivatives, net; (vi) current period
settlements on derivative contracts; and (vii) flood insurance recovery.
We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership's
determination of available cash for distribution. Petroleum EBITDA and Adjusted Petroleum EBITDA are
not recognized terms under GAAP and should not be substituted for net income or 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, 2017, 2016 and 2015:
Petroleum:
Petroleum net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Add:
Interest expense and other financing costs, net of interest
income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income tax expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Petroleum EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add:
FIFO impact, (favorable) unfavorable(a) . . . . . . . . . . . . . . . . .
Share-based compensation, non-cash . . . . . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses(b). . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current period settlements on derivative contracts(c) . . . . . . .
Flood insurance recovery(d) . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjusted Petroleum EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
_______________________________________
Year Ended December 31,
2017
2016
(in millions)
2015
88.8
$
15.3
$
291.2
46.7
—
133.1
268.6
(29.6)
—
80.4
69.8
(16.6)
—
43.3
—
129.0
187.6
(52.1)
—
31.5
19.4
36.4
—
372.6
$
222.8
$
42.2
—
130.2
463.6
60.3
0.6
102.2
28.6
(26.0)
(27.3)
602.0
(a) FIFO is the petroleum business' basis for determining inventory value 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
87
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 at the Coffeyville and
Wynnewood 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 environmental insurance carriers as a result of the flood and crude
oil discharge at the Coffeyville refinery in June/July 2007. Refer to Part II, Item 8, Note 15 ("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.
Coffeyville Refinery Financial Results
Net sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Cost of materials and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses (exclusive of depreciation and
amortization as reflected below) . . . . . . . . . . . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plus:
Direct operating expenses and major scheduled turnaround
expenses (exclusive of depreciation and amortization as
reflected below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Refining margin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FIFO impact, (favorable) unfavorable. . . . . . . . . . . . . . . . . . . . . .
Refining margin adjusted for FIFO impact . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
(in millions)
2015
3,867.8
$
2,948.9
$
3,285.8
2,513.9
3,220.6
2,626.1
209.5
—
71.5
—
301.0
209.5
—
71.5
582.0
(20.2)
561.8
$
196.4
31.5
69.7
—
137.4
227.9
—
69.7
435.0
(37.8)
397.2
$
209.1
102.2
72.1
(27.3)
238.4
311.3
(27.3)
72.1
594.5
38.0
632.5
88
Coffeyville Refinery Key Operating Statistics
Per crude oil throughput barrel:
Gross profit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Refining margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
FIFO impact, (favorable) unfavorable . . . . . . . . . . . . . . . . . . . $
Refining margin adjusted for FIFO impact(1) . . . . . . . . . . . . . $
Direct operating expenses and major scheduled turnaround
expenses (exclusive of depreciation and amortization) . . . . . . $
Direct operating expenses and major scheduled turnaround
expenses (exclusive of depreciation and amortization) per barrel
sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Barrels sold (barrels per day) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
2016
2015
(dollars per barrel)
6.27
$
$
12.12
(0.42) $
$
11.70
3.03
$
$
9.57
(0.83) $
$
8.74
5.77
14.37
0.92
15.29
4.36
$
5.02
$
7.53
4.00
$
4.54
$
143,598
137,047
6.92
123,279
Coffeyville Refinery Throughput
and Production Data (bpd)
Throughput:
Sweet . . . . . . . . . . . . . . . . . . . . . .
Medium . . . . . . . . . . . . . . . . . . . .
Heavy sour . . . . . . . . . . . . . . . . . .
Total crude oil throughput . . . .
All other feedstocks and
blendstocks . . . . . . . . . . . . . . . . . .
Total throughput . . . . . . . . . . .
Production:
Gasoline . . . . . . . . . . . . . . . . . . . .
Distillate . . . . . . . . . . . . . . . . . . . .
Other (excluding internally
produced fuel) . . . . . . . . . . . . . . .
Total refining production
(excluding internally produced
fuel) . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
%
2016
%
2015
%
121,434
—
10,135
131,569
9,058
140,627
71,915
59,593
11,335
86.4
—
7.2
93.6
6.4
100.0
50.4
41.7
7.9
104,679
1,229
18,261
124,169
8,453
132,622
69,303
55,790
78.9
0.9
13.8
93.6
6.4
100.0
51.4
41.4
96,727
2,058
14,520
113,305
8,400
121,705
57,815
53,136
9,756
7.2
13,503
79.5
1.7
11.9
93.1
6.9
100.0
46.5
42.7
10.8
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:
89
Total crude oil throughput barrels per day. . . . . . . . . . . . . . . .
Days in the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total crude oil throughput barrels . . . . . . . . . . . . . . . . . . .
Year Ended
December 31,
2016
124,169
366
2017
131,569
365
2015
113,305
365
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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Divided by: crude oil throughput barrels. . . . . . . . . . . . . . . . .
Refining margin per crude oil throughput barrel . . . . . . . . $
582.0
48.0
12.12
$
$
435.0
45.4
9.57
$
$
594.5
41.4
14.37
Year Ended
December 31,
2017
2016
2015
(in millions, except for $ per barrel data)
561.8
$
397.2
$
48.0
45.4
632.5
41.4
11.70
$
8.74
$
15.29
Year Ended December 31,
2017
2016
(in millions)
2015
1,792.1
$
1,478.0
$
1,519.7
1,245.4
1,936.9
1,516.3
153.9
80.4
51.7
(13.6)
234.3
51.7
272.4
(9.4)
263.0
$
165.5
—
50.7
16.4
165.5
50.7
232.6
(14.2)
218.4
$
166.2
—
50.2
204.2
166.2
50.2
420.6
22.3
442.9
Refining margin adjusted for FIFO impact . . . . . . . . . . . . . . . $
Divided by: crude oil throughput barrels. . . . . . . . . . . . . . . . .
Refining margin adjusted for FIFO impact per crude oil
throughput barrel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Wynnewood Refinery Financial Results
Net sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Cost of materials and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses (exclusive of depreciation and
amortization as reflected below) . . . . . . . . . . . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gross profit (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Plus:
Direct operating expenses and major scheduled turnaround
expenses (exclusive of depreciation and amortization as
reflected below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Refining margin. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
FIFO impact, (favorable) unfavorable. . . . . . . . . . . . . . . . . . . . . .
Refining margin adjusted for FIFO impact . . . . . . . . . . . . . . . . . . $
90
Wynnewood Refinery Key Operating Statistics
Per crude oil throughput barrel:
Gross profit (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Refining margin(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
FIFO impact, (favorable) unfavorable . . . . . . . . . . . . . . . . . . . $
Refining margin adjusted for FIFO impact(1) . . . . . . . . . . . . . $
Direct operating expenses and major scheduled turnaround
expenses (exclusive of depreciation and amortization) . . . . . . $
Direct operating expenses and major scheduled turnaround
expenses (exclusive of depreciation and amortization) per barrel
sold . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Barrels sold (barrels per day) . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
2016
2015
(dollars per barrel)
(0.51) $
$
10.20
(0.35) $
$
9.85
0.61
$
$
8.60
(0.53) $
$
8.07
7.01
14.44
0.77
15.21
8.77
$
6.12
$
5.71
8.52
$
6.06
$
75,314
74,596
5.59
81,429
Wynnewood Refinery
Throughput and Production
Data (bpd)
Throughput:
Sweet . . . . . . . . . . . . . . . . . . . . . .
Medium . . . . . . . . . . . . . . . . . . . .
Heavy sour . . . . . . . . . . . . . . . . . .
Total crude oil throughput . . . .
All other feedstocks and
blendstocks . . . . . . . . . . . . . . . . . .
Total throughput . . . . . . . . . . .
Production:
Gasoline . . . . . . . . . . . . . . . . . . . .
Distillate . . . . . . . . . . . . . . . . . . . .
Other (excluding internally
produced fuel) . . . . . . . . . . . . . . .
Total refining production
(excluding internally produced
fuel) . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
%
2016
%
2015
%
73,179
—
—
96.1
—
—
72,577
1,296
—
73,179
96.1
73,873
2,974
76,153
38,311
30,816
5,483
3.9
100.0
51.3
41.3
7.4
2,624
76,497
39,459
29,302
5,995
94.9
1.7
—
96.6
3.4
100.0
52.8
39.2
8.0
79,370
402
—
79,772
3,272
83,044
42,146
32,817
6,571
95.6
0.5
—
96.1
3.9
100.0
51.7
40.2
8.1
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:
91
Total crude oil throughput barrels per day. . . . . . . . . . . . . . . .
Days in the period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total crude oil throughput barrels . . . . . . . . . . . . . . . . . . .
Year Ended
December 31,
2017
2016
2015
73,179
365
73,873
366
79,772
365
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. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Divided by: crude oil throughput barrels. . . . . . . . . . . . . . . . .
Refining margin per crude oil throughput barrel . . . . . . . . $
272.4
26.7
10.20
$
$
232.6
27.0
8.60
$
$
420.6
29.1
14.44
Refining margin adjusted for FIFO impact . . . . . . . . . . . . . . . $
Divided by: crude oil throughput barrels. . . . . . . . . . . . . . . . .
Refining margin adjusted for FIFO impact per crude oil
throughput barrel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended
December 31,
2017
2016
2015
(in millions, except for $ per barrel data)
263.0
$
218.4
$
26.7
27.0
442.9
29.1
9.85
$
8.07
$
15.21
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016 (Petroleum Business)
Net Sales. Petroleum net sales were $5,664.2 million for the year ended December 31, 2017, compared to
$4,431.3 million for the year ended December 31, 2016. The increase of $1,232.9 million was largely the result of
higher sales prices for transportation fuels and by-products. The average sales price per gallon for the year ended
December 31, 2017 for gasoline of $1.59 and distillate of $1.66 increased by approximately 18.7% and 22.1%,
respectively, as compared to the year ended December 31, 2016. Overall sales volume increased approximately
4.7% for the year ended December 31, 2017 compared to the year ended December 31, 2016. Sales volumes
increased 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 increase in sales was an increase in
products purchased for resale for the year ended December 31, 2017 as compared to the 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, 2017 compared to the year ended December 31, 2016:
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
(in millions)
Gasoline. . . . . . . .
Distillate . . . . . . .
44.3
34.4
$
$
66.90
$ 2,966.8
69.71
$ 2,399.8
42.6
32.4
$
$
56.16
$2,390.8
56.99
$1,844.3
1.7
2.0
$
$
576.0
555.5
$
$
476.3
438.0
$
$
99.7
117.5
_______________________________________
(1)
(2)
Barrels in millions
Sales dollars in millions
92
Cost of Materials and Other. Cost of materials and other includes cost of crude oil, other feedstocks,
blendstocks, purchased refined products, RINs and transportation and distribution costs. Petroleum cost of materials
and other was $4,804.7 million for the year ended December 31, 2017, compared to $3,759.2 million for the year
ended December 31, 2016. The increase of $1,045.5 million was primarily the result of a an increase in the cost of
consumed crude and purchased products for resale. The increase in consumed crude oil cost was due to an increase
in crude oil prices. The WTI benchmark crude oil price increased approximately 17.0% from the year ended
December 31, 2017 as compared to the year ended December 31, 2016. The petroleum business' average cost per
barrel of crude oil consumed for the year ended December 31, 2017 was $50.63 compared to $41.99 for the year
ended December 31, 2016, a increase of approximately 20.6%. Crude oil throughput volume increased by
approximately 3.1% for the year ended December 31, 2017 as compared to the equivalent period in 2016 due
primarily to the major scheduled turnaround completed at the Coffeyville refinery in the first quarter of 2016. Sales
volumes of refined fuels increased by approximately 4.7% during the same period.
The impact of FIFO accounting also impacted cost of materials 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, 2017 and 2016, the petroleum business had an favorable FIFO inventory impact of $29.6 million
compared to a favorable FIFO inventory impact of $52.1 million, respectively.
Refining margin per barrel of crude oil throughput increased to $11.50 for the year ended December 31, 2017
from $9.27 for the year ended December 31, 2016. Refining margin adjusted for FIFO impact was $11.10 per crude
oil throughput barrel for the year ended December 31, 2017, as compared to $8.55 per crude oil throughput barrel
for the year ended December 31, 2016. Gross profit per barrel increased to $3.83 for the year ended December 31,
2017, as compared to gross profit per barrel of $2.10 in the equivalent period in 2016. The increase in refining
margin and gross profit per barrel was primarily due to the improvement in product margins. The benchmark 2-1-1
crack spread improved to $18.19 per barrel for the year 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 Group 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 $443.8 million for the year ended
December 31, 2017, compared to direct operating expenses and major scheduled turnaround expenses of $393.4
million for the year ended December 31, 2016. The increase of $50.4 million was 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 ($48.9
million), and higher utilities costs ($8.4 million). These increases were partially offset by a decrease in repair and
maintenance costs ($7.1 million). Utilities costs increased primarily due to a 28.1% increase in the petroleum
business' natural gas cost per MMBtu and a 15.3% increase in its electricity cost per Kilowatt Hour ("KWH").
Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2017 increased to
$5.94 per barrel as compared to $5.43 per barrel for the year ended December 31, 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
93
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 $203.8 million for the year ended December 31, 2017, as
compared to operating income of $77.8 million for the year ended December 31, 2016. The increase of $126.0
million was the result of an increase in refining margin ($187.4 million) due to higher sales prices for our
transportation fuels and by-products which was, partially offset by increases in direct operating expenses ($50.4
million), depreciation and amortization ($4.1 million) and selling, general and administrative expenses ($6.9
million).
Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Net Sales. Petroleum net sales were $4,431.3 million for the year ended December 31, 2016, compared to
$5,161.9 million for the year ended December 31, 2015. The decrease of $730.6 million was largely the result of
lower sales prices for transportation fuels and by-products. The average sales price per gallon for the year ended
December 31, 2016 for gasoline of $1.34 and distillate of $1.36 decreased by approximately 16.8% and 16.0%,
respectively, as compared to the year ended December 31, 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, 2016 compared to the year ended December 31, 2015:
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
(in millions)
Gasoline. . . . . . . . .
Distillate . . . . . . . .
42.6
32.4
$
$
56.16
$ 2,390.8
56.99
$ 1,844.3
40.1
33.1
$
$
67.52
$2,708.4
2.5
$ (317.6 ) $ (483.2 ) $
165.6
68.01
$2,248.2
(0.7 ) $ (403.9) $ (356.8) $
(47.1)
_______________________________________
(1)
(2)
Barrels in millions
Sales dollars in millions
Cost of Materials and Other. Petroleum cost of materials and other was $3,759.2 million for the year ended
December 31, 2016, compared to $4,143.6 million for the year ended December 31, 2015. The decrease of $384.4
million was primarily the result of a decrease in the cost of consumed crude and purchased products for resale. The
decrease in consumed crude oil cost was due to a decrease in crude oil 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, 2016 was $41.99 compared to $47.86 for the year ended December 31, 2015, a decrease of
approximately 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 2.3% during the same period.
The impact of FIFO accounting also impacted cost of materials 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, 2016 and 2015, the petroleum business had an favorable FIFO inventory impact of $52.1 million
compared to an unfavorable FIFO inventory impact of $60.3 million, respectively.
94
Refining margin per barrel of crude oil throughput decreased to $9.27 for the year ended December 31, 2016
from $14.45 for the year ended December 31, 2015. Refining margin adjusted for FIFO impact was $8.55 per crude
oil throughput barrel for the year ended December 31, 2016, as compared to $15.31 per crude oil throughput barrel
for the year ended December 31, 2015. Gross profit per barrel decreased to $2.10 for the year ended December 31,
2016, as compared to gross profit per barrel of $6.23 in the equivalent period in 2015. The decrease in refining
margin and gross profit per barrel was primarily due to the decline in product margins. The benchmark 2-1-1 crack
spread declined to $14.66 per barrel for the year ended December 31, 2016 from $20.41 per barrel for the year ended
December 31, 2015.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Petroleum direct operating
expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $393.4
million for the year ended December 31, 2016, compared to direct operating expenses and major scheduled
turnaround expenses of $478.5 million for the year ended December 31, 2015. The decrease of $85.1 million was
the 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 ($70.7 million), lower insurance expense ($4.5
million), environmental expense ($4.3 million), production chemicals ($3.1 million), repair and 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, 2016 decreased to $5.43 per barrel as compared to $6.79 per barrel for
the year ended December 31, 2015. The decrease in the direct operating expenses per barrel of crude oil throughput
was primarily a function of lower overall expenses.
Operating Income. Petroleum operating income was $77.8 million for the year ended December 31, 2016, as
compared to operating income of $361.7 million for the year ended December 31, 2015. The decrease of $283.9
million was the result of a decrease in the refining margin ($346.2 million) and the 2015 flood insurance recovery
($27.3 million), partially offset by decreases in direct operating expenses ($85.1 million), depreciation and
amortization ($1.2 million) and selling, general and administrative expenses ($3.3 million).
95
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, 2017, 2016 and 2015:
Nitrogen Fertilizer Business Financial Results
Net sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses:
Cost of materials and other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses(1). . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative . . . . . . . . . . . . . . . . . . . . . . . .
Operating income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Interest expense and other financing costs . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt. . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (loss), net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income tax expense. . . . . . . . . . . . . . . . .
Income tax expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
(in millions)
2015
330.8
$
356.3
$
289.2
84.9
152.9
2.6
74.0
314.4
25.6
(9.2)
(62.9)
—
(0.5)
(72.6)
0.2
(72.8) $
93.7
141.7
6.6
58.2
300.2
29.3
26.8
(48.6)
(4.9)
0.1
(26.6)
0.3
(26.9) $
65.2
99.1
7.0
28.4
199.7
20.8
68.7
(7.0)
—
0.3
62.0
—
62.0
Adjusted Nitrogen Fertilizer EBITDA(2) . . . . . . . . . . . . . . . . . . . $
65.8
$
92.7
$
106.8
96
Year Ended December 31,
2017
2016
2015
Key Operating Statistics
Sales (thousand tons):
Ammonia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
286.1
1,254.5
201.4
1,237.5
Product pricing at gate (dollars per ton)(3):
Ammonia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
280
152
$
$
376
177
$
$
Production volume (thousand tons):
Ammonia (gross produced)(4) . . . . . . . . . . . . . . . . . . . . . . . . . .
Ammonia (net available for sale)(4) . . . . . . . . . . . . . . . . . . . . . .
UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Feedstock:
Petroleum coke used in production (thousand tons) . . . . . . . . . .
Petroleum coke (dollars per ton) . . . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas used in production (thousands of MMBtu)(5) . . . . .
Natural gas used in production (dollars per MMBtu)(5)(6) . . . . $
Natural gas cost of materials and other (thousands of MMBtu)
(5) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Natural gas cost of materials and other (dollars per MMBtu)(5)
(6) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
Coffeyville Facility on-stream factors(7):
Gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Ammonia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
East Dubuque Facility on-stream factors (7):
Ammonia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
UAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
814.7
267.8
1,268.4
487.5
17
7,619.5
3.24
8,051.5
3.26
98.5%
97.4%
91.7%
90.4%
90.3%
Reconciliation to net sales (dollars in millions):
Sales net at gate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Freight in revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hydrogen revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
290.0
32.8
0.4
7.6
$
$
$
$
693.5
183.6
1,192.6
513.7
15
5,596.0
2.96
4,618.7
2.87
96.9%
94.9%
93.1%
87.7%
87.3%
309.0
33.0
3.2
11.1
$
$
$
$
Total net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
330.8
$
356.3
$
32.3
939.5
521
247
385.4
37.3
928.6
469.9
25
—
—
—
—
90.2%
87.5%
87.3%
—%
—%
248.8
27.2
11.8
1.4
289.2
Market Indicators
Ammonia — Southern Plains (dollars per ton) . . . . . . . . . . . . . . . $
Ammonia — Corn belt (dollars per ton) . . . . . . . . . . . . . . . . . . . . $
UAN — Corn belt (dollars per ton). . . . . . . . . . . . . . . . . . . . . . . . $
Natural gas NYMEX (dollars per MMBtu). . . . . . . . . . . . . . . . . . $
_______________________________________
(1)
97
Year Ended December 31,
2017
2016
2015
314
358
192
3.02
$
$
$
$
356
416
208
2.55
$
$
$
$
510
566
284
2.63
Amounts are shown exclusive of depreciation and amortization and major scheduled turnaround expenses.
(2)
Nitrogen Fertilizer EBITDA represents nitrogen fertilizer net income (loss) adjusted for (i) interest
(income) expense; (ii) income tax expense; and (iii) depreciation and amortization expense. Adjusted
Nitrogen Fertilizer EBITDA represents Nitrogen Fertilizer EBITDA further adjusted for (i) major
scheduled turnaround expenses, when applicable; (ii) share-based compensation, non-cash; (iii) gain or loss
on extinguishment of debt; (iv) expenses associated with the East 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, loss on disposition of assets, expenses associated with the East Dubuque Merger
and business interruption insurance recovery, relating to transactions not reflective of the Nitrogen
Fertilizer Partnership's core operations.
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, 2017, 2016 and 2015:
Nitrogen Fertilizer:
Nitrogen Fertilizer net income (loss). . . . . . . . . . . . . . . . . . . . . . . $
Add:
Interest expense and other financing costs, net . . . . . . . . . . . .
Income tax expense. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Nitrogen Fertilizer EBITDA . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Add:
Major scheduled turnaround expenses . . . . . . . . . . . . . . . . . . .
Share-based compensation, non-cash . . . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . .
Expenses associated with the East Dubuque Merger. . . . . . . .
Less:
Insurance recovery - business interruption . . . . . . . . . . . . . . . . . .
Adjusted Nitrogen Fertilizer EBITDA . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
(in millions)
2015
(72.8) $
(26.9) $
62.9
0.2
74.0
64.3
2.6
—
—
—
48.6
0.3
58.2
80.2
6.6
—
4.9
3.1
62.0
7.0
—
28.4
97.4
7.0
0.1
—
2.3
(1.1)
65.8
$
(2.1)
92.7
$
—
106.8
(3)
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.
98
(4)
(5)
(6)
(7)
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.
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).
The cost per MMBtu excludes derivative activity, when applicable. The impact of natural gas derivative
activity was not material for the periods presented.
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.
Coffeyville Facility
The Linde air separation unit experienced a shut down during the second quarter of 2017. 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, 2017 compared to the Year Ended December 31, 2016 (Nitrogen Fertilizer Business)
Net Sales. Nitrogen fertilizer net sales were $330.8 million for the year ended December 31, 2017, compared to
$356.3 million for the year ended December 31, 2016.
Excluding the East Dubuque Facility, net sales were $195.8 million for the year ended December 31, 2017
compared to $228.3 million for the year ended December 31, 2016. The decrease of $32.5 million was primarily
attributable to the lower UAN sales prices ($24.0 million), lower UAN sales volumes ($7.2 million) and lower
ammonia sales prices ($4.5 million), partially offset by higher ammonia sales volumes ($6.5 million) at the
Coffeyville Facility. For the year ended December 31, 2017, UAN and ammonia made up $170.5 million and $18.4
million of the nitrogen fertilizer business' net sales, respectively, including freight. This compared to UAN and
ammonia net sales of $201.7 million and $16.4 million, respectively, for the year ended December 31, 2016,
including freight.
99
The following table demonstrates the impact of changes in sales volumes and pricing for the primary
components of net sales at the Coffeyville Fertilizer Facility for the year ended December 31, 2017 compared to the
year ended December 31, 2016:
Price
Variance
Volume
Variance
(in millions)
UAN. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(24.0) $
Ammonia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(4.5) $
(0.2) $
(7.2)
6.5
(2.6)
The decrease in UAN and ammonia sales prices at the Coffeyville Fertilizer Facility for the year ended
December 31, 2017 compared to the year ended December 31, 2016 was primarily attributable to pricing fluctuation
in the market.
Cost of Materials and Other. Nitrogen fertilizer cost of materials and other includes cost of freight and
distribution expenses, feedstock, purchased ammonia and purchased hydrogen. Cost of materials and other for the
year ended December 31, 2017 was $84.9 million, compared to $93.7 million for the year ended December 31,
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 decrease 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
decreased distribution costs due to the timing of regulatory railcar repairs and maintenance ($3.5 million) and a
reduction of expenses 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 subsidiary of the 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 for the year ended December 31, 2017 were $155.5 million, as compared to $148.3 million for the year
ended December 31, 2016. The total increase of $7.2 million for the year ended December 31, 2017, as compared to
the year ended December 31, 2016.
Excluding the East Dubuque Facility, direct operating expenses were $94.4 million for the year ended
December 31, 2017 compared to $92.6 million for the year ended December 31, 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 $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,
2017, as compared to operating income of $26.8 million for the year ended December 31, 2016. The decrease of
$36.0 million was the result of decrease net sales ($25.5 million), increases in direct operating expenses ($11.2
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 ($3.7
million).
100
Year Ended December 31, 2016 compared to the Year Ended December 31, 2015
Net Sales. Nitrogen fertilizer net sales were $356.3 million for the year ended December 31, 2016, compared to
$289.2 million for the year ended December 31, 2015. The net sales increase of $67.1 million is primarily
attributable to increased sales volume due to the inclusion of the nine months of the East Dubuque Facility ($128.0
million). For the year ended December 31, 2016, UAN and ammonia made up $249.1 million and $78.0 million of
the nitrogen fertilizer business' net sales, respectively. This compared to UAN and ammonia net sales of $258.8
million and $17.2 million, respectively, for the year ended December 31, 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 at the
Coffeyville Fertilizer Facility for the year ended December 31, 2016 compared to the year ended December 31,
2015:
Price
Variance
Volume
Variance
(in millions)
UAN. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(69.8) $
Ammonia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Hydrogen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
(7.6) $
(1.8) $
16.8
6.8
(6.8)
The decrease in UAN and ammonia sales prices at the Coffeyville Fertilizer Facility for the year ended
December 31, 2016 compared to the year ended December 31, 2015 was primarily attributable to pricing fluctuation
in the market. The increase of UAN and ammonia sales volume at the Coffeyville Fertilizer Facility for the year
ended December 31, 2016 compared to the year ended December 31, 2015 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 hydrogen sales volume at the Coffeyville
Fertilizer Facility for the year ended December 31, 2016 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 $93.7
million, compared to $65.2 million for the year ended December 31, 2015. The $28.5 million increase was
attributable to the inclusion of the nine months of the East Dubuque Facility ($36.7 million), which is partially offset
by cost decreases at the Coffeyville Fertilizer Facility.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Nitrogen fertilizer direct operating
expenses (exclusive of depreciation and amortization) for the year ended December 31, 2016 were $148.3 million,
as compared to $106.1 million for the year ended December 31, 2015. The total increase of $42.2 million for the
year ended December 31, 2016, as compared to the year ended December 31, 2015, was primarily attributable to the
inclusion of the nine months of the East Dubuque Facility ($55.7 million).
Operating Income. Nitrogen fertilizer operating income was $26.8 million for the year ended December 31,
2016, as compared to operating income of $68.7 million for the year ended December 31, 2015. The decrease of
$41.9 million was the result of the increases in direct operating expenses ($42.2 million), depreciation and
amortization ($29.8 million), cost of materials and other ($28.5 million) and selling, general and administrative
expenses ($8.5 million), partially offset by increases in net sales ($67.1 million).
101
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 12 months, and that we have sufficient cash resources to fund our operations for at least the next 12
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 beyond
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, 2017, we had consolidated cash and cash equivalents of $481.8 million. Of that amount,
$258.8 million was cash and cash equivalents of CVR Energy, $173.8 million was cash and cash equivalents of the
Refining Partnership and $49.2 million was cash and cash equivalents of the Nitrogen Fertilizer Partnership. As of
February 20, 2018, we had consolidated cash and cash equivalents of approximately $499.7 million.
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
distributions are made to all common unitholders. As of December 31, 2017, we held approximately 66% and 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.
102
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
2019 . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . .
2021 and thereafter . . . . . .
Percentage
104.625%
102.313%
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. The Refining Partnership's $500.0 million aggregate principal amount of 6.5% Second Lien Senior
Notes due 2022 are unsecured and 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.
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, 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 prices (expressed as percentages of
principal amount) set forth below, plus any accrued and unpaid interest to the applicable redemption date on such
2022 Notes, if redeemed during the 12-month period beginning on November 1 of the years indicated below:
Year
2017 . . . . . . . . . . . . . . . . .
2018 . . . . . . . . . . . . . . . . .
2019 . . . . . . . . . . . . . . . . .
2020 and thereafter . . . . . .
Percentage
103.250%
102.167%
101.083%
100.000%
Prior to November 1, 2017, some or all of the 2022 Notes were 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.
103
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 member interest of Refining LLC.
See Part II, Item 8, Note 11 ("Long-Term Debt") of this Report for additional information on the 2022 Notes,
including a description of the covenants contained therein. The Refining Partnership was in compliance with the
covenants as of December 31, 2017.
Amended and Restated Asset Based (ABL) Credit Facility. On November 14, 2017, CRLLC, CVR Refining,
Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into
Amendment No. 1 to the Amended and Restated ABL Credit 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 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 swingline loans of $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. Availability under the Amended and Restated 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 Amended and
Restated ABL Credit Facility, including a description of the covenants contained therein. The Refining Partnership
was in compliance with the covenants as of December 31, 2017.
Asset Based (ABL) Credit Facility. The Nitrogen Fertilizer Partnership has an ABL Credit Facility, the proceeds
of which may be used to fund working capital and other general corporate purposes. The ABL Credit Facility is a
senior secured asset-based revolving credit facility with 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 ABL Credit Facility matures in
September 2021.
As of February 20, 2018, the Nitrogen Fertilizer Partnership and its 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 covenants contained therein. The Nitrogen Fertilizer Partnership was in
compliance with the covenants as of December 31, 2017.
104
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 2017 and current estimated capital
expenditures in 2018 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,
2017 Actual
2018 Estimate
Petroleum Business (the Refining Partnership):
Coffeyville refinery:
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coffeyville refinery total capital spending . . . . . . . . . . . . . . . . . . . . . . . . .
Wynnewood refinery:
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Wynnewood refinery total capital spending . . . . . . . . . . . . . . . . . . . . . . . .
Other Petroleum:
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other petroleum total capital spending . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Petroleum business total capital spending . . . . . . . . . . . . . . . . . . . . . . .
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Growth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nitrogen fertilizer business total capital spending . . . . . . . . . . . . . . . . .
Corporate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(in millions)
(unaudited)
36.9
$
3.0
39.9
38.1
4.0
42.1
2.7
15.0
17.7
99.7
14.1
0.4
14.5
4.4
Total capital spending. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
118.6
$
75.0
10.0
85.0
65.0
25.0
90.0
15.0
10.0
25.0
200.0
18.0
3.0
21.0
10.0
231.0
The petroleum business' and the nitrogen fertilizer business' estimated capital expenditures are subject to change
due to unanticipated changes in the cost, scope and completion time for capital projects. For example, they may
experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to
complete projects that sustain or improve the profitability of the refineries or nitrogen fertilizer 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.
105
On December 1, 2017, CVR Refining acquired the Cushing to Ellis crude oil pipeline system from Plains All
American Pipeline, L.P. ("Plains") for $15.0 million, which amount is included in other petroleum growth capital
spending in the table above. The approximately 100-mile, 8- and 10-inch pipeline system links CVR Refining’s
Wynnewood, Oklahoma, refinery to Cushing.
The following table sets forth our consolidated cash flows for the periods indicated below:
Cash Flows
Year Ended December 31,
2017
2016
(in millions)
2015
Net cash provided by (used in):. . . . . . . . . . . . . . . . . . . . . . . . . . .
Operating activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Investing activities (1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . $
$
166.9
(195.0)
(225.9)
(254.0) $
$
267.5
(201.4)
(95.4)
(29.3) $
536.8
(150.6)
(374.8)
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
106
($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.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended December 31, 2017 was $195.0 million compared to
$201.4 million for the year ended December 31, 2016. The decrease of $6.4 million of cash used in investing
activities was primarily due to the net cash paid by the nitrogen fertilizer business in 2016 for the acquisition of
CVR Nitrogen ($63.8 million) and lower 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
petroleum business' investment in the Midway joint venture.
Net cash used in investing activities for the year ended December 31, 2016 was $201.4 million compared to
$150.6 million for the year ended December 31, 2015. The increase of $50.8 million of cash used in investing
activities was primarily due to the net cash paid for the acquisition of CVR Nitrogen ($63.8 million), security
purchases ($18.6 million), investment in VPP ($5.6 million) and a decrease in proceeds from available-for-sale
securities ($48.7 million), partially offset by a decrease in capital expenditures 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
107
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.
As of and for the year ended December 31, 2017, there were no borrowings or repayments under the Amended
and Restated ABL Credit Facility or the 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, 2017 relating to contractual obligations and
other commercial commitments for the five-year period following December 31, 2017 and thereafter.
Total
2018
2019
2020
2021
2022
Thereafter
Payments Due by Period
(in millions)
Contractual Obligations
Long-term debt(1). . . . . . . . . $ 1,147.2
Operating leases(2) . . . . . . . .
32.3
Capital lease obligations(3) .
Unconditional purchase
obligations(4) . . . . . . . . . . . .
Environmental liabilities(5) .
Interest payments(6) . . . . . . .
518.3
Total . . . . . . . . . . . . . . . . . $ 2,853.9
1,107.1
45.0
4.0
$
— $
— $
— $
7.4
2.1
165.0
2.9
96.9
6.5
2.3
124.3
1.1
96.7
5.9
2.6
100.6
—
96.4
2.2
5.3
2.9
89.8
—
96.1
$
500.0
$
645.0
4.8
3.1
84.7
—
90.2
2.4
32.0
542.7
—
42.0
$
274.3
$
230.9
$
205.5
$
196.3
$
682.8
$ 1,264.1
Other Commercial
Commitments
Standby letters of credit(7) . . $
28.4
$
— $
— $
— $
— $
— $
—
_______________________________________
(1)
(2)
(3)
Consists of the 2021 Notes, the 2022 Notes and the 2023 Notes as of December 31, 2017.
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.
The amount includes commitments under capital lease arrangements for two leases associated with
pipelines and storage and terminal equipment at the Wynnewood refinery.
108
(4)
(5)
(6)
(7)
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
electricity 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 2018, (e) commitments related
to our biofuels blending obligation, (f) various agreements associated with our East Dubuque Facility in
Illinois for gas and gas transportation and (g) approximately $698.6 million payable ratably over 13 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, 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 20 years on
TransCanada's Keystone pipeline system.
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 Item 1."Business — Environmental Matters."
Interest payments are based on stated interest rates for our long-term debt outstanding and interest
payments for the capital lease obligation as of December 31, 2017 and also includes commitment fees on
the unutilized commitments of the ABL Credit Facility.
Standby letters of credit issued against our Amended and Restated ABL Credit Facility include $0.3 million
of letters of credit issued in connection with environmental liabilities, $26.5 million in letters of credit to
secure transportation services for crude oil and a $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 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 the 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.
109
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 listed below, could materially affect the amounts recorded in our
consolidated financial statements.
•
•
•
•
•
•
Estimated lives used in computing depreciation for property, plant and equipment
Goodwill impairment
Income taxes
Impairment of long-lived assets
Derivative instruments and fair value of financial instruments
Share-based compensation
Refer to Note 2 ("Summary of Significant Accounting Policies") to Part II, Item 8 of this Report for a discussion
of these accounting policies.
110
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 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 has 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
business. The nitrogen fertilizer business has not historically hedged for commodity prices.
Basis Risk.
The effectiveness of the 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.
The selection of the appropriate index to utilize in a hedging strategy is a prime consideration in the 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, the 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 its' Group 3 pricing area.
111
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 the 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, 2017, the Refining Partnership had no open commodity positions. At December 31, 2017,
the Refining Partnership's account balance maintained at the third-party clearing house totaled approximately $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, 2017 resulted in loss on derivatives, net of approximately $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, 2017, the Refining Partnership had open commodity swap instruments consisting of 7.1 million
barrels of 2-1-1crack spreads, 3.6 million barrels of distillate crack spreads and 3.6 million barrels of 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 benchmark would result in an increase or decrease in the related fair values of commodity instruments of
$17.7 million. The fair value of the outstanding contracts at December 31, 2017 was a net unrealized loss of $64.3
million, comprised of short-term unrealized losses.
Interest Rate Risk
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 $1.3 million on an annualized basis, thus decreasing net income by the same
amount.
112
Compliance Program Price Risk
As a producer of transportation fuels from petroleum, the Refining Partnership is required 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 RFS. 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 14 ("Commitments
and Contingencies") to Part II, Item 8 of this 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' pipeline transportation costs are transacted 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 billing and settlement of these transportation costs in Canadian
dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not material.
113
Item 8. Financial Statements and Supplementary Data
CVR Energy, Inc. and Subsidiaries
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements:
Report of Independent Registered Public Accounting Firm — Consolidated Financial Statements . . . . . .
Report of Independent Registered Public Accounting Firm — Internal Control Over Financial Reporting
Consolidated Balance Sheets at December 31, 2017 and 2016. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015. . . . . . . .
Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and
2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Statements of Changes in Equity for the years ended December 31, 2017, 2016 and 2015. .
Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Page
Number
115
116
117
118
119
120
121
123
114
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, 2017 and 2016, 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, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the
financial statements present fairly, in all material respects, the financial position of the Company as of December 31,
2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2017, 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, 2017, based on
criteria established in the 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission ("COSO"), and our report dated February 26, 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
We have served as the Company's auditor since 2013.
Kansas City, Missouri
February 26, 2018
115
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, 2017, based on criteria established in the 2013 Internal Control —
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
("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 on Internal Control Over Financial Reporting. 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 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.
/s/ GRANT THORNTON LLP
Kansas City, Missouri
February 26, 2018
116
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
December 31,
2017
2016
(in millions, except share data)
Current assets:
ASSETS
Cash and cash equivalents (including $223.0 and $369.7, respectively, of consolidated variable
interest entities ("VIEs")) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
481.8
$
Accounts receivable of VIEs, net of allowance for doubtful accounts of $1.1 and $0.5, respectively .
Inventories of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets (including $30.0 and $65.0, respectively, of VIEs) . . . . . . .
Income tax receivable (including $0.0 and $0.2, respectively, of VIEs) . . . . . . . . . . . . . . . . . . . . . . . .
Due from parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
178.7
385.2
33.7
9.7
5.1
735.8
151.9
349.2
68.4
10.2
—
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1,094.2
1,315.5
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Goodwill of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equity method investments in affiliates of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term assets (including $13.3 and $19.1, respectively, of VIEs) . . . . . . . . . . . . . . . . . . . . . .
0.2
41.0
82.8
16.7
0.2
41.0
5.6
15.8
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,806.7
$
4,050.2
Current liabilities:
LIABILITIES AND EQUITY
Note payable and capital lease obligations of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2.1
$
Accounts payable (including $329.0 and $247.7, respectively, of VIEs). . . . . . . . . . . . . . . . . . . . . . . .
Personnel accruals (including $29.9 and $23.6, respectively, of VIEs) . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued taxes other than income taxes of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue of VIEs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Due to parent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities (including $111.8 and $216.8, respectively, of VIEs) . . . . . . . . . . . . . . . . . . .
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term liabilities:
Long-term debt and capital lease obligations of VIEs, net of current portion . . . . . . . . . . . . . . . . . . . .
Deferred income taxes (including $1.0 and $0.8, respectively, of VIEs) . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities (including $3.7 and $5.4, respectively, of VIEs) . . . . . . . . . . . . . . . . . . . . .
Total long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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 .
Additional paid-in-capital . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Retained deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Treasury stock, 98,610 shares at cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accumulated other comprehensive loss, net of tax . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total CVR stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total equity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
333.9
55.9
26.5
12.9
—
112.4
543.7
1,164.4
385.9
8.7
1,559.0
0.9
1,197.6
(277.4)
(2.3)
—
918.8
785.2
1,704.0
Total liabilities and equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,806.7
$
See accompanying notes to consolidated financial statements.
117
1.8
251.0
45.7
27.0
12.6
10.6
217.2
565.9
1,162.8
579.9
32.0
1,774.7
0.9
1,197.6
(338.1)
(2.3)
—
858.1
851.5
1,709.6
4,050.2
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
Net sales. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses:
Cost of materials and other . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Direct operating expenses (exclusive of depreciation and
amortization as reflected below). . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Flood insurance recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative expenses (exclusive of
depreciation and amortization as reflected below) . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . .
Total operating costs and expenses . . . . . . . . . . . . . . . . . . .
Operating income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other income (expense):
Interest expense and other financing costs . . . . . . . . . . . . . . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt . . . . . . . . . . . . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total other expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . . . . . . . . . . . . . . . . .
Income tax expense (benefit). . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Net income (loss) attributable to noncontrolling interest
Net income attributable to CVR Energy stockholders . . . . . . . $
Basic and diluted earnings per share . . . . . . . . . . . . . . . . . . . . $
Dividends declared per share . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
2015
(in millions, except per share data)
5,988.4
$
4,782.4
$
5,432.5
4,882.9
3,847.5
4,190.4
599.5
203.3
5,685.7
—
114.2
10.7
5,810.6
177.8
(110.1)
1.1
(69.8)
—
1.0
(177.8)
0.0
(216.9)
216.9
(17.5)
234.4
2.70
2.00
$
$
$
541.8
184.5
4,573.8
—
109.1
8.6
4,691.5
90.9
(83.9)
0.7
(19.4)
(4.9)
5.7
(101.8)
(10.9)
(19.8)
8.9
(15.8)
24.7
0.28
2.00
$
$
$
584.7
156.4
4,931.5
(27.3)
99.0
7.7
5,010.9
421.6
(48.4)
1.0
(28.6)
—
36.7
(39.3)
382.3
84.5
297.8
128.2
169.6
1.95
2.00
Weighted-average common shares outstanding:
Basic and Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86.8
86.8
86.8
See accompanying notes to consolidated financial statements.
118
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other comprehensive income (loss):
Unrealized gain on available-for-sale securities, net of tax of $0.0, $0.2
and $12.6, respectively. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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) .
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) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Change in fair value of interest rate swaps, net of tax of $0.0, $0.0 and
$0.0, respectively . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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) . . . . . . . . . . . .
Total other comprehensive income. . . . . . . . . . . . . . . . . . . . . . . .
Comprehensive income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Comprehensive income (loss) attributable to noncontrolling
interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
2016
2015
(in millions)
8.9
$
216.9
$
297.8
—
—
—
—
—
—
216.9
0.3
19.2
(0.3)
(12.1)
—
—
—
—
8.9
(7.1)
(0.1)
0.8
0.7
298.5
(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.
119
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Common Stockholders
$0.01 Par
Value
Common
Stock
Shares
Issued
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)
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
Dividends paid to CVR Energy
stockholders . . . . . . . . . . . . . . . . . . . .
Distributions from CVR Partners to
public unitholders . . . . . . . . . . . . . . . .
Distributions from CVR Refining to
public unitholders . . . . . . . . . . . . . . . .
Share-based compensation . . . . . . . . .
Excess tax deficiency from share-
based compensation . . . . . . . . . . . . . .
Net income . . . . . . . . . . . . . . . . . . . . .
Other comprehensive income, net of
tax . . . . . . . . . . . . . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
Balance at December 31, 2015 . . . . . . .
86,929,660
Dividends paid to CVR Energy
stockholders . . . . . . . . . . . . . . . . . . . .
Distributions from CVR Partners to
public unitholders . . . . . . . . . . . . . . . .
Impact of CVR Partners' common
units issuance for the East
Dubuque Merger, net of tax of
$20.0 . . . . . . . . . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . .
—
—
—
—
Balance at December 31, 2016 . . . . . . .
86,929,660
Dividends paid to CVR Energy
stockholders . . . . . . . . . . . . . . . . . . . .
Distributions from CVR Partners to
public unitholders . . . . . . . . . . . . . . . .
Distributions from CVR Refining to
public unitholders . . . . . . . . . . . . . . . .
Net income (loss) . . . . . . . . . . . . . . . .
—
—
—
—
—
—
—
—
—
—
—
0.9
—
—
—
—
0.9
—
—
—
—
—
—
—
0.1
(0.1)
—
—
(173.7)
—
—
(0.2)
—
169.6
—
—
—
—
—
—
—
—
1,174.7
(189.2)
(2.3)
—
—
22.9
—
(173.6)
—
—
24.7
—
—
—
—
1,197.6
(338.1)
(2.3)
—
—
—
—
(173.7)
—
—
234.4
—
—
—
—
—
—
—
—
—
—
0.3
—
—
—
—
—
—
—
—
—
—
(173.7)
—
(173.7)
—
—
(0.1)
(0.1)
169.6
0.3
984.1
(42.8)
(42.8)
(156.9)
(156.9)
0.3
—
128.2
0.2
(0.1)
297.8
0.4
0.7
616.4
1,600.5
(173.6)
—
(173.6)
—
(41.9)
(41.9)
22.9
24.7
858.1
292.8
(15.8)
315.7
8.9
851.5
1,709.6
(173.7)
—
(173.7)
—
—
234.4
(1.5)
(1.5)
(47.3)
(17.5)
(47.3)
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.
120
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2017
2016
(in millions)
2015
Cash flows from operating activities:
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
216.9
$
8.9
$
297.8
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Allowance for doubtful accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of deferred financing costs and original issue discount . . . . . . .
Amortization of debt fair value adjustment. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Excess income tax deficiency of share-based compensation . . . . . . . . . . . . . .
Loss on disposition of assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on extinguishment of debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Share-based compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gain on sale of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unrealized gain on securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current period settlements on derivative contracts . . . . . . . . . . . . . . . . . . . . . .
Income from equity method investments, net of distributions . . . . . . . . . . . . .
Changes in assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets. . . . . . . . . . . . . . . . . . . . . . . . . .
Due to (from) parent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net cash provided by operating activities . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from investing activities:
214.0
0.6
4.8
—
(216.5)
—
2.4
—
18.8
—
—
69.8
(16.6)
(0.7)
(27.3)
(37.6)
33.9
(15.7)
1.0
88.1
0.6
0.9
(168.0)
(2.5)
166.9
193.1
0.2
3.6
1.2
(84.4)
—
0.5
4.9
9.3
(4.9)
(0.3)
19.4
36.4
—
(47.5)
(7.3)
(3.4)
22.2
(0.6)
(10.4)
(3.3)
(20.4)
151.2
(0.9)
267.5
164.1
(0.1)
2.8
—
(10.4)
0.1
1.8
—
12.8
(20.1)
—
28.6
(26.0)
—
41.0
39.7
40.4
32.8
3.8
(14.3)
4.2
(10.5)
(52.1)
0.4
536.8
Capital expenditures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(118.6)
(132.7)
(218.7)
Proceeds from sale of assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Acquisition of CVR Nitrogen, net of cash acquired . . . . . . . . . . . . . . . . . . . . . .
Purchase of securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in affiliates, net of return of investment. . . . . . . . . . . . . . . . . . . . . . .
Purchase of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Proceeds from sale of available-for-sale securities . . . . . . . . . . . . . . . . . . . . . . .
Net cash used in investing activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Cash flows from financing activities:
Proceeds on issuance of 2023 Notes, net of original issue discount . . . . . . . . .
Principal and premium payments on 2021 Notes . . . . . . . . . . . . . . . . . . . . . . .
Payments of revolving debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0.1
—
—
(76.5)
—
—
(195.0)
—
—
—
—
(63.8)
(4.2)
(5.6)
(14.4)
19.3
(201.4)
628.8
(322.2)
(49.1)
0.1
—
—
—
—
68.0
(150.6)
—
—
—
121
Year Ended December 31,
2017
2016
(in millions)
2015
(125.0)
(1.7)
(10.7)
(173.6)
— $
(41.9) $
—
(95.4)
(29.3)
765.1
735.8
45.5
76.8
15.8
6.0
$
$
$
$
$
— $
335.7
367.5
16.1
$
$
$
—
(1.3)
—
(173.7)
(156.9)
(42.8)
(0.1)
(374.8)
11.4
753.7
765.1
57.9
45.4
22.3
0.7
—
—
—
—
Principal payments on CRNF credit facility . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Payment of deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Dividends to CVR Energy's stockholders . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Distributions to CVR Refining's noncontrolling interest holders . . . . . . . . . . . $
Distributions to CVR Partners' noncontrolling interest holders . . . . . . . . . . . . $
Excess income tax deficiency of share-based compensation . . . . . . . . . . . . . .
Net cash used in financing activities . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net increase (decrease) in cash and cash equivalents . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, beginning of period . . . . . . . . . . . . . . . . . . . . . . . .
Cash and cash equivalents, end of period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Supplemental disclosures:
Cash paid for income taxes, net of refunds . . . . . . . . . . . . . . . . . . . . . . . . . . $
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 . . . . . . . . $
Non-cash investing and financing activities:
—
(1.8)
(1.6)
(173.7)
(47.3) $
(1.5) $
—
(225.9)
(254.0)
735.8
481.8
14.9
105.0
$
$
$
$
Construction in progress additions included in accounts payable . . . . . . $
8.2
Change in accounts payable related to construction in progress
additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Landlord incentives for leasehold improvements . . . . . . . . . . . . . . . . . . $
Fair value of common units issued in a business combination . . . . . . . . $
Fair value of debt assumed in a business combination . . . . . . . . . . . . . . $
Reduction of proceeds from 2023 Notes from underwriting discount . . . $
(5.2) $
1.2
$
— $
— $
— $
See accompanying notes to consolidated financial statements.
122
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Nature of Business
Organization
The "Company," "CVR Energy," or "CVR" may be used to refer to CVR Energy, Inc. and, unless the context
otherwise requires, 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. CVR's common stock is listed on the
New York Stock Exchange ("NYSE") under the symbol "CVI."
As of December 31, 2017, Icahn Enterprises L.P. ("IEP") and its affiliates owned approximately 82% of the
Company's outstanding shares.
CVR Partners, LP
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."
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the merger (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 acquired a nitrogen fertilizer manufacturing facility located in East Dubuque, Illinois (the
"East Dubuque Facility"). See Note 3 ("Acquisition").
As a result of the Nitrogen Fertilizer Partnership's acquisition of CVR Nitrogen, LP and issuance of the unit
consideration, the noncontrolling interest related to the Nitrogen Fertilizer Partnership reflected in our Consolidated
Financial Statements on April 1, 2016 and from such date and as of December 31, 2017 was approximately 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.
CVR Refining, LP
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. The common units, which are listed on the NYSE,
began trading on January 17, 2013 under the symbol "CVRR."
As of December 31, 2017, public security holders held approximately 34% of the total Refining Partnership
common units (including units owned by affiliates of IEP representing 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
123
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
(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 Financial 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 and 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 and the Nitrogen 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 power 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 receive benefits from the entity that could potentially be significant to the VIE. The standard requires an
ongoing analysis to determine whether the variable interest gives rise to a controlling financial interest in the VIE.
Based upon the general partner’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 partner 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 Refining 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 America ("GAAP"), using management's best estimates and judgments where
appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ materially from these estimates and judgments.
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 within 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 flows for accounts payable as they do not represent bank overdrafts. The amount of these checks included in
accounts payable as of December 31, 2017 and 2016 was $22.8 million and $18.1 million, respectively.
124
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 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, 2017, 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, 2017 and 2016 was approximately 11% and 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 net 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 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
Improvements to land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Buildings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Machinery and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Automotive equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Furniture and fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aircraft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Railcars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Range of Useful
Lives, in Years
15 to 30
20 to 30
5 to 30
5 to 15
3 to 10
20
25 to 30
125
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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 2017, 2016 and 2015, which is attributable
entirely to the nitrogen fertilizer segment and concluded there were no impairments. See Note 8 ("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 line-of-credit arrangements are
amortized to interest expense and other financing costs using the straight-line method through the termination date
of the 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, 2017, 2016 and 2015, the Company's petroleum and nitrogen fertilizer
segments incurred the following major scheduled turnaround expenses.
Petroleum segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Coffeyville refinery(1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Wynnewood refinery(2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nitrogen Fertilizer segment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nitrogen Fertilizer plants(3). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Major Scheduled Turnaround Expenses . . . . . . . . . . . . . . . . . $
_______________________________________
For the Year Ended December 31,
2017
2016
2015
(in millions)
— $
31.5
$
102.2
80.4
2.6
—
6.6
—
7.0
83.0
$
38.1
$
109.2
(1) The Coffeyville refinery completed the first phase of its most recent major scheduled turnaround in November
2015. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016.
126
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(2) The Wynnewood refinery completed the first phase of its most recent major scheduled turnaround in November
2017. The second phase of the Wynnewood turnaround is expected to occur in 2019. In addition to the two
phase turnaround, the petroleum business accelerated certain planned turnaround activities in 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 turnaround expenses for the hydrocracker.
(3) The Nitrogen Fertilizer Partnership underwent a full facility turnaround at the Coffeyville fertilizer facility in
the third quarter of 2015. During the second quarter of 2016 and the third quarter of 2017, the East Dubuque
Facility completed major scheduled turnarounds.
Cost Classifications
Cost of materials and other includes cost of crude oil, other feedstocks, blendstocks, purchased refined products,
pet coke expenses, renewable identification numbers ("RINs") expenses and freight and distribution costs.
Direct operating expenses (exclusive of depreciation and amortization) consist primarily of energy and other
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.
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.
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.
Impairment of Long-Lived Assets
CVR accounts for long-lived assets in accordance with accounting standards issued by the 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 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.
127
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Non-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 Statements of
Operations.
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 materials and 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 ASC Topic 815, Derivatives and Hedging, 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. See Note 17 ("Derivative Financial
Instruments") for further discussion.
The nitrogen fertilizer business enters into forward contracts with fixed delivery prices to purchase portions of
its natural gas requirements. The nitrogen fertilizer partnership elected to apply the normal purchase and normal sale
exclusion to natural gas contracts that are entered into to be used in production within a reasonable time during the
normal course of business. Accordingly, the fair value of these contracts is not recorded on the Consolidated Balance
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 11
("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 4 ("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.
128
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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 22 ("Subsequent Events") for further
discussion.
Recent Accounting Pronouncements
In May 2014, the FASB issued 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 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. In 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 and cash flows arising from contracts with customers. The standard is effective for interim and annual
periods beginning after December 15, 2017. The Company adopted this standard, effective January 1, 2018, using
the modified retrospective application method, whereby the cumulative effect of 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. The 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 legally enforceable and the
associated right to consideration is unconditional.
In February 2016, the FASB issued ASU No. 2016-02, “Leases” (“ASU 2016-02”) creating a new 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
129
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 Company'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 FASB 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, with early adoption permitted. The Company adopted this standard as of
January 1, 2017.
In January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other (Topic 350) -
Simplifying the Test for Goodwill Impairment" (“ASU 2017-04”). The new standard simplifies the accounting 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 goodwill allocated to that reporting unit. The standard is effective for interim
and annual periods beginning after December 15, 2019, with early adoption permitted. The Company adopted this
standard as of January 1, 2017.
(3) Acquisition
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the East Dubuque Merger as contemplated by
the Agreement and Plan of Merger, 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 not 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 CVR Partners-affiliated entity upon closing of the 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
130
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Nitrogen GP, upon closing of the East Dubuque Merger, vested in full and the holders thereof received the merger
consideration.
In accordance with the FASB’s ASC Topic 805 — Business Combinations ("ASC 805"), 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 the 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 $367.5 million fair value of assumed debt. The East Dubuque Facility contributed net sales of $127.9
million and an operating loss of $1.2 million to the Consolidated Statement of Operations for the year ended
December 31, 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.
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.
131
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Purchase Price
Allocation
(in millions)
Cash . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses and other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other long-term liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total fair value of net assets acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total consideration transferred, net of cash acquired . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
35.4
8.9
49.1
5.2
775.3
1.1
(29.8)
(37.0)
(367.5)
(1.2)
439.5
35.4
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:
Fair value of CVR Partners common units issued, as of the close of the East Dubuque Merger. $
Less: Change in CVR Energy's noncontrolling interest in CVR Partner's equity due to the East
Dubuque Merger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment to additional paid-in capital, as of the close of the East Dubuque Merger . . . . . . . . $
335.7
292.8
42.9
Non-controlling
interest
(in millions)
132
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(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,
2017, only performance units under the 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, 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, 2017, 2016 and
2015 is presented below:
Non-vested at December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . .
Restricted
Shares
Weighted-
Average
Grant-Date
Fair Value
Aggregate
Intrinsic
Value
(in millions)
48,011
$
45.89
$
1.9
—
(43,085)
(4,327)
599
—
(599)
—
—
45.55
47.68
$
57.23
$
—
—
57.23
—
— $
— $
—
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 were generally graded-vesting awards,
which vested over a three-year period. Compensation expense was recognized on a straight-line basis over the
vesting period of the respective tranche of the award. The change of control of CVR Energy in 2012 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 contingent 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.
133
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In December 2012 and during 2013, restricted stock units and dividend equivalent rights were granted to certain
employees of CVR. The awards vested 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 represented 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 were liability-classified, were remeasured each subsequent reporting date until they vested.
As of December 31, 2017, no restricted stock units were outstanding. Total compensation expense for the years
ended December 31, 2017 and 2016 related to the restricted stock unit awards was nominal. Total compensation
expense for the year ended December 31, 2015 was approximately $0.8 million related to the restricted stock unit
awards.
As of December 31, 2017, the Company had no liability for non-vested restricted stock unit awards and
associated dividend equivalent rights. The liability as of December 31, 2016 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, 2016 and 2015, the Company paid cash of a nominal amount
and $2.5 million, respectively, to settle liability-classified restricted stock unit awards and dividend equivalent rights
upon vesting.
Performance Unit Awards
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 of $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.
134
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 $10.0 million if the average closing price of CVR Energy's common stock over the 30-trading
day period from January 4, 2022 to February 15, 2022 is equal to or greater than $60 per share. At December 31,
2017, there was approximately $10.0 million of total unrecognized compensation cost related to the 2017
Performance Unit Award Agreement to be recognized over a period of 4 years.
Long-Term Incentive Plan — CVR Partners
Common Units and Phantom Units
Individuals who are eligible to receive awards under the CVR Partners, LP Long-Term Incentive Plan ("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 Partners' LTIP is 5,000,000. As of
December 31, 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 2015,
2016 and 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.
135
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, 2017, 2016 and 2015 is presented below:
Non-vested at December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . .
Weighted-
Average
Grant-Date
Fair Value
Units
Aggregate
Intrinsic
Value
(in millions)
243,946
$
11.07
$
2.4
245,199
(94,854)
(2,388)
391,903
680,718
(292,536)
(8,299)
771,786
780,372
(340,730)
(23,222)
1,188,206
$
$
$
7.87
12.55
10.99
8.71
6.20
8.78
8.72
6.47
3.48
7.01
6.49
4.35
$
$
$
3.1
4.6
3.9
As of December 31, 2017, there was approximately $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 1.7 years.
Total compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 related to the awards
under the CVR Partners LTIP was approximately $1.1 million, $1.8 million and $1.3 million, respectively.
At December 31, 2017 and 2016, the Nitrogen Fertilizer Partnership had a liability of $0.7 million and $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,
2017, 2016 and 2015 the Nitrogen Fertilizer Partnership paid cash of $1.4 million, $2.1 million and $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 was 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 were provided. Each phantom unit and distribution equivalent right represents the right to
receive, upon vesting, a cash payment equal to (i) the average 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, 2017 and 2016 related to the award was not
material. As there were no remaining performance cycles related to these awards, there was no unrecognized
compensation expense or liability associated with the phantom units at December 31, 2017.
On December 31, 2014, the first award of the Phantom Unit Agreement vested and a nominal amount was paid
in 2015. On December 31, 2015, the second award of the Phantom Unit Agreement vested and a nominal amount
was paid in 2016. On December 31, 2016, the third award of the Phantom Unit Agreement vested and nominal
136
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
amount was paid in 2017. The award was fully vested at December 31, 2016 and the amount associated with the
agreement was not material.
Long-Term Incentive Plan – CVR Refining
Individuals who are eligible to receive awards under the CVR Refining, LP Long-Term Incentive Plan (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 Coffeyville 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.
In 2015, 2016 and 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.
A summary of phantom unit activity and changes under the CVR Refining LTIP during the years ended
December 31, 2017, 2016 and 2015 is presented below:
Non-vested at December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . .
Phantom Units
Weighted-
Average
Grant-Date
Fair Value
Aggregate
Intrinsic
Value
(in millions)
403,947
$
18.89
$
6.8
302,319
(136,531)
(58,144)
511,591
644,148
(218,351)
(32,533)
904,855
550,172
(349,921)
(118,626)
986,480
$
$
$
20.40
19.26
18.87
19.68
$
9.7
9.43
19.78
19.13
12.38
$
9.4
12.66
13.42
13.52
12.03
$
16.3
As of December 31, 2017, there was approximately $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, 2017, 2016 and 2015 related to the awards
under the CVR Refining LTIP was $7.4 million, $1.8 million and $4.6 million, respectively. As of December 31,
137
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
2017 and 2016, the Refining Partnership had a liability of $3.7 million and $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, 2017, 2016 and 2015, the Refining Partnership paid
cash of $5.1 million, $2.6 million and $3.3 million, respectively, to settle liability-classified phantom unit awards
and associated distribution equivalent rights upon vesting.
In December 2014, the Company granted an award of 227,927 incentive units in the form of SARs to an
executive of CVR Energy. In April 2015, the award granted was canceled 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, 2017,
2016 and 2015 and the liability related to the SARs as of December 31, 2017 and 2016 were not material.
Incentive Unit Awards
In 2015, 2016 and 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.
138
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, 2017, 2016 and 2015 is
presented below:
Non-vested at December 31, 2014 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2015 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2016 . . . . . . . . . . . . . . . . . . . . . . . .
Granted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forfeited . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Non-vested at December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . .
Incentive Units
Weighted-
Average
Grant-Date
Fair Value
Aggregate
Intrinsic
Value
(in millions)
435,515
$
18.95
$
7.3
347,811
(160,120)
(18,264)
604,942
678,469
(256,016)
(39,598)
987,797
382,648
(371,731)
(219,453)
779,261
$
$
$
20.38
19.33
19.69
19.64
9.46
19.69
19.52
12.63
12.87
14.14
12.23
$
$
11.5
10.3
12.14
$
12.9
As of December 31, 2017, there was approximately $10.0 million of total unrecognized compensation cost
related to non-vested incentive units to be recognized over a weighted-average period of approximately 1.6 years.
Total compensation expense for the years ended December 31, 2017, 2016 and 2015 related to the incentive units
was $6.8 million, $2.3 million and $5.7 million, respectively. As of December 31, 2017 and 2016, the Company had
a liability of $3.3 million and $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, 2017, 2016 and 2015, the Company paid cash of $5.5 million, $3.0 million and $3.9 million,
respectively, to settle liability-classified incentive unit awards and associated distribution equivalent rights upon
vesting.
(5) Inventories
Inventories consisted of the following:
Finished goods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Raw materials and precious metals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
In-process inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Parts and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
December 31,
2017
2016
(in millions)
172.0
$
151.7
113.8
22.4
77.0
98.4
23.9
75.2
385.2
$
349.2
139
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(6) Property, Plant and Equipment
Property, plant and equipment consisted of the following:
Land and improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Buildings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Machinery and equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Automotive equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Furniture and fixtures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Leasehold improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Aircraft . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Railcars . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Construction in progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: Accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Property, plant and equipment, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
December 31,
2017
2016
(in millions)
47.4
$
83.3
3,733.8
24.7
32.4
4.6
3.6
16.8
56.2
46.5
64.8
3,656.5
24.7
28.9
3.6
3.6
16.8
54.2
4,002.8
1,431.0
2,571.8
$
3,899.6
1,227.5
2,672.1
Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2017, 2016
and 2015 totaled approximately $1.1 million, $5.4 million and $3.7 million, respectively. Land, buildings and
equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million at
both December 31, 2017 and 2016. Amortization of assets held under capital leases is included in depreciation
expense.
140
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(7) Equity Method Investments
VPP Joint Venture
On September 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 evaluates the carrying value of goodwill annually as of November 1 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.
141
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 as of November 1, 2017. The qualitative analysis included an
analysis of the key drivers and other external factors that may impact the results of operations of the Nitrogen
Fertilizer Partnership's Coffeyville Facility to determine if 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 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
Partnership's Coffeyville Facility was less than the carrying value. Based on the results of the tests, it was not
necessary to perform the quantitative goodwill impairment analysis.
(9) Insurance Claims
On July 29, 2014, the Refining Partnership's Coffeyville refinery experienced a fire at its isomerization unit.
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. 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 had 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 received net indemnity
of approximately $1.2 million from insurers for this incident in the first quarter of 2016. The insurance indemnity
reduced direct operating expenses (exclusive of depreciation and amortization).
142
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(10) Income Taxes
On May 19, 2012, CVR became a member of the consolidated federal tax group of 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.
As of December 31, 2017 and 2016, the Company's Consolidated Balance Sheets reflected a receivable of $5.1
million and a payable of $10.6 million, respectively, for federal income taxes due to/from AEPC. These amounts are
recorded as due to/from parent in the Consolidated Balance Sheets. During the years ended December 31, 2017,
2016 and 2015, the Company paid $15.0 million, $45.0 million and $57.5 million, respectively, to AEPC under the
Tax Allocation Agreement.
Income tax expense (benefit) is comprised of the following:
Current. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total current. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Federal. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
State. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total deferred. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
(in millions)
2015
(0.7) $
(22.1)
(22.8)
(181.4)
(12.7)
(194.1)
(216.9) $
$
67.2
(7.0)
60.2
(61.0)
(19.0)
(80.0)
(19.8) $
74.9
14.5
89.4
2.7
(7.6)
(4.9)
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,
2017
2016
(in millions)
2015
Tax computed at federal statutory rate . . . . . . . . . . . . . . . . . . . . . $
State income taxes, net of federal tax benefit . . . . . . . . . . . . . . . .
State tax incentives, net of federal tax expense. . . . . . . . . . . . . . .
Domestic production activities deduction . . . . . . . . . . . . . . . . . . .
Noncontrolling interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Adjustment to deferred tax assets and liabilities for enacted
change in federal tax rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total income tax expense (benefit) . . . . . . . . . . . . . . . . . . . . . . . . $
$
0.0
(15.7)
(6.9)
—
6.1
0.1
(3.8) $
(8.0)
(8.8)
(4.3)
5.5
(0.4)
(200.5)
(216.9) $
—
(19.8) $
133.8
11.7
(7.2)
(5.9)
(44.9)
(3.0)
—
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
143
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, $5.7 million and $4.3 million on a credit of approximately $6.6 million, $8.7 million and $6.7 million for
the years ended December 31, 2017, 2016 and 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 $2.6 million, $3.1 million and $2.9 million on a credit of
approximately $4.0 million, $4.8 million and $4.4 million for the years ended December 31, 2017, 2016 and 2015,
respectively, with respect to the Oklahoma Investment credits.
As of December 31, 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 Company 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 was 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 will be realized. A benefit of approximately $200.5 million was recognized as a result of the
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, 2017 and 2016 are as follows:
Deferred income tax assets:
Personnel accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
State tax credit carryforward, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net operating loss carryforward . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total gross deferred income tax assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Deferred income tax liabilities:
Personnel accruals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Property, plant, and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in CVR Partners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Investment in CVR Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Prepaid expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total gross deferred income tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Net deferred income tax liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
144
December 31,
2017
2016
(in millions)
— $
11.3
7.2
—
18.5
(1.2)
(2.1)
(54.6)
(345.3)
(0.2)
(1.0)
(404.4)
(385.9) $
1.3
10.5
—
0.1
11.9
—
(3.8)
(89.2)
(497.8)
(0.3)
(0.7)
(591.8)
(579.9)
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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, 2017 and
2016.
A reconciliation of the unrecognized tax benefits for the years ended December 31, 2017, 2016 and 2015 is as
follows:
Balance beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Increase based on prior year tax positions. . . . . . . . . . . . . . . . . . .
Decrease based on prior year tax positions . . . . . . . . . . . . . . . . . .
Increases in current year tax positions. . . . . . . . . . . . . . . . . . . . . .
Settlements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Reductions related to expirations of statute of limitations . . . . . .
Balance end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Year Ended December 31,
2017
2016
(in millions)
2015
44.1
$
49.0
$
—
—
—
—
(15.4)
28.7
$
—
—
—
—
(4.9)
44.1
$
55.5
—
—
9.8
—
(16.3)
49.0
Included in the balance of unrecognized tax benefits as of December 31, 2017, 2016 and 2015 are $22.7 million,
$28.7 million and $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 $5.8 million of its unrecognized tax positions relating to state tax
credits may be recognized by the end of 2018 as a result of a lapse of the statute of limitations. Approximately $25.8
million and $25.7 million of unrecognized tax benefits were netted with deferred tax asset carryforwards as of
December 31, 2017 and 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 benefit of approximately $7.0 million during 2017 and
has recognized a liability for interest of approximately $1.0 million as of December 31, 2017. In 2016, CVR
recognized interest expense of approximately $0.5 million and had recognized a liability for interest of
approximately $8.0 million as of December 31, 2016. In 2015, CVR recognized interest expense of approximately
$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 2017, 2016 or 2015.
At December 31, 2017, the Company's tax filings are generally open to examination in the United States for the
tax years ended December 31, 2014 through December 31, 2016 and in various individual states for the tax years
ended December 31, 2013 through December 31, 2016.
145
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(11) Long-Term Debt
Long-term debt consisted of the following:
December 31, 2017
December 31, 2016
(in millions)
6.5% Senior Notes due 2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
9.25% Senior Secured Notes due 2023 . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.5% Senior Notes due 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Capital lease obligations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt issuance cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Unamortized debt discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Current portion of capital lease obligations . . . . . . . . . . . . . . . . . . . . . . .
Long-term debt, net of current portion . . . . . . . . . . . . . . . . . . . . . . . . $
500.0
645.0
2.2
45.0
1,192.2
(12.2)
(13.5)
(2.1)
1,164.4
$
$
500.0
645.0
2.2
46.9
1,194.1
(14.2)
(15.3)
(1.8)
1,162.8
2022 Senior 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
Notes due 2022 (the "2022 Notes"). The 2022 Notes are unsecured and 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.
CVR Energy, CVR Partners and their respective subsidiaries are not guarantors.
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 imposes covenants that restrict the ability 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 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 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
146
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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. The Refining Partnership was in compliance with the covenants as of
December 31, 2017, and the 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, 2017 and 2016 related to the 2022 Notes. At December 31,
2017, the estimated fair value of the 2022 Notes was approximately $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.
Amended and Restated Asset Based (ABL) Credit Facility
On November 14, 2017, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of
Refining LLC (collectively, the "Credit Parties") entered into Amendment No. 1 to the Amended and Restated ABL
Credit 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 November 14, 2022.
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 swingline loans of $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 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 exceeds 15% of the lesser of the borrowing base and the
total commitments, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period
shall be equal to or greater than 1.00 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).
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) 1.50% for LIBOR borrowings and (b) 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) 1.75% for LIBOR borrowings and (b) 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) 0.375% 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) 0.25% 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
147
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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,
investments and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted
subsidiaries. The Amended and Restated 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, 2017.
In connection with the Amended and Restated ABL Credit Facility, CRLLC and its subsidiaries incurred lender
and other third-party costs of approximately $1.6 million for the year ended December 31, 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 $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.
As of December 31, 2017, the Refining Partnership had availability under the Amended and Restated ABL
Credit Facility of $337.7 million and had letters of credit outstanding of approximately $28.4 million. There were no
borrowings outstanding under the Amended and Restated ABL Credit Facility as of December 31, 2017. Availability
under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of December 31,
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
148
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 of December 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.
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
149
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
Nitrogen Fertilizer Partnership Credit Facility
On 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. At March 31, 2016, the effective rate
of the term loan was approximately 3.98%. On April 1, 2016, the Partnership repaid all amounts outstanding under
the Credit Agreement and the Credit Agreement was terminated.
Deferred Financing Costs
For the years ended December 31, 2017, 2016 and 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,
respectively.
Capital Lease Obligations
The Refining Partnership maintains two leases, accounted for as a capital lease and a financial obligation, which
relate to the Magellan Pipeline Terminals, L.P. ("Magellan Pipeline") and Excel Pipeline LLC ("Excel Pipeline").
The underlying assets and related depreciation are 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, has 142 months remaining of its term and will expire in September 2029. The financing arrangement,
which relates to the Magellan Pipeline terminals, bulk terminal and loading facility, has 141 months remaining of its
lease term and will expire in September 2029. As of December 31, 2017, the outstanding obligation associated with
these arrangements totaled approximately $45.0 million, of which $42.9 million is included in long-term liabilities
and $2.1 million is included in current liabilities in the Consolidated Balance Sheets.
150
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Future payments required under capital lease at December 31, 2017 are as follows:
Year Ending December 31,
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total future payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: amount representing interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Present value of future minimum payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less: current portion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Long-term portion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Capital Lease
(in millions)
6.5
6.5
6.5
6.5
6.5
44.2
76.7
31.7
45.0
2.1
42.9
(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.
The following is a summary of the quarterly and special dividends paid to stockholders during the years ended
December 31, 2017 and 2016:
December 31, 2016
March 31, 2017
June 30, 2017
September 30, 2017
Total Dividends
Paid in 2017
(in millions, except per share data)
Dividend type . . . . .
Amount paid to IEP $
Amounts paid to
public stockholders .
Total amount paid . . $
Per common share. . $
Shares outstanding .
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
142.4
31.3
173.7
2.00
151
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
December 31, 2015
March 31, 2016
June 30, 2016
September 30, 2016
Total Dividends
Paid in 2016
(in millions, except per share data)
Dividend type . . . . .
Amount paid to IEP $
Amounts paid to
public stockholders.
Total amount paid. . $
Per common share . $
Shares outstanding .
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
Quarterly
35.6
7.8
43.4
0.50
86.8
$
$
$
142.4
31.2
173.6
2.00
(13) Earnings Per Share
The computations of the basic and diluted earnings per share for the years ended December 31, 2017, 2016 and
2015 are as follows:
For the Year Ended December 31,
2017
2016
2015
Net income attributable to CVR Energy stockholders . . . . . . . . . $
(in millions, except per share data)
234.4
24.7
$
$
Weighted-average shares of common stock outstanding - Basic
and Diluted . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
86.8
86.8
Basic and Diluted earnings per share . . . . . . . . . . . . . . . . . . . . . . $
2.70
$
0.28
$
169.6
86.8
1.95
There were no dilutive awards outstanding during the years ended December 31, 2017, 2016 and 2015 as all
unvested awards under the LTIP were liability-classified awards. See Note 4 ("Share-Based Compensation").
(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 $8.5 million, $8.1 million and $7.3 million for the years ended December 31, 2017, 2016 and 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.
152
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(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)
2018. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2019. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$
_______________________________________
$
(in millions)
7.4
6.5
5.9
5.3
4.8
2.4
32.3
$
165.0
124.3
100.6
89.8
84.7
542.7
1,107.1
(1)
This amount includes approximately $698.6 million payable ratably over 13 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, 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 20 years on TransCanada's Keystone pipeline
system.
CVR leases equipment, including railcars and real properties, under long-term operating leases expiring at
various dates through 2035. For the years ended December 31, 2017, 2016 and 2015, lease expense totaled
approximately $7.6 million, $8.2 million and $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,
2017, 2016 and 2015, total expense of $209.4 million, $150.5 million and $135.9 million, respectively, was incurred
related to long-term commitments.
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, 2018.
153
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.
The U.S. Attorney’s office for the Southern District of New York contacted CVR Energy in September 2017
seeking production of information pertaining to our, CVR Refining’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 against
us or Mr. Icahn. We maintain a strong compliance program and, while no assurances can be made, we do not believe
this inquiry will have a material impact on our business, financial condition, results of operations or 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 Coffeyville 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. The parties stipulated to the value of
the real property, following which BOTA issued 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’s decision.
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.
154
CVR Energy, Inc. and Subsidiaries
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 U.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 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, all of which have 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. CRRM has completed the implementation of the recommendations of
several audits required by the RMP Consent Decree, which were related to compliance with RMP requirements.
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.
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, 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
155
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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, 2017 and 2016, environmental
accruals of approximately $3.9 million and $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 $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, 2017 and 2016, respectively. The accruals include estimated
closure and post-closure costs of approximately $0.4 million for two landfills at December 31, 2017 and 2016.
The estimated future payments for these required obligations are as follows:
Year Ending December 31,
2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2020 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2022 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Thereafter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Undiscounted total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Less amounts representing interest at 1.98% . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Accrued environmental liabilities at December 31, 2017 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Amount
(in millions)
2.9
1.1
—
—
—
—
4.0
0.1
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.
156
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 were
required to be in compliance with the more stringent emission standards as of January 1, 2017; however, compliance
with the rule was 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. 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 was accelerated to December 21, 2018. It is not anticipated that the refineries will require additional
controls or capital expenditures to meet the new standard.
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. 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 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 is blended into transportation
fuel.
In December 2015, 2016 and 2017, the EPA published in the Federal Register final rules establishing the
renewable fuel volume mandates for 2016, 2017 and 2018, and the biomass-based diesel volume mandates for 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 authorities to lower the volumes in each rulemaking, but its decision to do so for the 2014-2016
compliance years was challenged in the U.S. Court of Appeals for the District of Columbia 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.
RINs expense for the years ended December 31, 2017, 2016 and 2015 was approximately $249.0 million,
$205.9 million and $123.9 million, respectively. As of December 31, 2017 and 2016, CVR Refining's biofuel
blending obligation was approximately $28.3 million and $186.3 million, respectively, which is recorded in other
current liabilities in the Consolidated Balance Sheets. The price of RINs has been extremely volatile 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
157
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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
reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its fluid 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.
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 National
Emission Standard for Hazardous Air Pollutants ("NESHAP"). The National Petroleum Refining Initiative has
resulted in most U.S. refineries (representing more than 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. In March 2016, the United States District Court for the District of Kansas approved a modification to the
Second Consent Decree memorializing 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 is 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. The
additional incremental capital expenditures associated with the Second Consent Decree are expected to be
approximately $0.7 million.
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. ODEQ 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 are estimated to be
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, 2017, 2016 and 2015, capital expenditures were approximately $15.6
million, $17.2 million and $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.
158
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 was no environmental impact. The refinery was in the final stages of
shutdown for turnaround maintenance at the time of the incident. WRC completed an internal investigation of the
incident and cooperated with the 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.
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, 2017. If
the ACF and Federal-Mogul plans were voluntarily terminated, they would be collectively underfunded by
approximately $423.7 million and $613.4 million as of December 31, 2017 and 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.
(16) Fair Value Measurements
In accordance with FASB ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820"), the
Company utilizes the market approach to 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 or liabilities, such as a business.
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:
159
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Level 1 — Quoted prices in active markets for identical assets or liabilities
Level 2 — Other significant observable inputs (including quoted prices in active markets for similar
assets or liabilities)
Level 3 — Significant unobservable inputs (including the Company's own assumptions in determining
the fair value)
•
•
•
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input
level, as of December 31, 2017 and 2016:
Location and Description
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . $
Other current assets (investments) . . . . . . . . . . .
Total Assets. . . . . . . . . . . . . . . . . . . . . . . . . $
Other current liabilities (derivative
agreements) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other current liabilities (biofuel blending
obligation) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total Liabilities . . . . . . . . . . . . . . . . . . . . . . $
Location and Description
Cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . $
Other current assets (investments) . . . . . . . . . . .
Total Assets. . . . . . . . . . . . . . . . . . . . . . . . . $
Other current liabilities (derivative
agreements) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Other current liabilities (biofuel blending
obligation & benzene obligation). . . . . . . . . . . .
Total Liabilities . . . . . . . . . . . . . . . . . . . . . . $
Level 1
Level 2
Level 3
Total
December 31, 2017
(in millions)
— $
—
— $
15.2
0.1
15.3
$
$
— $
—
— $
15.2
0.1
15.3
— $
(64.3) $
— $
(64.3)
—
— $
(1.0)
(65.3) $
—
— $
(1.0)
(65.3)
Level 1
Level 2
Level 3
Total
December 31, 2016
(in millions)
— $
—
— $
15.8
0.1
15.9
$
$
— $
—
— $
15.8
0.1
15.9
— $
(11.1) $
— $
(11.1)
—
— $
(187.0)
(198.1) $
—
— $
(187.0)
(198.1)
As of December 31, 2017 and 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, uncommitted biofuel
blending obligation and benzene obligations. Additionally, the fair value of the Company's debt issuances is
disclosed in Note 11 ("Long-Term Debt"). The Refining Partnership's commodity derivative contracts, the
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 Company had
no transfers of assets or liabilities between any of the above levels during the year ended December 31, 2017.
In March 2016, CVR Energy purchased 400,000 CVR Nitrogen common units in the public market. During the
first quarter of 2016, the fair value of the common units was based on quoted prices for the identical 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 reclassified as an investment in consolidated subsidiary and is eliminated in
consolidation. Subsequent to the East Dubuque Merger, the Nitrogen Fertilizer Partnership purchased the 400,000
160
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
CVR Nitrogen common units from CVR Energy during the second quarter of 2016. During the year ended
December 31, 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 $19.3 million
for the sale of this investment in available-for-sale securities. Upon the sale of the available-for-sale securities, the
Company reclassified an unrealized gain of $0.5 million from accumulated 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, 2016.
(17) Derivative Financial Instruments
Current period settlements on derivative contracts and Loss on derivatives, net were as follows:
Year Ended December 31,
2017
2016
(in millions)
2015
Current period settlement on derivative contracts. . . . . . . . . . . . . $
Loss on derivatives, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
(16.6) $
(69.8)
$
36.4
(19.4)
(26.0)
(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 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, 2017 or 2016. For the years ended
December 31, 2017, 2016 and 2015, the Refining Partnership recognized a net loss of $0.5 million, a net loss of $0.5
million, and a net gain of $3.2 million, respectively, which are recorded in loss on derivatives, net in the
Consolidated Statements of Operations.
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, 2017, 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
161
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
distillate crack spreads, and 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 4.0 million barrels of crack spreads, 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, 2017
was a net unrealized loss of $64.3 million, of which the entire balance is included in other current liabilities. The fair
value of the outstanding contracts at December 31, 2016 was a net unrealized loss of $11.1 million, of which entire
balance is included in other current liabilities. For the years ended December 31, 2017, 2016 and 2015, the Refining
Partnership recognized a net loss of $69.3 million, $18.9 million and $36.4 million, respectively, which are recorded
in loss on derivatives, net in the Consolidated Statements of Operations.
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, 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.
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 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.
162
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, 2017 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:
Description
As of December 31, 2017
Gross
Current
Assets
Gross
Amounts
Offset
Net
Current
Assets
Presented
(in millions)
Cash
Collateral
Not Offset
Net
Amount
Commodity Swaps . . . . . . . . . . . . . . . . . . . . . . $
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
7.0
7.0
$
$
(7.0) $
(7.0) $
— $
— $
— $
— $
—
—
Description
As of December 31, 2017
Gross
Current
Liabilities
Gross
Amounts
Offset
Net
Current
Liabilities
Presented
Cash
Collateral
Not Offset
Net
Amount
Commodity Swaps . . . . . . . . . . . . . . . . . . . . . . $
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
71.3
71.3
$
$
(in millions)
64.3
64.3
(7.0) $
(7.0) $
$
$
— $
— $
64.3
64.3
Description
As of December 31, 2016
Gross
Current
Liabilities
Gross
Amounts
Offset
Net
Current
Liabilities
Presented
Cash
Collateral
Not Offset
Net
Amount
Commodity Swaps . . . . . . . . . . . . . . . . . . . . . . $
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
11.1
11.1
$
$
(in millions)
11.1
11.1
— $
— $
$
$
— $
— $
11.1
11.1
(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, 2017, IEP owned
approximately 82% of all common shares outstanding.
Railcar Lease Agreements and Maintenance
The Nitrogen Fertilizer Partnership has agreements to lease a total of 115 UAN railcars from American Railcar
Leasing, LLC ("ARL"), a company controlled by IEP. The lease agreements will expire in 2023. In the second
quarter of 2017, the Nitrogen Fertilizer Partnership entered into an agreement to lease an additional 70 UAN railcars
from ARL 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, 2017 and 2016, rent expense of approximately
$1.0 million and $0.3 million, respectively, was recorded in cost of materials and other in the Consolidated
Statements of Operations related to these agreements.
American Railcar Industries, Inc. a company controlled by IEP, performed railcar maintenance for the Nitrogen
Fertilizer Partnership and the expense associated with this maintenance was approximately $0.2 million for the year
ended December 31, 2017 and was included in cost of materials and other in the Consolidated Statement of
Operations.
163
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 10 ("Income Taxes") for a discussion of related party
transactions under the Tax Allocation Agreement.
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 $0.2 million, $0.2 million and $0.1 million during the years ended
December 31, 2017, 2016 and 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 Facility with the Nitrogen Fertilizer Partnership
On April 1, 2016, in connection with the closing of the East Dubuque Merger, the Nitrogen Fertilizer
Partnership entered into a $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 fund the repayment of amounts
outstanding under the Wells Fargo Credit Agreement discussed in Note 3 ("Acquisition") (ii) to pay the cash
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 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 7 ("Equity
Method Investments") for additional discussion of the joint ventures.
(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. All intercompany transactions are eliminated in the other segment as described below. All operations of
the segments are located within the United States.
Petroleum
Principal products of the petroleum segment include gasoline, diesel fuel, jet fuel, natural gas liquids, asphalt
and petroleum refining by-products, including petroleum coke, which are sold to retailers, petroleum jobbers,
railroads and other refiners/marketers. The petroleum segment also sells hydrogen and petroleum coke to the
164
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
nitrogen fertilizer segment pursuant to separate intercompany agreements. Intercompany sales included in petroleum
net sales are eliminated in consolidation.
The petroleum segment may 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 materials and other and are eliminated in consolidation.
Nitrogen Fertilizer
The principal product of the nitrogen fertilizer segment is nitrogen fertilizer. Nitrogen fertilizer is used by
farmers to improve the yield and quality of their crops, primarily corn and wheat. The nitrogen fertilizer segment
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 are 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 are 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 are reported in nitrogen fertilizer
cost of materials and other and are eliminated 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.
165
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following table summarizes certain operating results and capital expenditures information by segment:
Net sales
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment elimination. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Cost of materials and other
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Intersegment elimination. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Direct operating expenses (exclusive of depreciation and
amortization)
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Depreciation and amortization
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating income (loss)
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Capital expenditures
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen fertilizer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
2016
(in millions)
2015
5,664.2
$
4,431.3
$
330.8
(6.6)
5,988.4
4,804.7
84.9
(6.7)
4,882.9
$
$
$
356.3
(5.2)
4,782.4
3,759.2
93.7
(5.4)
3,847.5
$
$
$
5,161.9
289.2
(18.6)
5,432.5
4,143.6
65.2
(18.4)
4,190.4
443.8
$
393.4
$
155.5
0.2
599.5
133.1
74.0
6.9
214.0
203.8
(9.2)
(16.8)
177.8
99.7
14.5
4.4
$
$
$
$
$
$
148.3
0.1
541.8
129.0
58.2
5.9
193.1
77.8
26.8
(13.7)
90.9
102.3
23.2
7.2
$
$
$
$
$
$
478.5
106.1
0.1
584.7
130.2
28.4
5.5
164.1
361.7
68.7
(8.8)
421.6
194.7
17.0
7.0
218.7
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
118.6
$
132.7
$
166
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Year Ended December 31,
2017
2016
(in millions)
2015
Total assets
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2,269.9
$
2,331.9
$
2,189.0
1,234.3
302.5
1,312.2
406.1
536.3
574.1
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
3,806.7
$
4,050.2
$
3,299.4
Goodwill
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Nitrogen Fertilizer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
— $
— $
41.0
—
41.0
—
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
41.0
$
41.0
$
—
41.0
—
41.0
(20) Major Customers and Suppliers
Sales to major customers as a percentage of the respective segment's sales were as follows:
Petroleum
Customer A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Nitrogen Fertilizer
Customer B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Customer C . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Year Ended December 31,
2017
2016
2015
19%
5%
11%
16%
15%
10%
10%
20%
14%
10%
14%
24%
The petroleum segment obtained crude oil from one third-party supplier under a long-term supply agreement
during 2017, 2016 and 2015. Volume contracted as a percentage of the total crude oil purchases (in barrels) for each
of the periods was as follows:
Petroleum
Supplier A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
55%
61%
61%
Year Ended December 31,
2017
2016
2015
167
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(21) Selected Quarterly Financial Information (unaudited)
Summarized quarterly financial data for December 31, 2017 and 2016 is as follows:
Year Ended December 31, 2017
Quarter
First
Second
Third
Fourth
Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses:
1,507.1
$
(in millions, except per share data)
1,453.8
1,434.4
$
$
1,593.1
Cost of materials and other . . . . . . . . . . . . . . .
Direct operating expenses (exclusive of
depreciation and amortization as reflected
below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . .
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative (exclusive
of depreciation and amortization as reflected
below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . .
Total operating costs and expenses. . . . . . .
Operating income . . . . . . . . . . . . . . . . . . . .
Other income (expense):
Interest expense and other financing costs . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . .
Gain (loss) on derivatives, net . . . . . . . . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . .
Total other expense. . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . .
Net income (loss). . . . . . . . . . . . . . . . . . . . . . .
Less: Net income (loss) attributable to
noncontrolling interest . . . . . . . . . . . . . . . .
Net income (loss) attributable to CVR
Energy stockholders . . . . . . . . . . . . . . . . . . $
Basic and diluted earnings (loss) per share. $
Dividends declared per share . . . . . . . . . . . $
1,221.2
1,228.6
1,132.4
1,300.7
138.1
48.6
1,407.9
29.1
2.5
1,439.5
67.6
(27.0)
0.2
12.2
—
(14.6)
53.0
14.8
38.2
16.0
22.2
0.26
0.50
124.2
51.7
1,404.5
26.3
2.3
1,433.1
1.3
(27.6)
0.3
—
0.1
(27.2)
(25.9)
(6.6)
(19.3)
(8.8)
$
$
$
(10.5) $
(0.12) $
$
0.50
161.1
51.3
1,344.8
27.3
2.8
1,374.9
78.9
(27.6)
0.2
(17.0)
—
(44.4)
34.5
9.2
25.3
3.1
22.2
0.26
0.50
$
$
$
176.1
51.7
1,528.5
31.5
3.1
1,563.1
30.0
(27.9)
0.4
(65.0)
0.9
(91.6)
(61.6)
(234.3)
172.7
(27.8)
200.5
2.31
0.50
Weighted-average common shares
outstanding - basic and diluted . . . . . . . . . .
86.8
86.8
86.8
86.8
168
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Year Ended December 31, 2016
Quarter
First
Second
Third
Fourth
Net sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $
Operating costs and expenses:
905.5
$
(in millions, except per share data)
1,240.3
1,283.2
$
$
1,353.4
Cost of materials and other . . . . . . . . . . . . . . .
Direct operating expenses (exclusive of
depreciation and amortization as reflected
below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . .
Cost of sales . . . . . . . . . . . . . . . . . . . . . . . .
Selling, general and administrative (exclusive
of depreciation and amortization as reflected
below) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Depreciation and amortization . . . . . . . . . . . .
Total operating costs and expenses. . . . . . .
Operating income (loss) . . . . . . . . . . . . . . .
Other income (expense):
Interest expense and other financing costs . . .
Interest income . . . . . . . . . . . . . . . . . . . . . . . .
Loss on derivatives, net . . . . . . . . . . . . . . . . . .
Gain (loss) on extinguishment of debt. . . . . . .
Other income, net . . . . . . . . . . . . . . . . . . . . . .
Total other expense. . . . . . . . . . . . . . . . . . .
Income (loss) before income taxes . . . . . . .
Income tax expense (benefit) . . . . . . . . . . . . . . .
Net income (loss). . . . . . . . . . . . . . . . . . . . . . .
Less: Net income (loss) attributable to
noncontrolling interest . . . . . . . . . . . . . . . .
Net income (loss) attributable to CVR
Energy stockholders . . . . . . . . . . . . . . . . . . $
Basic and diluted earnings (loss) per share. $
Dividends declared per share . . . . . . . . . . . $
Weighted-average common shares
outstanding
736.8
976.9
1,005.7
1,128.1
141.4
37.9
916.1
27.2
2.1
945.4
(39.9)
(12.1)
0.2
(1.2)
—
0.3
(12.8)
(52.7)
(21.8)
(30.9)
(14.7)
(16.2) $
(0.19) $
$
0.50
138.3
48.5
1,163.7
26.6
2.2
1,192.5
90.7
129.5
48.2
1,183.4
27.8
1.9
1,213.1
27.2
(18.5)
0.1
(1.9)
(5.1)
0.1
(25.3)
65.4
21.6
43.8
15.4
28.4
0.33
0.50
$
$
$
(26.2)
0.2
(1.7)
—
5.0
(22.7)
4.5
2.5
2.0
(3.4)
5.4
0.06
0.50
$
$
$
132.6
49.9
1,310.6
27.5
2.4
1,340.5
12.9
(27.1)
0.2
(14.6)
0.2
0.3
(41.0)
(28.1)
(22.1)
(6.0)
(13.1)
7.1
0.08
0.50
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 Refining Partnership's Wynnewood
refinery completed the first phase of its most recent major scheduled turnaround in the 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
169
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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 $31.5 million for the
year ended December 31, 2016, of which approximately $29.4 million and $2.1 million were incurred in the first
and second quarters of 2016, respectively.
As discussed in Note 2 ("Summary of Significant Accounting Policies"), during the third quarter of 2017 and
during the second quarter of 2016, the Nitrogen Fertilizer Partnership's East Dubuque facility completed major
scheduled turnarounds.
On April 1, 2016, the Nitrogen Fertilizer Partnership completed the East Dubuque Merger, whereby the
Nitrogen Fertilizer Partnership acquired the East Dubuque Facility. The consolidated financial statements include the
results of the East Dubuque Facility beginning on April 1, 2016, the date of the closing of the acquisition. See Note
3 ("Acquisition") for further discussion.
(22) Subsequent Events
Dividend
On February 21, 2018, the board of directors of the Company declared a cash dividend for the fourth quarter of
2017 to the Company's stockholders of $0.50 per share, or $43.4 million in aggregate. The dividend will be paid on
March 12, 2018 to stockholders of record at the close of business on March 5, 2018. IEP will receive $35.6 million
in respect of its 82% ownership interest in the Company's shares.
170
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, 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 Securities 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, 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, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over
financial reporting.
Item 9B. Other Information
None.
171
Item 10. Directors, Executive Officers and Corporate Governance
PART III
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 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, 2017 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.
172
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
2.1**
3.1**
3.1.1**
3.2**
4.1**
4.2**
4.3**
4.4**
4.5**
4.6**
Exhibit Title
Transaction Agreement among CVR Energy, Inc., IEP Energy LLC and each of the other Offeror
Parties (as defined therein) dated as of April 18, 2012 (incorporated by reference to Exhibit 2.1 to the
Company's Form 8-K filed on April 23, 2012).
Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (incorporated by reference
to Exhibit 10.1 to the Company's Form 10-Q filed on December 6, 2007).
Certificate of Designations, Rights and Preferences setting forth the terms of the Series A Preferred
Stock of CVR Energy, Inc. (incorporated by reference to Exhibit 3.1 to the Company's Form 8-K
filed on January 17, 2012).
Amended and Restated Bylaws of CVR Energy, Inc. (incorporated by reference to Exhibit 3.1 to the
Company's Form 8-K filed on July 20, 2011).
Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007).
Indenture, dated as of October 23, 2012, among CVR Refining, LLC, Coffeyville Finance Inc., the
Guarantors (as defined therein) and Wells Fargo Bank, National Association, as Trustee and
Collateral Trustee (incorporated by reference to Exhibit 4.1 to the Company's Form 8-K filed on
October 29, 2012).
Forms of 6.500% Second Lien Senior Secured Notes due 2022 (included within the Indenture filed as
Exhibit 4.2).
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)).
Form of 9.250% Senior Secured Note due 2023 (included within the Indenture filed as Exhibit 4.4
and incorporated by reference to Exhibit 4.1 to 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)).
173
4.7**
4.8**
10.1**
10.1.1**
10.2**
10.3**
10.4**
10.5**
10.6**
Forms of 6.5% Second Lien Senior Secured Notes due 2021 (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).
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 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).
174
10.7**
10.8**
10.8.1**
10.8.2**
10.9**
10.10**
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.).
Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, by and between
The BOC Group, Inc. (n/k/a Linde LLC) and Coffeyville Resources Nitrogen Fertilizers, LLC
(incorporated by reference to Exhibit 10.6 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.).
First Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of
October 31, 2008, by and between Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc.
(n/k/a Linde LLC) (incorporated by reference to Exhibit 10.3 to the Company's Form 10-Q filed on
November 13, 2008).
Second Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of
October 1, 2017 by and between Linde LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
(incorporated by reference as Exhibit 10.2.2 to the Form 10-K filed by CVR Partners, LP on February
23, 2018 (Commision File No. 001-65120)).
Hydrogen Purchase and Sale Agreement, dated as of January 1, 2017, by and between Coffeyville
Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC
(incorporated by reference to Exhibit 10.1 to CVR Partners, LP's Form 10-Q filed on April 27, 2017
(Commission File No. 001-35120)).
Amended and Restated Crude Oil Supply Agreement, dated August 31, 2012, by and between
Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to
Exhibit 10.2 to the Company's Form 10-Q filed on November 6, 2012) (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.).
10.10.1**
First Amendment to Amended and Restated Crude Oil Supply Agreement, dated as of June 8, 2015,
by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC (incorporated by
reference to Exhibit 10.1 to the Company's Form 10-Q filed on July 30, 2015).
10.11**
10.12**+
10.13**+
10.14**+
10.15**+
10.16**+
Amended and Restated Electric Services Agreement dated as of August 1, 2010, by and between
Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas (incorporated by
reference to Exhibit 10.1 to the Company's Form 8-K filed on August 25, 2010).
Fifth Amended and Restated Employment Agreement, dated as of December 31, 2015, by and
between CVR Energy, Inc. and John J. Lipinski (incorporated by reference to Exhibit 10.18 to CVR
Partners, LP's Form 10-K filed on February 18, 2016 (Commission File No. 001-35120)).
Employment Agreement, dated as of November 1, 2017, by and between CVR Energy, Inc. and
David L. Lamp (incorporated by reference as Exhibit 10.20 to the Form 10-K filed by CVR Partners,
LP on February 23, 2018 (Commission File No. 001-35120)).
Performance Unit Agreement, dated as of November 1, 2017, by and between CVR Energy, Inc. and
David L. Lamp (incorporated by reference as Exhibit 10.21 to the Form 10-K filed by CVR Partners,
LP on February 23, 2018 (Commission File No. 001-35120)).
Performance Unit Award Agreement, dated as of November 1, 2017, by and between CVR Energy,
Inc. and David L. Lamp (incorporated by reference as Exhibit 10.22 to the Form 10-K filed by CVR
Partners, LP on February 23, 2018 (Commission File No. 001-35120)).
Employment Agreement, dated as of December 1, 2014, by and between CVR Energy, Inc. and
Martin J. Power (incorporated by reference to Exhibit 10.19 to the Company's Form 10-K filed on
February 20, 2015).
175
10.17**
10.18**
10.19**
Second Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated
April 13, 2011 (incorporated by reference to Exhibit 10.7 to the Company's Form 8-K/A filed on
May 23, 2011).
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).
Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources
Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by
reference to Exhibit 10.7 to the Company's Form 10-Q filed on December 6, 2007).
10.19.1**
Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville
Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC
(incorporated by reference to Exhibit 10.17.1 to the Company's Form 10-K filed on March 28, 2008).
10.19.2**
10.20**
Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between
Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen
Fertilizers, LLC (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q filed on
August 14, 2008).
Second Amended and Restated Feedstock and Shared Services Agreement, dated as of January 1,
2017, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources
Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q filed by CVR
Partners, LP on April 27, 2017).
10.20.1** Amendment to the Second Amended and Restated Feedstock and Shared Services Agreement, dated
as of November 1, 2017, by and between Coffeyville Resources Refining & Marketing, LLC and
Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7.1 to the
Form 10-K filed by CVR Partners, LP on February 23, 2018).
10.21**
10.22**
10.23**
10.24**
10.25**
10.26**
Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between
Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen
Fertilizers, LLC (incorporated by reference to Exhibit 10.9 to the Company's Form 10-Q filed on
December 6, 2007).
Third Amended and Restated Services Agreement, dated as of January 1, 2017, among CVR
Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 to the
Form 10-Q filed by CVR Partners, LP on April 27, 2017).
Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc.,
CVR GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.2 to the Company's
Form 8-K/A filed on May 23, 2011).
Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources
Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by
reference to Exhibit 10.5 to the Company's Form 10-Q filed on December 6, 2007).
Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, by and between
Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen
Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company's Form 8-K/A filed on
May 23, 2011).
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
filed by CVR Partners, LP on February 24, 2012 (Commission File No. 001-35120)).
10.26.1** Amendment to GP Services Agreement, dated as of June 27, 2014, by and between 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 August 1, 2014).
10.27**
Trademark License Agreement, dated as of April 13, 2011, by and between CVR Energy, Inc. and
CVR Partners, LP (incorporated by reference to Exhibit 10.9 to the Company's Form 8-K/A filed on
May 23, 2011).
176
10.28**
Lease and Operating Agreement, dated as of May 4, 2012, by and between Coffeyville Resources
Terminal, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to
Exhibit 10.2 to the Company's Form 10-Q filed on August 2, 2012).
10.29**
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.49 to the Company's
Form 10-K for the year ended December 31, 2008, filed on March 13, 2009).
10.30**+
Amended and Restated CVR Energy, Inc. 2007 Long Term Incentive Plan, dated as of December 26,
2013 (incorporated by reference to Exhibit 10.32 to the Company's Form 10-K filed on February 26,
2014).
10.30.1**+ Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.33.1 to the
Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007).
10.30.2**+ Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.33.2 to the
Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007).
10.30.3**+ Form of Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.28.3 to the
Company's Form 10-K for the year ended December 31, 2009, filed on March 12, 2010).
10.30.4**+ Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 to the Company's
Form 8-K filed on December 23, 2011).
10.30.5**+ Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to the
Company's Form 8-K filed on January 4, 2013).
10.30.6**+ Form of Incentive Unit Agreement (incorporated by reference to Exhibit 10.32.6 to the Company's
Form 10-K filed on February 26, 2014).
10.30.7*+
Form of Incentive Unit Agreement.
10.31**+
10.32**+
10.33**+
Performance Unit Agreement, dated as of December 31, 2015, by and between CVR Energy, Inc. and
John J. Lipinski (incorporated by reference to Exhibit 10.20 to CVR Partners, LP's Form 10-K filed
on February 18, 2016 (Commission File No. 001-35120)).
Other Unit Based Award Agreement, dated as of April 15, 2015, by and between CVR Energy, Inc.
and Martin J. Power (incorporated by reference to Exhibit 10.3 to CVR Refining, LP's Form 10-K
filed on February 19, 2016 (Commission File No. 001-35781)).
CVR Partners, LP Long-Term Incentive Plan (adopted March 16, 2011) (incorporated by reference to
Exhibit 10.1 to the Form S-8 filed by CVR Partners, LP on April 12, 2011 (Commission File
No. 333-173444)).
10.33.1**+ Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement
(incorporated by reference to Exhibit 10.38.3 to the Company's Form 10-K filed on February 20,
2015).
10.33.2**+ Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement
(incorporated by reference to Exhibit 10.16.5 to the Form 10-K filed by CVR Partners, LP on
February 23, 2018 (commission File No. 001-35120)).
10.34**+
10.35**+
10.36**
10.37**
Amended and Restated CVR Energy, Inc. Performance Incentive Plan (incorporated by reference to
Appendix A to the Company's Proxy Statement on Schedule 14A filed on April 29, 2016).
CVR Partners, LP Performance Incentive Plan (incorporated by reference to Exhibit 10.28 to the
Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)).
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)).
Contribution Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining
Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to
the Form S-1/A filed by CVR Refining, LP on January 8, 2013 (Commission File No. 333-184200)).
10.38**+
CVR Refining, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the
Partnership's Form 8-K filed on January 23, 2013 (Commission File No. 001-35781)).
177
10.38.1**+ Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement
(incorporated by reference to Exhibit 10.44.2 to the Company's Form 10-K filed on February 20,
2015).
10.38.2*+
Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement.
10.39**
10.40**
10.41**
Amended and Restated Services Agreement, dated as of January 1, 2017, by and among CVR
Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to
Exhibit 10.3 to the Form 10-Q filed by CVR Refining, LP on May 1, 2017).
Trademark License Agreement, dated as of January 23, 2013, by and among CVR Refining, LP and
CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by CVR Refining,
LP on January 29, 2013 (Commission File No. 001-35781)).
Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and among CVR
Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.4 to the
Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).
10.41.1**
First Amendment to Credit Agreement, dated as of October 29, 2014, by and among CVR
Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.1 to the
Company's Form 8-K filed October 30, 2014).
10.42**
10.43**
10.44**
10.45**
10.48**
10.49**
10.50**
10.51**
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)).
Amended and Restated Registration Rights Agreement, dated as of April 13, 2011, among CVR
Partners, LP and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.6 to the
Company's Form 8-K/A filed by on May 23, 2011).
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)).
Collateral Trust Agreement, dated as of June 10, 2016, 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 10.1 of the Form
8-K filed by CVR Partners on June 16, 2016 (Commission File No. 001-35120)).
Parity Lien Security Agreement, dated as of June 10, 2016, 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 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, 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 collateral agent (incorporated by reference to Exhibit
10.1 of the Form 8-K filed by CVR Partners, LP on October 6, 2016 (Commission File No.
001-35120)).
Security 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, LLC, CVR Nitrogen Finance Corporation, CVR Nitrogen GP, LLC, certain of
their affiliates from time to time party thereto, and UBS AG, Stamford Branch, as administrative
agent and collateral agent (incorporated by reference to Exhibit 10.2 of the Form 8-K filed by CVR
Partners, LP on October 6, 2016 (Commission File No. 001-35120)).
178
10.52**
Intercreditor 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, 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 collateral agent for the secured parties, Wilmington Trust, National Association, as trustee and
collateral 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 of the Form 8-K filed by CVR Partners, LP on October 6,
2016 (Commission File No. 001-35120)).
21.1**
List of Subsidiaries of CVR Energy, Inc (incorporated by reference to Exhibit 21.1 to the Company's
Form 10-K filed on February 21, 2017).
23.1*
31.1*
31.2*
32.1†
101*
Consent of Grant Thornton LLP.
Rule 13a-14(a)/15d-14(a) Certification of President and Chief Executive Officer.
Rule 13a-14(a)/15d-14(a) Certification of Executive Vice President, Chief Financial Officer and
Treasurer.
Section 1350 Certification of President and Chief Executive Officer and Executive Vice President,
Chief Financial Officer and Treasurer.
The following financial information for CVR Energy, Inc.'s Annual Report on Form 10-K for the year
ended December 31, 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.
Furnished herewith.
Denotes management contract or compensatory plan or arrangement.
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.
179
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.
SIGNATURES
CVR Energy, Inc.
By:
/s/ DAVID L. LAMP
Name:
Title:
David L. Lamp
President and Chief Executive Officer
Date: February 26, 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/ DAVID L. LAMP
David L. Lamp
/s/ SUSAN M. BALL
Susan M. Ball
Carl C. Icahn
/s/ BOB G. ALEXANDER
Bob G. Alexander
/s/ SUNGHWAN CHO
SungHwan Cho
/s/ JONATHAN FRATES
Jonathan Frates
/s/ STEPHEN MONGILLO
Stephen Mongillo
/s/ LOUIS J. PASTOR
Louis J. Pastor
/s/ JAMES M. STROCK
James M. Strock
President, Chief Executive Officer and Director
(Principal Executive Officer)
February 26, 2018
Executive Vice President, Chief Financial Officer and Treasurer
(Principal Financial and Accounting Officer)
February 26, 2018
Chairman of the Board of Directors
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
February 26, 2018
Director
Director
Director
Director
Director
Director
180
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2277 Plaza Drive, Suite 500
Sugar Land, Texas 77479
www.CVREnergy.com