(Mark One)
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þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended December 31, 2017
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OR
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from to .
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Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
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61-1512186
(I.R.S. Employer
Identification No.)
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2277 Plaza Drive, Suite 500
Sugar Land, Texas
(Address of Principal Executive Offices)
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77479
(Zip Code)
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $0.01 par value per share
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The New York Stock Exchange
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Large accelerated filer
o
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Accelerated filer
þ
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Non-accelerated filer
o
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(Do not check if a smaller reporting company)
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Smaller reporting company
o
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Emerging growth company
o
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Class
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Outstanding at February 20, 2018
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Common Stock, par value $0.01 per share
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86,831,050 shares
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Document
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Parts Incorporated
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Proxy Statement for the 2018 Annual Meeting of Stockholders
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Items 10, 11, 12, 13 and 14 of Part III
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Page
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•
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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.
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•
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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.
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•
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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.
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•
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restrictions on operations or the need to install enhanced or additional controls;
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•
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the need to obtain and comply with permits, licenses and authorizations;
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•
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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
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•
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specifications for the products marketed by the petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN and ammonia.
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Facility
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Site
Investigation
Costs
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Capital
Costs
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Total Operation & Maintenance Costs Through 2021
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Total Estimated Costs Through 2021
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||||||||
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(in millions)
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||||||||||||||
Coffeyville Refinery
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$
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0.1
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$
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—
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$
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—
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$
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0.1
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Phillipsburg Terminal
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0.3
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—
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—
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0.3
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Wynnewood Refinery
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—
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2.7
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0.9
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3.6
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||||
Total Estimated Costs
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$
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0.4
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$
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2.7
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$
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0.9
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$
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4.0
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•
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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;
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•
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accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect its refinery or suppliers or customers;
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•
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the counterparties to its futures contracts fail to perform under the contracts; or
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a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.
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•
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denial or delay in obtaining regulatory approvals and/or permits;
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•
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unplanned increases in the cost of equipment, materials or labor;
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•
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disruptions in transportation of equipment and materials;
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•
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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;
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•
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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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•
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market-related increases in a project's debt or equity financing costs; and/or
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•
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non-performance or force majeure by, or disputes with, the petroleum business' vendors, suppliers, contractors or sub-contractors.
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•
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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.
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•
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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.
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•
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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.
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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.
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•
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major unplanned maintenance requirements
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•
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catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire, or natural disasters, including, floods, windstorms and other similar events;
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•
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labor supply shortages, or labor difficulties that result in a work stoppage or slowdown;
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•
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cessation or suspension of a plant or specific operations dictated by environmental authorities; and
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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.
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limiting their ability to obtain additional financing to fund their working capital needs, capital expenditures, debt service requirements, acquisitions or other purposes;
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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);
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•
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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;
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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;
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restricting them from making strategic acquisitions or investments, introducing new technologies or exploiting business opportunities;
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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;
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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;
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•
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increasing their vulnerability to a downturn in general economic conditions or in pricing of their products; and
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•
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limiting their ability to react to changing market conditions in their respective industries and in their respective customers' industries.
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•
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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
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•
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their future ability to obtain other financing.
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incur additional indebtedness or issue certain preferred units;
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pay distributions in respect of our units or make other restricted payments;
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make certain payments on debt that is subordinated or secured on a junior basis;
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make certain investments;
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•
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sell certain assets;
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•
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create liens on certain assets;
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consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
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•
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enter into certain transactions with our affiliates; and
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•
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designate our subsidiaries as unrestricted subsidiaries.
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•
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the election and appointment of directors;
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•
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business strategy and policies;
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•
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mergers or other business combinations;
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•
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acquisition or disposition of assets;
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•
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future issuances of common stock, common units or other securities;
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•
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incurrence of debt or obtaining other sources of financing; and
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•
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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.
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•
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the requirement that a majority of our board of directors consist of independent directors;
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•
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the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors; and
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•
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the requirement that we have a compensation committee that is composed entirely of independent directors.
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•
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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;
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•
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limitations on the ability of stockholders to call special meetings of stockholders;
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•
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limitations on the ability of stockholders to act by written consent in lieu of a stockholders' meeting; and
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•
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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.
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•
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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.
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•
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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.
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•
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The partnership agreements provide that each partnership's general partner and the officers and directors of its general partner will not be liable for monetary damages to common unitholders, including us, for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that (i) in the case of the Nitrogen Fertilizer Partnership, the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct, or in, the case of a criminal matter, acted with knowledge that the conduct was criminal and (ii) in the case of the Refining Partnership, such losses or liabilities were the result of the conduct of our general partner or such officer or director engaged in by it in bad faith or with respect to any criminal conduct, with the knowledge that its conduct was unlawful.
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Location
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Acres
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Own/Lease
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Use
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Coffeyville, KS
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440
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Own
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Refining Partnership: oil refinery and office buildings
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Nitrogen Fertilizer Partnership: fertilizer plant
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Wynnewood, OK
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400
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Own
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Refining Partnership: oil refinery, office buildings, refined oil storage
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East Dubuque, IL
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210
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Own
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Nitrogen Fertilizer Partnership: fertilizer plant and fertilizer storage
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Montgomery County, KS (Coffeyville Station)
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30
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Own
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Refining Partnership: crude oil storage
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Montgomery County, KS (Broome Station)
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20
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Own
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Refining Partnership: crude oil storage
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Cowley County, KS (Hooser Station)
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70
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Own
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Refining Partnership: crude oil storage
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Cushing, OK
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138
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Own
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Refining Partnership: crude oil storage
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2017
|
High
|
|
Low
|
||||
First Quarter
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$
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25.91
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|
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$
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18.88
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Second Quarter
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23.20
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|
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17.53
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Third Quarter
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26.35
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|
|
16.75
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||
Fourth Quarter
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38.25
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|
|
25.35
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2016
|
High
|
|
Low
|
||||
First Quarter
|
$
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38.98
|
|
|
$
|
22.05
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|
Second Quarter
|
26.57
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|
|
14.87
|
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||
Third Quarter
|
16.39
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|
|
13.01
|
|
||
Fourth Quarter
|
25.41
|
|
|
12.03
|
|
|
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
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
|
||||||
Amount paid to IEP
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
142.4
|
|
Amounts paid to public stockholders
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
31.3
|
|
|||||
Total amount paid
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
173.7
|
|
Per common share
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
2.00
|
|
Shares outstanding
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
|
|
December 31, 2015
|
|
March 31, 2016
|
|
June 30, 2016
|
|
September 30, 2016
|
|
|
Total Dividends
Paid in 2016 |
||||||||||
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(in millions, except per share data)
|
|||||||||||||||||||
Dividend type
|
Quarterly
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|
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
|
|
||||||
Amount paid to IEP
|
$
|
35.6
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|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
|
$
|
142.4
|
|
Amounts paid to public stockholders
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
|
31.2
|
|
|||||
Total amount paid
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
|
$
|
173.6
|
|
Per common share
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
|
$
|
2.00
|
|
Shares outstanding
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
|
|
|
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
|
$
|
—
|
|
|
$
|
0.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.8
|
|
Amounts paid to public unitholders
|
—
|
|
|
1.5
|
|
|
—
|
|
|
—
|
|
|
1.5
|
|
|||||
Total amount paid
|
$
|
—
|
|
|
$
|
2.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.3
|
|
Per common unit
|
$
|
—
|
|
|
$
|
0.02
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.02
|
|
Common units outstanding
|
113.3
|
|
|
113.3
|
|
|
113.3
|
|
|
113.3
|
|
|
|
|
December 31, 2015
|
|
March 31, 2016
|
|
June 30, 2016
|
|
September 30, 2016
|
|
Total Cash
Distributions Paid in 2016 |
||||||||||
|
(in millions, except per common unit data)
|
||||||||||||||||||
Amount paid to CRLLC
|
$
|
10.5
|
|
|
$
|
10.5
|
|
|
$
|
6.6
|
|
|
$
|
—
|
|
|
$
|
27.6
|
|
Amounts paid to public unitholders
|
9.2
|
|
|
20.1
|
|
|
12.6
|
|
|
—
|
|
|
41.9
|
|
|||||
Total amount paid
|
$
|
19.7
|
|
|
$
|
30.6
|
|
|
$
|
19.2
|
|
|
$
|
—
|
|
|
$
|
69.5
|
|
Per common unit
|
$
|
0.27
|
|
|
$
|
0.27
|
|
|
$
|
0.17
|
|
|
$
|
—
|
|
|
$
|
0.71
|
|
Common units outstanding
|
73.1
|
|
|
113.3
|
|
|
113.3
|
|
|
113.3
|
|
|
|
|
Dec '12
|
|
Dec '13
|
|
Dec '14
|
|
Dec '15
|
|
Dec '16
|
|
Dec '17
|
|
||||||
CVR Energy, Inc.
|
314.57
|
|
|
358.04
|
|
|
354.60
|
|
|
378.31
|
|
|
244.10
|
|
|
439.48
|
|
|
Russell 2000 Index
|
106.36
|
|
|
145.72
|
|
|
150.86
|
|
|
142.24
|
|
|
169.95
|
|
|
192.28
|
|
|
Peer Group
|
264.52
|
|
|
346.24
|
|
|
324.45
|
|
|
378.74
|
|
|
343.43
|
|
|
390.83
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Statements of Operations Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net sales
|
$
|
5,988.4
|
|
|
$
|
4,782.4
|
|
|
$
|
5,432.5
|
|
|
$
|
9,109.5
|
|
|
$
|
8,985.8
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of materials and other
|
4,882.9
|
|
|
3,847.5
|
|
|
4,190.4
|
|
|
8,066.0
|
|
|
7,563.2
|
|
|||||
Direct operating expenses(1)
|
599.5
|
|
|
541.8
|
|
|
584.7
|
|
|
515.1
|
|
|
455.8
|
|
|||||
Depreciation and amortization
|
203.3
|
|
|
184.5
|
|
|
156.4
|
|
|
148.1
|
|
|
139.5
|
|
|||||
Cost of sales
|
5,685.7
|
|
|
4,573.8
|
|
|
4,931.5
|
|
|
8,729.2
|
|
|
8,158.5
|
|
|||||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|
—
|
|
|||||
Selling, general and administrative expenses(1)
|
114.2
|
|
|
109.1
|
|
|
99.0
|
|
|
109.7
|
|
|
113.5
|
|
|||||
Depreciation and amortization
|
10.7
|
|
|
8.6
|
|
|
7.7
|
|
|
6.3
|
|
|
3.3
|
|
|||||
Operating income
|
177.8
|
|
|
90.9
|
|
|
421.6
|
|
|
264.3
|
|
|
710.5
|
|
|||||
Interest expense and other financing costs
|
(110.1
|
)
|
|
(83.9
|
)
|
|
(48.4
|
)
|
|
(40.0
|
)
|
|
(50.5
|
)
|
|||||
Interest income
|
1.1
|
|
|
0.7
|
|
|
1.0
|
|
|
0.9
|
|
|
1.2
|
|
|||||
Gain (loss) on derivatives, net
|
(69.8
|
)
|
|
(19.4
|
)
|
|
(28.6
|
)
|
|
185.6
|
|
|
57.1
|
|
|||||
Loss on extinguishment of debt
|
—
|
|
|
(4.9
|
)
|
|
—
|
|
|
—
|
|
|
(26.1
|
)
|
|||||
Other income (expense), net
|
1.0
|
|
|
5.7
|
|
|
36.7
|
|
|
(3.7
|
)
|
|
13.5
|
|
|||||
Income (loss) before income tax expense
|
—
|
|
|
(10.9
|
)
|
|
382.3
|
|
|
407.1
|
|
|
705.7
|
|
|||||
Income tax expense (benefit)
|
(216.9
|
)
|
|
(19.8
|
)
|
|
84.5
|
|
|
97.7
|
|
|
183.7
|
|
|||||
Net income
|
216.9
|
|
|
8.9
|
|
|
297.8
|
|
|
309.4
|
|
|
522.0
|
|
|||||
Less: Net income (loss) attributable to noncontrolling interest
|
(17.5
|
)
|
|
(15.8
|
)
|
|
128.2
|
|
|
135.5
|
|
|
151.3
|
|
|||||
Net income attributable to CVR Energy stockholders
|
$
|
234.4
|
|
|
$
|
24.7
|
|
|
$
|
169.6
|
|
|
$
|
173.9
|
|
|
$
|
370.7
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic and Diluted earnings per share
|
$
|
2.70
|
|
|
$
|
0.28
|
|
|
$
|
1.95
|
|
|
$
|
2.00
|
|
|
$
|
4.27
|
|
Dividends declared per share
|
$
|
2.00
|
|
|
$
|
2.00
|
|
|
$
|
2.00
|
|
|
$
|
5.00
|
|
|
$
|
14.25
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic and Diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
481.8
|
|
|
$
|
735.8
|
|
|
$
|
765.1
|
|
|
$
|
753.7
|
|
|
$
|
842.1
|
|
Working capital
|
550.5
|
|
|
749.6
|
|
|
789.0
|
|
|
1,031.3
|
|
|
1,228.5
|
|
|||||
Total assets
|
3,806.7
|
|
|
4,050.2
|
|
|
3,299.4
|
|
|
3,454.3
|
|
|
3,655.9
|
|
|||||
Total debt, including current portion
|
1,166.5
|
|
|
1,164.6
|
|
|
667.1
|
|
|
666.7
|
|
|
666.3
|
|
|||||
Total CVR stockholders' equity
|
918.8
|
|
|
858.1
|
|
|
984.1
|
|
|
988.1
|
|
|
1,188.6
|
|
|||||
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
$
|
166.9
|
|
|
$
|
267.5
|
|
|
$
|
536.8
|
|
|
$
|
640.3
|
|
|
$
|
440.1
|
|
Investing activities
|
(195.0
|
)
|
|
(201.4
|
)
|
|
(150.6
|
)
|
|
(296.6
|
)
|
|
(250.3
|
)
|
|||||
Financing activities
|
(225.9
|
)
|
|
(95.4
|
)
|
|
(374.8
|
)
|
|
(432.1
|
)
|
|
(243.7
|
)
|
|||||
Net increase (decrease) in cash and cash equivalents
|
$
|
(254.0
|
)
|
|
$
|
(29.3
|
)
|
|
$
|
11.4
|
|
|
$
|
(88.4
|
)
|
|
$
|
(53.9
|
)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures for property, plant and equipment
|
$
|
118.6
|
|
|
$
|
132.7
|
|
|
$
|
218.7
|
|
|
$
|
218.4
|
|
|
$
|
256.5
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization.
|
•
|
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.
|
•
|
volatile margins in the refining industry and exposure to the risks associated with volatile crude oil prices;
|
•
|
the availability of adequate cash and other sources of liquidity for the capital needs of our businesses;
|
•
|
the ability to forecast future financial condition or results of operations and future revenues and expenses of our businesses;
|
•
|
the effects of transactions involving forward and derivative instruments;
|
•
|
disruption of the petroleum business' ability to obtain an adequate supply of crude oil;
|
•
|
changes in laws, regulations and policies with respect to the export of crude oil or other hydrocarbons;
|
•
|
interruption of the pipelines supplying feedstock and in the distribution of the petroleum business' products;
|
•
|
competition in the petroleum and nitrogen fertilizer businesses;
|
•
|
capital expenditures and potential liabilities arising from environmental laws and regulations;
|
•
|
changes in ours or the Refining Partnership's or Nitrogen Fertilizer Partnership's credit profile;
|
•
|
the cyclical nature of the nitrogen fertilizer business;
|
•
|
the seasonal nature of the petroleum business;
|
•
|
the supply and price levels of essential raw materials of our businesses;
|
•
|
the risk of a material decline in production at our refineries and nitrogen fertilizer 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.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
2015
|
||||||
|
|
(in millions)
|
||||||||||
Loss on extinguishment of debt(1)
|
|
$
|
—
|
|
|
$
|
4.9
|
|
|
$
|
—
|
|
Loss on derivatives, net
|
|
69.8
|
|
|
19.4
|
|
|
28.6
|
|
|||
Major scheduled turnaround expenses(2)
|
|
83.0
|
|
|
38.1
|
|
|
109.2
|
|
|||
Flood insurance recovery(3)
|
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
(1)
|
Represents a loss on extinguishment of debt incurred by CVR Partners in June 2016 in connection with the repurchase of senior notes assumed in the East Dubuque Merger, which includes a prepayment premium and write-off of 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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except per share data)
|
||||||||||
Consolidated Statements of Operations Data
|
|
|
|
|
|
||||||
Net sales
|
$
|
5,988.4
|
|
|
$
|
4,782.4
|
|
|
$
|
5,432.5
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of materials and other
|
4,882.9
|
|
|
3,847.5
|
|
|
4,190.4
|
|
|||
Direct operating expenses(1)
|
599.5
|
|
|
541.8
|
|
|
584.7
|
|
|||
Depreciation and amortization
|
203.3
|
|
|
184.5
|
|
|
156.4
|
|
|||
Cost of sales
|
5,685.7
|
|
|
4,573.8
|
|
|
4,931.5
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Selling, general and administrative expenses(1)
|
114.2
|
|
|
109.1
|
|
|
99.0
|
|
|||
Depreciation and amortization
|
10.7
|
|
|
8.6
|
|
|
7.7
|
|
|||
Operating income
|
177.8
|
|
|
90.9
|
|
|
421.6
|
|
|||
Interest expense and other financing costs
|
(110.1
|
)
|
|
(83.9
|
)
|
|
(48.4
|
)
|
|||
Interest income
|
1.1
|
|
|
0.7
|
|
|
1.0
|
|
|||
Loss on derivatives, net
|
(69.8
|
)
|
|
(19.4
|
)
|
|
(28.6
|
)
|
|||
Loss on extinguishment of debt
|
—
|
|
|
(4.9
|
)
|
|
—
|
|
|||
Other income, net
|
1.0
|
|
|
5.7
|
|
|
36.7
|
|
|||
Income (loss) before income tax expense
|
—
|
|
|
(10.9
|
)
|
|
382.3
|
|
|||
Income tax expense (benefit)
|
(216.9
|
)
|
|
(19.8
|
)
|
|
84.5
|
|
|||
Net income
|
216.9
|
|
|
8.9
|
|
|
297.8
|
|
|||
Less: Net income (loss) attributable to noncontrolling interest
|
(17.5
|
)
|
|
(15.8
|
)
|
|
128.2
|
|
|||
Net income attributable to CVR Energy stockholders
|
$
|
234.4
|
|
|
$
|
24.7
|
|
|
$
|
169.6
|
|
|
|
|
|
|
|
||||||
Basic and diluted earnings per share
|
$
|
2.70
|
|
|
$
|
0.28
|
|
|
$
|
1.95
|
|
Dividends declared per share
|
$
|
2.00
|
|
|
$
|
2.00
|
|
|
$
|
2.00
|
|
Adjusted EBITDA(2)
|
$
|
258.4
|
|
|
$
|
181.6
|
|
|
$
|
498.8
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
||||||
Basic and diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization.
|
(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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
|
(unaudited)
|
||||||||||
Net income attributable to CVR Energy stockholders
|
$
|
234.4
|
|
|
$
|
24.7
|
|
|
$
|
169.6
|
|
Add:
|
|
|
|
|
|
||||||
Interest expense and other financing costs, net of interest income
|
109.0
|
|
|
83.2
|
|
|
47.4
|
|
|||
Income tax expense (benefit)
|
(216.9
|
)
|
|
(19.8
|
)
|
|
84.5
|
|
|||
Depreciation and amortization
|
214.0
|
|
|
193.1
|
|
|
164.1
|
|
|||
Adjustments attributable to noncontrolling interest
|
(151.2
|
)
|
|
(127.3
|
)
|
|
(75.2
|
)
|
|||
EBITDA
|
189.3
|
|
|
153.9
|
|
|
390.4
|
|
|||
Add:
|
|
|
|
|
|
||||||
FIFO impact, (favorable) unfavorable
|
(29.6
|
)
|
|
(52.1
|
)
|
|
60.3
|
|
|||
Share-based compensation(a)
|
—
|
|
|
—
|
|
|
12.8
|
|
|||
Loss on extinguishment of debt(b)
|
—
|
|
|
4.9
|
|
|
—
|
|
|||
Major scheduled turnaround expenses
|
83.0
|
|
|
38.1
|
|
|
109.2
|
|
|||
Loss on derivatives, net
|
69.8
|
|
|
19.4
|
|
|
28.6
|
|
|||
Current period settlement on derivative contracts(c)
|
(16.6
|
)
|
|
36.4
|
|
|
(26.0
|
)
|
|||
Flood insurance recovery(d)
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Expenses associated with the East Dubuque Merger(e)
|
—
|
|
|
3.1
|
|
|
2.3
|
|
|||
Insurance recovery - business interruption(f)
|
(1.1
|
)
|
|
(2.1
|
)
|
|
—
|
|
|||
Adjustments attributable to noncontrolling interest
|
(36.4
|
)
|
|
(20.0
|
)
|
|
(51.5
|
)
|
|||
Adjusted EBITDA
|
$
|
258.4
|
|
|
$
|
181.6
|
|
|
$
|
498.8
|
|
(a)
|
Adjusted EBITDA for the year ended December 31,
2015
would have been $486.0 million without adjusting for share-based compensation expense of $12.8 million.
|
(b)
|
Represents a loss on extinguishment of debt incurred by CVR Partners in June 2016 in connection with the repurchase of senior notes assumed in the East Dubuque Merger, which includes a prepayment premium and write-off of the unamortized purchase accounting adjustment.
|
(c)
|
Represents the portion of (gain) loss 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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Consolidated Petroleum Business Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
5,664.2
|
|
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of materials and other
|
4,804.7
|
|
|
3,759.2
|
|
|
4,143.6
|
|
|||
Direct operating expenses(1)(2)
|
363.4
|
|
|
361.9
|
|
|
376.3
|
|
|||
Major scheduled turnaround expenses
|
80.4
|
|
|
31.5
|
|
|
102.2
|
|
|||
Depreciation and amortization
|
129.3
|
|
|
126.3
|
|
|
128.0
|
|
|||
Cost of sales
|
5,377.8
|
|
|
4,278.9
|
|
|
4,750.1
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Selling, general and administrative expenses(1)
|
78.8
|
|
|
71.9
|
|
|
75.2
|
|
|||
Depreciation and amortization
|
3.8
|
|
|
2.7
|
|
|
2.2
|
|
|||
Operating income
|
203.8
|
|
|
77.8
|
|
|
361.7
|
|
|||
Interest expense and other financing costs
|
(47.2
|
)
|
|
(43.4
|
)
|
|
(42.6
|
)
|
|||
Interest income
|
0.5
|
|
|
0.1
|
|
|
0.4
|
|
|||
Loss on derivatives, net
|
(69.8
|
)
|
|
(19.4
|
)
|
|
(28.6
|
)
|
|||
Other income, net
|
1.5
|
|
|
0.2
|
|
|
0.3
|
|
|||
Income before income tax expense
|
88.8
|
|
|
15.3
|
|
|
291.2
|
|
|||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income
|
$
|
88.8
|
|
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
|
|
|
|
|
||||||
Gross profit(3)
|
$
|
286.4
|
|
|
$
|
152.4
|
|
|
$
|
439.1
|
|
Refining margin(4)
|
$
|
859.5
|
|
|
$
|
672.1
|
|
|
$
|
1,018.3
|
|
Adjusted Petroleum EBITDA(5)
|
$
|
372.6
|
|
|
$
|
222.8
|
|
|
$
|
602.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(dollars per barrel)
|
||||||||||
Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Gross profit(3)
|
$
|
3.83
|
|
|
$
|
2.10
|
|
|
$
|
6.23
|
|
Refining margin(4)
|
11.50
|
|
|
9.27
|
|
|
14.45
|
|
|||
FIFO impact, (favorable) unfavorable
|
(0.40
|
)
|
|
(0.72
|
)
|
|
0.86
|
|
|||
Refining margin adjusted for FIFO impact(4)
|
11.10
|
|
|
8.55
|
|
|
15.31
|
|
|||
Direct operating expenses and major scheduled turnaround expenses(1)(2)
|
5.94
|
|
|
5.43
|
|
|
6.79
|
|
|||
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(6)
|
$
|
5.55
|
|
|
$
|
5.08
|
|
|
$
|
6.40
|
|
Barrels sold (barrels per day)(6)
|
218,912
|
|
|
211,643
|
|
|
204,708
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
||||||
Refining Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Sweet
|
194,613
|
|
|
89.8
|
|
177,256
|
|
|
84.8
|
|
176,097
|
|
|
86.0
|
|||
Medium
|
—
|
|
|
—
|
|
2,525
|
|
|
1.2
|
|
2,460
|
|
|
1.2
|
|||
Heavy sour
|
10,135
|
|
|
4.7
|
|
18,261
|
|
|
8.7
|
|
14,520
|
|
|
7.1
|
|||
Total crude oil throughput
|
204,748
|
|
|
94.5
|
|
198,042
|
|
|
94.7
|
|
193,077
|
|
|
94.3
|
|||
All other feedstocks and blendstocks
|
12,032
|
|
|
5.5
|
|
11,077
|
|
|
5.3
|
|
11,672
|
|
|
5.7
|
|||
Total throughput
|
216,780
|
|
|
100.0
|
|
209,119
|
|
|
100.0
|
|
204,749
|
|
|
100.0
|
|||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gasoline
|
110,226
|
|
|
50.7
|
|
108,762
|
|
|
51.9
|
|
99,961
|
|
|
48.5
|
|||
Distillate
|
90,409
|
|
|
41.6
|
|
85,092
|
|
|
40.6
|
|
85,953
|
|
|
41.7
|
|||
Other (excluding internally produced fuel)
|
16,818
|
|
|
7.7
|
|
15,751
|
|
|
7.5
|
|
20,074
|
|
|
9.8
|
|||
Total refining production (excluding internally produced fuel)
|
217,453
|
|
|
100.0
|
|
209,605
|
|
|
100.0
|
|
205,988
|
|
|
100.0
|
|||
Product price (dollars per gallon):
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gasoline
|
$
|
1.59
|
|
|
|
|
$
|
1.34
|
|
|
|
|
$
|
1.61
|
|
|
|
Distillate
|
1.66
|
|
|
|
|
1.36
|
|
|
|
|
1.62
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Market Indicators (dollars per barrel)
|
|
|
|
|
|
||||||
West Texas Intermediate (WTI) NYMEX
|
$
|
50.85
|
|
|
$
|
43.47
|
|
|
$
|
48.76
|
|
Crude Oil Differentials:
|
|
|
|
|
|
||||||
WTI less WTS (light/medium sour)
|
0.97
|
|
|
0.85
|
|
|
(0.28
|
)
|
|||
WTI less WCS (heavy sour)
|
12.69
|
|
|
13.95
|
|
|
13.20
|
|
|||
NYMEX Crack Spreads:
|
|
|
|
|
|
||||||
Gasoline
|
17.46
|
|
|
15.42
|
|
|
19.89
|
|
|||
Heating Oil
|
18.93
|
|
|
13.89
|
|
|
20.93
|
|
|||
NYMEX 2-1-1 Crack Spread
|
18.19
|
|
|
14.66
|
|
|
20.41
|
|
|||
PADD II Group 3 Product Basis:
|
|
|
|
|
|
||||||
Gasoline
|
(1.83
|
)
|
|
(3.62
|
)
|
|
(2.12
|
)
|
|||
Ultra-Low Sulfur Diesel
|
(0.50
|
)
|
|
(0.92
|
)
|
|
(2.02
|
)
|
|||
PADD II Group 3 Product Crack Spread:
|
|
|
|
|
|
||||||
Gasoline
|
15.63
|
|
|
11.82
|
|
|
17.76
|
|
|||
Ultra-Low Sulfur Diesel
|
18.42
|
|
|
12.96
|
|
|
18.91
|
|
|||
PADD II Group 3 2-1-1
|
17.03
|
|
|
12.39
|
|
|
18.34
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization.
|
(2)
|
Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.
|
(3)
|
Gross profit, 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.
|
(4)
|
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.
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Net sales
|
$
|
5,664.2
|
|
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
Cost of materials and other
|
4,804.7
|
|
|
3,759.2
|
|
|
4,143.6
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
363.4
|
|
|
361.9
|
|
|
376.3
|
|
|||
Major scheduled turnaround expenses
|
80.4
|
|
|
31.5
|
|
|
102.2
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Depreciation and amortization
|
129.3
|
|
|
126.3
|
|
|
128.0
|
|
|||
Gross profit
|
286.4
|
|
|
152.4
|
|
|
439.1
|
|
|||
Add:
|
|
|
|
|
|
||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
363.4
|
|
|
361.9
|
|
|
376.3
|
|
|||
Major scheduled turnaround expenses
|
80.4
|
|
|
31.5
|
|
|
102.2
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Depreciation and amortization
|
129.3
|
|
|
126.3
|
|
|
128.0
|
|
|||
Refining margin
|
859.5
|
|
|
672.1
|
|
|
1,018.3
|
|
|||
FIFO impact, (favorable) unfavorable
|
(29.6
|
)
|
|
(52.1
|
)
|
|
60.3
|
|
|||
Refining margin adjusted for FIFO impact
|
$
|
829.9
|
|
|
$
|
620.0
|
|
|
$
|
1,078.6
|
|
|
Year Ended
December 31, |
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Total crude oil throughput barrels per day
|
204,748
|
|
|
198,042
|
|
|
193,077
|
|
Days in the period
|
365
|
|
|
366
|
|
|
365
|
|
Total crude oil throughput barrels
|
74,733,020
|
|
|
72,483,372
|
|
|
70,473,105
|
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining margin
|
$
|
859.5
|
|
|
$
|
672.1
|
|
|
$
|
1,018.3
|
|
Divided by: crude oil throughput barrels
|
74.7
|
|
|
72.5
|
|
|
70.5
|
|
|||
Refining margin per crude oil throughput barrel
|
$
|
11.50
|
|
|
$
|
9.27
|
|
|
$
|
14.45
|
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining margin adjusted for FIFO impact
|
$
|
829.9
|
|
|
$
|
620.0
|
|
|
$
|
1,078.6
|
|
Divided by: crude oil throughput barrels
|
74.7
|
|
|
72.5
|
|
|
70.5
|
|
|||
Refining margin adjusted for FIFO impact per crude oil throughput barrel
|
$
|
11.10
|
|
|
$
|
8.55
|
|
|
$
|
15.31
|
|
(5)
|
Petroleum EBITDA represents net income for the petroleum segment before (i) interest expense and other financing costs, net of interest income; (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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Petroleum:
|
|
|
|
|
|
||||||
Petroleum net income
|
$
|
88.8
|
|
|
$
|
15.3
|
|
|
$
|
291.2
|
|
Add:
|
|
|
|
|
|
||||||
Interest expense and other financing costs, net of interest income
|
46.7
|
|
|
43.3
|
|
|
42.2
|
|
|||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|||
Depreciation and amortization
|
133.1
|
|
|
129.0
|
|
|
130.2
|
|
|||
Petroleum EBITDA
|
268.6
|
|
|
187.6
|
|
|
463.6
|
|
|||
Add:
|
|
|
|
|
|
||||||
FIFO impact, (favorable) unfavorable(a)
|
(29.6
|
)
|
|
(52.1
|
)
|
|
60.3
|
|
|||
Share-based compensation, non-cash
|
—
|
|
|
—
|
|
|
0.6
|
|
|||
Major scheduled turnaround expenses(b)
|
80.4
|
|
|
31.5
|
|
|
102.2
|
|
|||
Loss on derivatives, net
|
69.8
|
|
|
19.4
|
|
|
28.6
|
|
|||
Current period settlements on derivative contracts(c)
|
(16.6
|
)
|
|
36.4
|
|
|
(26.0
|
)
|
|||
Flood insurance recovery(d)
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Adjusted Petroleum EBITDA
|
$
|
372.6
|
|
|
$
|
222.8
|
|
|
$
|
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 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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Coffeyville Refinery Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
3,867.8
|
|
|
$
|
2,948.9
|
|
|
$
|
3,220.6
|
|
Cost of materials and other
|
3,285.8
|
|
|
2,513.9
|
|
|
2,626.1
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
209.5
|
|
|
196.4
|
|
|
209.1
|
|
|||
Major scheduled turnaround expenses
|
—
|
|
|
31.5
|
|
|
102.2
|
|
|||
Depreciation and amortization
|
71.5
|
|
|
69.7
|
|
|
72.1
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Gross profit
|
301.0
|
|
|
137.4
|
|
|
238.4
|
|
|||
Plus:
|
|
|
|
|
|
||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below)
|
209.5
|
|
|
227.9
|
|
|
311.3
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Depreciation and amortization
|
71.5
|
|
|
69.7
|
|
|
72.1
|
|
|||
Refining margin
|
582.0
|
|
|
435.0
|
|
|
594.5
|
|
|||
FIFO impact, (favorable) unfavorable
|
(20.2
|
)
|
|
(37.8
|
)
|
|
38.0
|
|
|||
Refining margin adjusted for FIFO impact
|
$
|
561.8
|
|
|
$
|
397.2
|
|
|
$
|
632.5
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(dollars per barrel)
|
||||||||||
Coffeyville Refinery Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Gross profit
|
$
|
6.27
|
|
|
$
|
3.03
|
|
|
$
|
5.77
|
|
Refining margin(1)
|
$
|
12.12
|
|
|
$
|
9.57
|
|
|
$
|
14.37
|
|
FIFO impact, (favorable) unfavorable
|
$
|
(0.42
|
)
|
|
$
|
(0.83
|
)
|
|
$
|
0.92
|
|
Refining margin adjusted for FIFO impact(1)
|
$
|
11.70
|
|
|
$
|
8.74
|
|
|
$
|
15.29
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
$
|
4.36
|
|
|
$
|
5.02
|
|
|
$
|
7.53
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold
|
$
|
4.00
|
|
|
$
|
4.54
|
|
|
$
|
6.92
|
|
Barrels sold (barrels per day)
|
143,598
|
|
|
137,047
|
|
|
123,279
|
|
|
Year Ended December 31,
|
|||||||||||||
|
2017
|
|
2016
|
|
2015
|
|||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
|||
Coffeyville Refinery Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Sweet
|
121,434
|
|
|
86.4
|
|
104,679
|
|
|
78.9
|
|
96,727
|
|
|
79.5
|
Medium
|
—
|
|
|
—
|
|
1,229
|
|
|
0.9
|
|
2,058
|
|
|
1.7
|
Heavy sour
|
10,135
|
|
|
7.2
|
|
18,261
|
|
|
13.8
|
|
14,520
|
|
|
11.9
|
Total crude oil throughput
|
131,569
|
|
|
93.6
|
|
124,169
|
|
|
93.6
|
|
113,305
|
|
|
93.1
|
All other feedstocks and blendstocks
|
9,058
|
|
|
6.4
|
|
8,453
|
|
|
6.4
|
|
8,400
|
|
|
6.9
|
Total throughput
|
140,627
|
|
|
100.0
|
|
132,622
|
|
|
100.0
|
|
121,705
|
|
|
100.0
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Gasoline
|
71,915
|
|
|
50.4
|
|
69,303
|
|
|
51.4
|
|
57,815
|
|
|
46.5
|
Distillate
|
59,593
|
|
|
41.7
|
|
55,790
|
|
|
41.4
|
|
53,136
|
|
|
42.7
|
Other (excluding internally produced fuel)
|
11,335
|
|
|
7.9
|
|
9,756
|
|
|
7.2
|
|
13,503
|
|
|
10.8
|
Total refining production (excluding internally produced fuel)
|
142,843
|
|
|
100.0
|
|
134,849
|
|
|
100.0
|
|
124,454
|
|
|
100.0
|
|
(1)
|
The calculation of refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel for the years ended
December 31, 2017
,
2016
and
2015
is as follows:
|
|
Year Ended
December 31, |
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Total crude oil throughput barrels per day
|
131,569
|
|
|
124,169
|
|
|
113,305
|
|
Days in the period
|
365
|
|
|
366
|
|
|
365
|
|
Total crude oil throughput barrels
|
48,022,685
|
|
|
45,445,854
|
|
|
41,356,325
|
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining margin
|
$
|
582.0
|
|
|
$
|
435.0
|
|
|
$
|
594.5
|
|
Divided by: crude oil throughput barrels
|
48.0
|
|
|
45.4
|
|
|
41.4
|
|
|||
Refining margin per crude oil throughput barrel
|
$
|
12.12
|
|
|
$
|
9.57
|
|
|
$
|
14.37
|
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining margin adjusted for FIFO impact
|
$
|
561.8
|
|
|
$
|
397.2
|
|
|
$
|
632.5
|
|
Divided by: crude oil throughput barrels
|
48.0
|
|
|
45.4
|
|
|
41.4
|
|
|||
Refining margin adjusted for FIFO impact per crude oil throughput barrel
|
$
|
11.70
|
|
|
$
|
8.74
|
|
|
$
|
15.29
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Wynnewood Refinery Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
1,792.1
|
|
|
$
|
1,478.0
|
|
|
$
|
1,936.9
|
|
Cost of materials and other
|
1,519.7
|
|
|
1,245.4
|
|
|
1,516.3
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
153.9
|
|
|
165.5
|
|
|
166.2
|
|
|||
Major scheduled turnaround expenses
|
80.4
|
|
|
—
|
|
|
—
|
|
|||
Depreciation and amortization
|
51.7
|
|
|
50.7
|
|
|
50.2
|
|
|||
Gross profit (loss)
|
(13.6
|
)
|
|
16.4
|
|
|
204.2
|
|
|||
Plus:
|
|
|
|
|
|
||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below)
|
234.3
|
|
|
165.5
|
|
|
166.2
|
|
|||
Depreciation and amortization
|
51.7
|
|
|
50.7
|
|
|
50.2
|
|
|||
Refining margin
|
272.4
|
|
|
232.6
|
|
|
420.6
|
|
|||
FIFO impact, (favorable) unfavorable
|
(9.4
|
)
|
|
(14.2
|
)
|
|
22.3
|
|
|||
Refining margin adjusted for FIFO impact
|
$
|
263.0
|
|
|
$
|
218.4
|
|
|
$
|
442.9
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(dollars per barrel)
|
||||||||||
Wynnewood Refinery Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Gross profit (loss)
|
$
|
(0.51
|
)
|
|
$
|
0.61
|
|
|
$
|
7.01
|
|
Refining margin(1)
|
$
|
10.20
|
|
|
$
|
8.60
|
|
|
$
|
14.44
|
|
FIFO impact, (favorable) unfavorable
|
$
|
(0.35
|
)
|
|
$
|
(0.53
|
)
|
|
$
|
0.77
|
|
Refining margin adjusted for FIFO impact(1)
|
$
|
9.85
|
|
|
$
|
8.07
|
|
|
$
|
15.21
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
$
|
8.77
|
|
|
$
|
6.12
|
|
|
$
|
5.71
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold
|
$
|
8.52
|
|
|
$
|
6.06
|
|
|
$
|
5.59
|
|
Barrels sold (barrels per day)
|
75,314
|
|
|
74,596
|
|
|
81,429
|
|
|
Year Ended December 31,
|
|||||||||||||
|
2017
|
|
2016
|
|
2015
|
|||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
|||
Wynnewood Refinery Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Sweet
|
73,179
|
|
|
96.1
|
|
72,577
|
|
|
94.9
|
|
79,370
|
|
|
95.6
|
Medium
|
—
|
|
|
—
|
|
1,296
|
|
|
1.7
|
|
402
|
|
|
0.5
|
Heavy sour
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
Total crude oil throughput
|
73,179
|
|
|
96.1
|
|
73,873
|
|
|
96.6
|
|
79,772
|
|
|
96.1
|
All other feedstocks and blendstocks
|
2,974
|
|
|
3.9
|
|
2,624
|
|
|
3.4
|
|
3,272
|
|
|
3.9
|
Total throughput
|
76,153
|
|
|
100.0
|
|
76,497
|
|
|
100.0
|
|
83,044
|
|
|
100.0
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Gasoline
|
38,311
|
|
|
51.3
|
|
39,459
|
|
|
52.8
|
|
42,146
|
|
|
51.7
|
Distillate
|
30,816
|
|
|
41.3
|
|
29,302
|
|
|
39.2
|
|
32,817
|
|
|
40.2
|
Other (excluding internally produced fuel)
|
5,483
|
|
|
7.4
|
|
5,995
|
|
|
8.0
|
|
6,571
|
|
|
8.1
|
Total refining production (excluding internally produced fuel)
|
74,610
|
|
|
100.0
|
|
74,756
|
|
|
100.0
|
|
81,534
|
|
|
100.0
|
|
(1)
|
The calculation of refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel for the years ended
December 31, 2017
,
2016
and
2015
is as follows:
|
|
Year Ended
December 31, |
|||||||
|
2017
|
|
2016
|
|
2015
|
|||
Total crude oil throughput barrels per day
|
73,179
|
|
|
73,873
|
|
|
79,772
|
|
Days in the period
|
365
|
|
|
366
|
|
|
365
|
|
Total crude oil throughput barrels
|
26,710,335
|
|
|
27,037,518
|
|
|
29,116,780
|
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining margin
|
$
|
272.4
|
|
|
$
|
232.6
|
|
|
$
|
420.6
|
|
Divided by: crude oil throughput barrels
|
26.7
|
|
|
27.0
|
|
|
29.1
|
|
|||
Refining margin per crude oil throughput barrel
|
$
|
10.20
|
|
|
$
|
8.60
|
|
|
$
|
14.44
|
|
|
Year Ended
December 31, |
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining margin adjusted for FIFO impact
|
$
|
263.0
|
|
|
$
|
218.4
|
|
|
$
|
442.9
|
|
Divided by: crude oil throughput barrels
|
26.7
|
|
|
27.0
|
|
|
29.1
|
|
|||
Refining margin adjusted for FIFO impact per crude oil throughput barrel
|
$
|
9.85
|
|
|
$
|
8.07
|
|
|
$
|
15.21
|
|
|
Year Ended December 31, 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
|
44.3
|
|
|
$
|
66.90
|
|
|
$
|
2,966.8
|
|
|
42.6
|
|
|
$
|
56.16
|
|
|
$
|
2,390.8
|
|
|
1.7
|
|
|
$
|
576.0
|
|
|
$
|
476.3
|
|
|
$
|
99.7
|
|
Distillate
|
34.4
|
|
|
$
|
69.71
|
|
|
$
|
2,399.8
|
|
|
32.4
|
|
|
$
|
56.99
|
|
|
$
|
1,844.3
|
|
|
2.0
|
|
|
$
|
555.5
|
|
|
$
|
438.0
|
|
|
$
|
117.5
|
|
(1)
|
Barrels in millions
|
(2)
|
Sales dollars in millions
|
|
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
|
42.6
|
|
|
$
|
56.16
|
|
|
$
|
2,390.8
|
|
|
40.1
|
|
|
$
|
67.52
|
|
|
$
|
2,708.4
|
|
|
2.5
|
|
|
$
|
(317.6
|
)
|
|
$
|
(483.2
|
)
|
|
$
|
165.6
|
|
Distillate
|
32.4
|
|
|
$
|
56.99
|
|
|
$
|
1,844.3
|
|
|
33.1
|
|
|
$
|
68.01
|
|
|
$
|
2,248.2
|
|
|
(0.7
|
)
|
|
$
|
(403.9
|
)
|
|
$
|
(356.8
|
)
|
|
$
|
(47.1
|
)
|
(1)
|
Barrels in millions
|
(2)
|
Sales dollars in millions
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Nitrogen Fertilizer Business Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
330.8
|
|
|
$
|
356.3
|
|
|
$
|
289.2
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of materials and other
|
84.9
|
|
|
93.7
|
|
|
65.2
|
|
|||
Direct operating expenses(1)
|
152.9
|
|
|
141.7
|
|
|
99.1
|
|
|||
Major scheduled turnaround expenses
|
2.6
|
|
|
6.6
|
|
|
7.0
|
|
|||
Depreciation and amortization
|
74.0
|
|
|
58.2
|
|
|
28.4
|
|
|||
Cost of sales
|
314.4
|
|
|
300.2
|
|
|
199.7
|
|
|||
Selling, general and administrative
|
25.6
|
|
|
29.3
|
|
|
20.8
|
|
|||
Operating income (loss)
|
(9.2
|
)
|
|
26.8
|
|
|
68.7
|
|
|||
Interest expense and other financing costs
|
(62.9
|
)
|
|
(48.6
|
)
|
|
(7.0
|
)
|
|||
Loss on extinguishment of debt
|
—
|
|
|
(4.9
|
)
|
|
—
|
|
|||
Other income (loss), net
|
(0.5
|
)
|
|
0.1
|
|
|
0.3
|
|
|||
Income (loss) before income tax expense
|
(72.6
|
)
|
|
(26.6
|
)
|
|
62.0
|
|
|||
Income tax expense
|
0.2
|
|
|
0.3
|
|
|
—
|
|
|||
Net income (loss)
|
$
|
(72.8
|
)
|
|
$
|
(26.9
|
)
|
|
$
|
62.0
|
|
|
|
|
|
|
|
||||||
Adjusted Nitrogen Fertilizer EBITDA(2)
|
$
|
65.8
|
|
|
$
|
92.7
|
|
|
$
|
106.8
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Key Operating Statistics
|
|
|
|
|
|
||||||
Sales (thousand tons):
|
|
|
|
|
|
||||||
Ammonia
|
286.1
|
|
|
201.4
|
|
|
32.3
|
|
|||
UAN
|
1,254.5
|
|
|
1,237.5
|
|
|
939.5
|
|
|||
Product pricing at gate (dollars per ton)(3):
|
|
|
|
|
|
||||||
Ammonia
|
$
|
280
|
|
|
$
|
376
|
|
|
$
|
521
|
|
UAN
|
$
|
152
|
|
|
$
|
177
|
|
|
$
|
247
|
|
Production volume (thousand tons):
|
|
|
|
|
|
||||||
Ammonia (gross produced)(4)
|
814.7
|
|
|
693.5
|
|
|
385.4
|
|
|||
Ammonia (net available for sale)(4)
|
267.8
|
|
|
183.6
|
|
|
37.3
|
|
|||
UAN
|
1,268.4
|
|
|
1,192.6
|
|
|
928.6
|
|
|||
Feedstock:
|
|
|
|
|
|
||||||
Petroleum coke used in production (thousand tons)
|
487.5
|
|
|
513.7
|
|
|
469.9
|
|
|||
Petroleum coke (dollars per ton)
|
$
|
17
|
|
|
$
|
15
|
|
|
$
|
25
|
|
Natural gas used in production (thousands of MMBtu)(5)
|
7,619.5
|
|
|
5,596.0
|
|
|
—
|
|
|||
Natural gas used in production (dollars per MMBtu)(5)(6)
|
$
|
3.24
|
|
|
$
|
2.96
|
|
|
$
|
—
|
|
Natural gas cost of materials and other (thousands of MMBtu)(5)
|
8,051.5
|
|
|
4,618.7
|
|
|
—
|
|
|||
Natural gas cost of materials and other (dollars per MMBtu)(5)(6)
|
$
|
3.26
|
|
|
$
|
2.87
|
|
|
$
|
—
|
|
Coffeyville Facility on-stream factors(7):
|
|
|
|
|
|
||||||
Gasification
|
98.5
|
%
|
|
96.9
|
%
|
|
90.2
|
%
|
|||
Ammonia
|
97.4
|
%
|
|
94.9
|
%
|
|
87.5
|
%
|
|||
UAN
|
91.7
|
%
|
|
93.1
|
%
|
|
87.3
|
%
|
|||
East Dubuque Facility on-stream factors (7):
|
|
|
|
|
|
||||||
Ammonia
|
90.4
|
%
|
|
87.7
|
%
|
|
—
|
%
|
|||
UAN
|
90.3
|
%
|
|
87.3
|
%
|
|
—
|
%
|
|||
|
|
|
|
|
|
||||||
Reconciliation to net sales (dollars in millions):
|
|
|
|
|
|
||||||
Sales net at gate
|
$
|
290.0
|
|
|
$
|
309.0
|
|
|
$
|
248.8
|
|
Freight in revenue
|
32.8
|
|
|
33.0
|
|
|
27.2
|
|
|||
Hydrogen revenue
|
0.4
|
|
|
3.2
|
|
|
11.8
|
|
|||
Other revenue
|
7.6
|
|
|
11.1
|
|
|
1.4
|
|
|||
Total net sales
|
$
|
330.8
|
|
|
$
|
356.3
|
|
|
$
|
289.2
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Market Indicators
|
|
|
|
|
|
||||||
Ammonia — Southern Plains (dollars per ton)
|
$
|
314
|
|
|
$
|
356
|
|
|
$
|
510
|
|
Ammonia — Corn belt (dollars per ton)
|
$
|
358
|
|
|
$
|
416
|
|
|
$
|
566
|
|
UAN — Corn belt (dollars per ton)
|
$
|
192
|
|
|
$
|
208
|
|
|
$
|
284
|
|
Natural gas NYMEX (dollars per MMBtu)
|
$
|
3.02
|
|
|
$
|
2.55
|
|
|
$
|
2.63
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization 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.
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Nitrogen Fertilizer:
|
|
|
|
|
|
||||||
Nitrogen Fertilizer net income (loss)
|
$
|
(72.8
|
)
|
|
$
|
(26.9
|
)
|
|
$
|
62.0
|
|
Add:
|
|
|
|
|
|
||||||
Interest expense and other financing costs, net
|
62.9
|
|
|
48.6
|
|
|
7.0
|
|
|||
Income tax expense
|
0.2
|
|
|
0.3
|
|
|
—
|
|
|||
Depreciation and amortization
|
74.0
|
|
|
58.2
|
|
|
28.4
|
|
|||
Nitrogen Fertilizer EBITDA
|
64.3
|
|
|
80.2
|
|
|
97.4
|
|
|||
Add:
|
|
|
|
|
|
||||||
Major scheduled turnaround expenses
|
2.6
|
|
|
6.6
|
|
|
7.0
|
|
|||
Share-based compensation, non-cash
|
—
|
|
|
—
|
|
|
0.1
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
4.9
|
|
|
—
|
|
|||
Expenses associated with the East Dubuque Merger
|
—
|
|
|
3.1
|
|
|
2.3
|
|
|||
Less:
|
|
|
|
|
|
||||||
Insurance recovery - business interruption
|
(1.1
|
)
|
|
(2.1
|
)
|
|
—
|
|
|||
Adjusted Nitrogen Fertilizer EBITDA
|
$
|
65.8
|
|
|
$
|
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.
|
(4)
|
Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into other fertilizer products. Net tons available for sale represent the ammonia available for sale that was not upgraded into other fertilizer products.
|
(5)
|
The feedstock natural gas shown above does not include natural gas used for fuel. The cost of fuel natural gas is included in direct operating expense (exclusive of depreciation and amortization).
|
(6)
|
The cost per MMBtu excludes derivative activity, when applicable. The impact of natural gas derivative activity was not material for the periods presented.
|
(7)
|
On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is a measure of operating efficiency.
|
|
|
|
|
||||
|
Price
Variance
|
|
Volume
Variance
|
||||
|
(in millions)
|
||||||
UAN
|
$
|
(24.0
|
)
|
|
$
|
(7.2
|
)
|
Ammonia
|
$
|
(4.5
|
)
|
|
$
|
6.5
|
|
Hydrogen
|
$
|
(0.2
|
)
|
|
$
|
(2.6
|
)
|
|
|
|
|
||||
|
Price
Variance |
|
Volume
Variance |
||||
|
(in millions)
|
||||||
UAN
|
$
|
(69.8
|
)
|
|
$
|
16.8
|
|
Ammonia
|
$
|
(7.6
|
)
|
|
$
|
6.8
|
|
Hydrogen
|
$
|
(1.8
|
)
|
|
$
|
(6.8
|
)
|
|
Year Ended December 31,
|
||||||
|
2017 Actual
|
|
2018 Estimate
|
||||
|
(in millions)
|
||||||
|
(unaudited)
|
||||||
Petroleum Business (the Refining Partnership):
|
|
|
|
||||
Coffeyville refinery:
|
|
|
|
||||
Maintenance
|
$
|
36.9
|
|
|
$
|
75.0
|
|
Growth
|
3.0
|
|
|
10.0
|
|
||
Coffeyville refinery total capital spending
|
39.9
|
|
|
85.0
|
|
||
Wynnewood refinery:
|
|
|
|
||||
Maintenance
|
38.1
|
|
|
65.0
|
|
||
Growth
|
4.0
|
|
|
25.0
|
|
||
Wynnewood refinery total capital spending
|
42.1
|
|
|
90.0
|
|
||
Other Petroleum
:
|
|
|
|
||||
Maintenance
|
2.7
|
|
|
15.0
|
|
||
Growth
|
15.0
|
|
|
10.0
|
|
||
Other petroleum total capital spending
|
17.7
|
|
|
25.0
|
|
||
Petroleum business total capital spending
|
99.7
|
|
|
200.0
|
|
||
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
|
|
|
|
||||
Maintenance
|
14.1
|
|
|
18.0
|
|
||
Growth
|
0.4
|
|
|
3.0
|
|
||
Nitrogen fertilizer business total capital spending
|
14.5
|
|
|
21.0
|
|
||
Corporate
|
4.4
|
|
|
10.0
|
|
||
Total capital spending
|
$
|
118.6
|
|
|
$
|
231.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
$
|
166.9
|
|
|
$
|
267.5
|
|
|
$
|
536.8
|
|
Investing activities (1)
|
(195.0
|
)
|
|
(201.4
|
)
|
|
(150.6
|
)
|
|||
Financing activities
|
(225.9
|
)
|
|
(95.4
|
)
|
|
(374.8
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
$
|
(254.0
|
)
|
|
$
|
(29.3
|
)
|
|
$
|
11.4
|
|
|
(1)
|
Investing activities for the year ended December 31, 2017 includes the acquisition of the Cushing to Ellis crude oil pipeline system totaling
$15.0
million and equity method investments in the Midway joint venture of
$76.0
million.
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
2022
|
|
Thereafter
|
||||||||||||||
|
(in millions)
|
||||||||||||||||||||||||||
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Long-term debt(1)
|
$
|
1,147.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.2
|
|
|
$
|
500.0
|
|
|
$
|
645.0
|
|
Operating leases(2)
|
32.3
|
|
|
7.4
|
|
|
6.5
|
|
|
5.9
|
|
|
5.3
|
|
|
4.8
|
|
|
2.4
|
|
|||||||
Capital lease obligations(3)
|
45.0
|
|
|
2.1
|
|
|
2.3
|
|
|
2.6
|
|
|
2.9
|
|
|
3.1
|
|
|
32.0
|
|
|||||||
Unconditional purchase obligations(4)
|
1,107.1
|
|
|
165.0
|
|
|
124.3
|
|
|
100.6
|
|
|
89.8
|
|
|
84.7
|
|
|
542.7
|
|
|||||||
Environmental liabilities(5)
|
4.0
|
|
|
2.9
|
|
|
1.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||||
Interest payments(6)
|
518.3
|
|
|
96.9
|
|
|
96.7
|
|
|
96.4
|
|
|
96.1
|
|
|
90.2
|
|
|
42.0
|
|
|||||||
Total
|
$
|
2,853.9
|
|
|
$
|
274.3
|
|
|
$
|
230.9
|
|
|
$
|
205.5
|
|
|
$
|
196.3
|
|
|
$
|
682.8
|
|
|
$
|
1,264.1
|
|
Other Commercial Commitments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Standby letters of credit(7)
|
$
|
28.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Consists of the 2021 Notes, the 2022 Notes and the 2023 Notes as of
December 31, 2017
.
|
(2)
|
The Refining Partnership and the Nitrogen Fertilizer Partnership lease various facilities and equipment, including railcars and real property, under operating leases for various periods. See Note 18 ("Related Party Transactions") to Part II, Item 8 of this Report for a discussion of our railcar leases with affiliates.
|
(3)
|
The amount includes commitments under capital lease arrangements for two leases associated with pipelines and storage and terminal equipment at the Wynnewood refinery.
|
(4)
|
The amount includes (a) commitments under several agreements for the petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an 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.
|
(5)
|
Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and Wynnewood, Oklahoma. We also are required to make payments with respect to other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See Item 1."Business — Environmental Matters."
|
(6)
|
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.
|
(7)
|
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.
|
•
|
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.
|
Audited Financial Statements:
|
Page
Number
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions, except share data)
|
||||||
ASSETS
|
|||||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents (including $223.0 and $369.7, respectively, of consolidated variable interest entities ("VIEs"))
|
$
|
481.8
|
|
|
$
|
735.8
|
|
Accounts receivable of VIEs, net of allowance for doubtful accounts of $1.1 and $0.5, respectively
|
178.7
|
|
|
151.9
|
|
||
Inventories of VIEs
|
385.2
|
|
|
349.2
|
|
||
Prepaid expenses and other current assets (including $30.0 and $65.0, respectively, of VIEs)
|
33.7
|
|
|
68.4
|
|
||
Income tax receivable (including $0.0 and $0.2, respectively, of VIEs)
|
9.7
|
|
|
10.2
|
|
||
Due from parent
|
5.1
|
|
|
—
|
|
||
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
|
0.2
|
|
|
0.2
|
|
||
Goodwill of VIEs
|
41.0
|
|
|
41.0
|
|
||
Equity method investments in affiliates of VIEs
|
82.8
|
|
|
5.6
|
|
||
Other long-term assets (including $13.3 and $19.1, respectively, of VIEs)
|
16.7
|
|
|
15.8
|
|
||
Total assets
|
$
|
3,806.7
|
|
|
$
|
4,050.2
|
|
LIABILITIES AND EQUITY
|
|||||||
Current liabilities:
|
|
|
|
||||
Note payable and capital lease obligations of VIEs
|
$
|
2.1
|
|
|
$
|
1.8
|
|
Accounts payable (including $329.0 and $247.7, respectively, of VIEs)
|
333.9
|
|
|
251.0
|
|
||
Personnel accruals (including $29.9 and $23.6, respectively, of VIEs)
|
55.9
|
|
|
45.7
|
|
||
Accrued taxes other than income taxes of VIEs
|
26.5
|
|
|
27.0
|
|
||
Deferred revenue of VIEs
|
12.9
|
|
|
12.6
|
|
||
Due to parent
|
—
|
|
|
10.6
|
|
||
Other current liabilities (including $111.8 and $216.8, respectively, of VIEs)
|
112.4
|
|
|
217.2
|
|
||
Total current liabilities
|
543.7
|
|
|
565.9
|
|
||
Long-term liabilities:
|
|
|
|
||||
Long-term debt and capital lease obligations of VIEs, net of current portion
|
1,164.4
|
|
|
1,162.8
|
|
||
Deferred income taxes (including $1.0 and $0.8, respectively, of VIEs)
|
385.9
|
|
|
579.9
|
|
||
Other long-term liabilities (including $3.7 and $5.4, respectively, of VIEs)
|
8.7
|
|
|
32.0
|
|
||
Total long-term liabilities
|
1,559.0
|
|
|
1,774.7
|
|
||
Commitments and contingencies
|
|
|
|
||||
Equity:
|
|
|
|
||||
CVR stockholders' equity:
|
|
|
|
||||
Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 shares issued
|
0.9
|
|
|
0.9
|
|
||
Additional paid-in-capital
|
1,197.6
|
|
|
1,197.6
|
|
||
Retained deficit
|
(277.4
|
)
|
|
(338.1
|
)
|
||
Treasury stock, 98,610 shares at cost
|
(2.3
|
)
|
|
(2.3
|
)
|
||
Accumulated other comprehensive loss, net of tax
|
—
|
|
|
—
|
|
||
Total CVR stockholders' equity
|
918.8
|
|
|
858.1
|
|
||
Noncontrolling interest
|
785.2
|
|
|
851.5
|
|
||
Total equity
|
1,704.0
|
|
|
1,709.6
|
|
||
Total liabilities and equity
|
$
|
3,806.7
|
|
|
$
|
4,050.2
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except per share data)
|
||||||||||
Net sales
|
$
|
5,988.4
|
|
|
$
|
4,782.4
|
|
|
$
|
5,432.5
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of materials and other
|
4,882.9
|
|
|
3,847.5
|
|
|
4,190.4
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
599.5
|
|
|
541.8
|
|
|
584.7
|
|
|||
Depreciation and amortization
|
203.3
|
|
|
184.5
|
|
|
156.4
|
|
|||
Cost of sales
|
5,685.7
|
|
|
4,573.8
|
|
|
4,931.5
|
|
|||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|||
Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below)
|
114.2
|
|
|
109.1
|
|
|
99.0
|
|
|||
Depreciation and amortization
|
10.7
|
|
|
8.6
|
|
|
7.7
|
|
|||
Total operating costs and expenses
|
5,810.6
|
|
|
4,691.5
|
|
|
5,010.9
|
|
|||
Operating income
|
177.8
|
|
|
90.9
|
|
|
421.6
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense and other financing costs
|
(110.1
|
)
|
|
(83.9
|
)
|
|
(48.4
|
)
|
|||
Interest income
|
1.1
|
|
|
0.7
|
|
|
1.0
|
|
|||
Loss on derivatives, net
|
(69.8
|
)
|
|
(19.4
|
)
|
|
(28.6
|
)
|
|||
Loss on extinguishment of debt
|
—
|
|
|
(4.9
|
)
|
|
—
|
|
|||
Other income, net
|
1.0
|
|
|
5.7
|
|
|
36.7
|
|
|||
Total other expense
|
(177.8
|
)
|
|
(101.8
|
)
|
|
(39.3
|
)
|
|||
Income (loss) before income taxes
|
0.0
|
|
|
(10.9
|
)
|
|
382.3
|
|
|||
Income tax expense (benefit)
|
(216.9
|
)
|
|
(19.8
|
)
|
|
84.5
|
|
|||
Net income
|
216.9
|
|
|
8.9
|
|
|
297.8
|
|
|||
Less: Net income (loss) attributable to noncontrolling interest
|
(17.5
|
)
|
|
(15.8
|
)
|
|
128.2
|
|
|||
Net income attributable to CVR Energy stockholders
|
$
|
234.4
|
|
|
$
|
24.7
|
|
|
$
|
169.6
|
|
|
|
|
|
|
|
||||||
Basic and diluted earnings per share
|
$
|
2.70
|
|
|
$
|
0.28
|
|
|
$
|
1.95
|
|
Dividends declared per share
|
$
|
2.00
|
|
|
$
|
2.00
|
|
|
$
|
2.00
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
||||||
Basic and Diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Net income
|
$
|
216.9
|
|
|
$
|
8.9
|
|
|
$
|
297.8
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
||||||
Unrealized gain on available-for-sale securities, net of tax of $0.0, $0.2 and $12.6, respectively
|
—
|
|
|
0.3
|
|
|
19.2
|
|
|||
Net gain reclassified into income on sale of available-for-sale-securities, net of tax of $0.0, $(0.2), and $(8.0), respectively (Note 15)
|
—
|
|
|
(0.3
|
)
|
|
(12.1
|
)
|
|||
Net gain reclassified into income on reclassification of available-for-sale securities to trading securities, net of tax of $0.0, $0.0, and $(4.6), respectively (Note 15)
|
—
|
|
|
—
|
|
|
(7.1
|
)
|
|||
Change in fair value of interest rate swaps, net of tax of $0.0, $0.0 and $0.0, respectively
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|||
Net loss reclassified into income on settlement of interest rate swaps, net of tax of $0.0, $0.0, and $0.2, respectively (Note 16)
|
—
|
|
|
—
|
|
|
0.8
|
|
|||
Total other comprehensive income
|
—
|
|
|
—
|
|
|
0.7
|
|
|||
Comprehensive income
|
216.9
|
|
|
8.9
|
|
|
298.5
|
|
|||
Less: Comprehensive income (loss) attributable to noncontrolling interest
|
(17.5
|
)
|
|
(15.8
|
)
|
|
128.6
|
|
|||
Comprehensive income attributable to CVR Energy stockholders
|
$
|
234.4
|
|
|
$
|
24.7
|
|
|
$
|
169.9
|
|
|
Common Stockholders
|
|
|
|
|
|||||||||||||||||||||||||||||
|
Shares
Issued
|
|
$0.01 Par
Value
Common
Stock
|
|
Additional
Paid-In
Capital
|
|
Retained
Earnings (Deficit)
|
|
Treasury
Stock
|
|
Accumulated
Other
Comprehensive
Income (Loss)
|
|
Total CVR
Stockholders'
Equity
|
|
Noncontrolling
Interest
|
|
Total
Equity
|
|||||||||||||||||
|
(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
|
—
|
|
|
—
|
|
|
—
|
|
|
(173.7
|
)
|
|
—
|
|
|
—
|
|
|
(173.7
|
)
|
|
—
|
|
|
(173.7
|
)
|
||||||||
Distributions from CVR Partners to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(42.8
|
)
|
|
(42.8
|
)
|
||||||||
Distributions from CVR Refining to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(156.9
|
)
|
|
(156.9
|
)
|
||||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
0.1
|
|
|
(0.2
|
)
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
0.3
|
|
|
0.2
|
|
||||||||
Excess tax deficiency from share-based compensation
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
(0.1
|
)
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
169.6
|
|
|
—
|
|
|
—
|
|
|
169.6
|
|
|
128.2
|
|
|
297.8
|
|
||||||||
Other comprehensive income, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
0.3
|
|
|
0.4
|
|
|
0.7
|
|
||||||||
Balance at December 31, 2015
|
86,929,660
|
|
|
0.9
|
|
|
1,174.7
|
|
|
(189.2
|
)
|
|
(2.3
|
)
|
|
—
|
|
|
984.1
|
|
|
616.4
|
|
|
1,600.5
|
|
||||||||
Dividends paid to CVR Energy stockholders
|
—
|
|
|
—
|
|
|
—
|
|
|
(173.6
|
)
|
|
—
|
|
|
—
|
|
|
(173.6
|
)
|
|
—
|
|
|
(173.6
|
)
|
||||||||
Distributions from CVR Partners to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(41.9
|
)
|
|
(41.9
|
)
|
||||||||
Impact of CVR Partners' common units issuance for the East Dubuque Merger, net of tax of $20.0
|
—
|
|
|
—
|
|
|
22.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22.9
|
|
|
292.8
|
|
|
315.7
|
|
||||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
24.7
|
|
|
—
|
|
|
—
|
|
|
24.7
|
|
|
(15.8
|
)
|
|
8.9
|
|
||||||||
Balance at December 31, 2016
|
86,929,660
|
|
|
0.9
|
|
|
1,197.6
|
|
|
(338.1
|
)
|
|
(2.3
|
)
|
|
—
|
|
|
858.1
|
|
|
851.5
|
|
|
1,709.6
|
|
||||||||
Dividends paid to CVR Energy stockholders
|
—
|
|
|
—
|
|
|
—
|
|
|
(173.7
|
)
|
|
—
|
|
|
—
|
|
|
(173.7
|
)
|
|
—
|
|
|
(173.7
|
)
|
||||||||
Distributions from CVR Partners to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.5
|
)
|
|
(1.5
|
)
|
||||||||
Distributions from CVR Refining to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(47.3
|
)
|
|
(47.3
|
)
|
||||||||
Net income (loss)
|
—
|
|
|
—
|
|
|
—
|
|
|
234.4
|
|
|
—
|
|
|
—
|
|
|
234.4
|
|
|
(17.5
|
)
|
|
216.9
|
|
||||||||
Balance at December 31, 2017
|
86,929,660
|
|
|
$
|
0.9
|
|
|
$
|
1,197.6
|
|
|
$
|
(277.4
|
)
|
|
$
|
(2.3
|
)
|
|
$
|
—
|
|
|
$
|
918.8
|
|
|
$
|
785.2
|
|
|
$
|
1,704.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
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
|
214.0
|
|
|
193.1
|
|
|
164.1
|
|
|||
Allowance for doubtful accounts
|
0.6
|
|
|
0.2
|
|
|
(0.1
|
)
|
|||
Amortization of deferred financing costs and original issue discount
|
4.8
|
|
|
3.6
|
|
|
2.8
|
|
|||
Amortization of debt fair value adjustment
|
—
|
|
|
1.2
|
|
|
—
|
|
|||
Deferred income taxes
|
(216.5
|
)
|
|
(84.4
|
)
|
|
(10.4
|
)
|
|||
Excess income tax deficiency of share-based compensation
|
—
|
|
|
—
|
|
|
0.1
|
|
|||
Loss on disposition of assets
|
2.4
|
|
|
0.5
|
|
|
1.8
|
|
|||
Loss on extinguishment of debt
|
—
|
|
|
4.9
|
|
|
—
|
|
|||
Share-based compensation
|
18.8
|
|
|
9.3
|
|
|
12.8
|
|
|||
Gain on sale of available-for-sale securities
|
—
|
|
|
(4.9
|
)
|
|
(20.1
|
)
|
|||
Unrealized gain on securities
|
—
|
|
|
(0.3
|
)
|
|
—
|
|
|||
Loss on derivatives, net
|
69.8
|
|
|
19.4
|
|
|
28.6
|
|
|||
Current period settlements on derivative contracts
|
(16.6
|
)
|
|
36.4
|
|
|
(26.0
|
)
|
|||
Income from equity method investments, net of distributions
|
(0.7
|
)
|
|
—
|
|
|
—
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(27.3
|
)
|
|
(47.5
|
)
|
|
41.0
|
|
|||
Inventories
|
(37.6
|
)
|
|
(7.3
|
)
|
|
39.7
|
|
|||
Prepaid expenses and other current assets
|
33.9
|
|
|
(3.4
|
)
|
|
40.4
|
|
|||
Due to (from) parent
|
(15.7
|
)
|
|
22.2
|
|
|
32.8
|
|
|||
Other long-term assets
|
1.0
|
|
|
(0.6
|
)
|
|
3.8
|
|
|||
Accounts payable
|
88.1
|
|
|
(10.4
|
)
|
|
(14.3
|
)
|
|||
Accrued income taxes
|
0.6
|
|
|
(3.3
|
)
|
|
4.2
|
|
|||
Deferred revenue
|
0.9
|
|
|
(20.4
|
)
|
|
(10.5
|
)
|
|||
Other current liabilities
|
(168.0
|
)
|
|
151.2
|
|
|
(52.1
|
)
|
|||
Other long-term liabilities
|
(2.5
|
)
|
|
(0.9
|
)
|
|
0.4
|
|
|||
Net cash provided by operating activities
|
166.9
|
|
|
267.5
|
|
|
536.8
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(118.6
|
)
|
|
(132.7
|
)
|
|
(218.7
|
)
|
|||
Proceeds from sale of assets
|
0.1
|
|
|
—
|
|
|
0.1
|
|
|||
Acquisition of CVR Nitrogen, net of cash acquired
|
—
|
|
|
(63.8
|
)
|
|
—
|
|
|||
Purchase of securities
|
—
|
|
|
(4.2
|
)
|
|
—
|
|
|||
Investment in affiliates, net of return of investment
|
(76.5
|
)
|
|
(5.6
|
)
|
|
—
|
|
|||
Purchase of available-for-sale securities
|
—
|
|
|
(14.4
|
)
|
|
—
|
|
|||
Proceeds from sale of available-for-sale securities
|
—
|
|
|
19.3
|
|
|
68.0
|
|
|||
Net cash used in investing activities
|
(195.0
|
)
|
|
(201.4
|
)
|
|
(150.6
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds on issuance of 2023 Notes, net of original issue discount
|
—
|
|
|
628.8
|
|
|
—
|
|
|||
Principal and premium payments on 2021 Notes
|
—
|
|
|
(322.2
|
)
|
|
—
|
|
|||
Payments of revolving debt
|
—
|
|
|
(49.1
|
)
|
|
—
|
|
|||
Principal payments on CRNF credit facility
|
—
|
|
|
(125.0
|
)
|
|
—
|
|
|||
Payment of capital lease obligations
|
(1.8
|
)
|
|
(1.7
|
)
|
|
(1.3
|
)
|
|||
Payment of deferred financing costs
|
(1.6
|
)
|
|
(10.7
|
)
|
|
—
|
|
|||
Dividends to CVR Energy's stockholders
|
(173.7
|
)
|
|
(173.6
|
)
|
|
(173.7
|
)
|
|||
Distributions to CVR Refining's noncontrolling interest holders
|
$
|
(47.3
|
)
|
|
$
|
—
|
|
|
$
|
(156.9
|
)
|
Distributions to CVR Partners' noncontrolling interest holders
|
$
|
(1.5
|
)
|
|
$
|
(41.9
|
)
|
|
$
|
(42.8
|
)
|
Excess income tax deficiency of share-based compensation
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|||
Net cash used in financing activities
|
(225.9
|
)
|
|
(95.4
|
)
|
|
(374.8
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
(254.0
|
)
|
|
(29.3
|
)
|
|
11.4
|
|
|||
Cash and cash equivalents, beginning of period
|
735.8
|
|
|
765.1
|
|
|
753.7
|
|
|||
Cash and cash equivalents, end of period
|
$
|
481.8
|
|
|
$
|
735.8
|
|
|
$
|
765.1
|
|
Supplemental disclosures:
|
|
|
|
|
|
||||||
Cash paid for income taxes, net of refunds
|
$
|
14.9
|
|
|
$
|
45.5
|
|
|
$
|
57.9
|
|
Cash paid for interest net of capitalized interest of $1.1, $5.4, and $3.7 for the years ended December 31, 2017, 2016 and 2015, respectively
|
$
|
105.0
|
|
|
$
|
76.8
|
|
|
$
|
45.4
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Construction in progress additions included in accounts payable
|
$
|
8.2
|
|
|
$
|
15.8
|
|
|
$
|
22.3
|
|
Change in accounts payable related to construction in progress additions
|
$
|
(5.2
|
)
|
|
$
|
6.0
|
|
|
$
|
0.7
|
|
Landlord incentives for leasehold improvements
|
$
|
1.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Fair value of common units issued in a business combination
|
$
|
—
|
|
|
$
|
335.7
|
|
|
$
|
—
|
|
Fair value of debt assumed in a business combination
|
$
|
—
|
|
|
$
|
367.5
|
|
|
$
|
—
|
|
Reduction of proceeds from 2023 Notes from underwriting discount
|
$
|
—
|
|
|
$
|
16.1
|
|
|
$
|
—
|
|
Asset
|
Range of Useful
Lives, in Years
|
Improvements to land
|
15 to 30
|
Buildings
|
20 to 30
|
Machinery and equipment
|
5 to 30
|
Automotive equipment
|
5 to 15
|
Furniture and fixtures
|
3 to 10
|
Aircraft
|
20
|
Railcars
|
25 to 30
|
|
For the Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Petroleum segment
|
|
|
|
|
|
||||||
Coffeyville refinery(1)
|
$
|
—
|
|
|
$
|
31.5
|
|
|
$
|
102.2
|
|
Wynnewood refinery(2)
|
80.4
|
|
|
—
|
|
|
—
|
|
|||
|
|
|
|
|
|
||||||
Nitrogen Fertilizer segment
|
|
|
|
|
|
||||||
Nitrogen Fertilizer plants(3)
|
2.6
|
|
|
6.6
|
|
|
7.0
|
|
|||
Total Major Scheduled Turnaround Expenses
|
$
|
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.
|
(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.
|
|
|
Purchase Price Allocation
|
||
|
|
(in millions)
|
||
Cash
|
|
$
|
35.4
|
|
Accounts receivable
|
|
8.9
|
|
|
Inventories
|
|
49.1
|
|
|
Prepaid expenses and other current assets
|
|
5.2
|
|
|
Property, plant and equipment
|
|
775.3
|
|
|
Other long-term assets
|
|
1.1
|
|
|
Deferred revenue
|
|
(29.8
|
)
|
|
Other current liabilities
|
|
(37.0
|
)
|
|
Long-term debt
|
|
(367.5
|
)
|
|
Other long-term liabilities
|
|
(1.2
|
)
|
|
Total fair value of net assets acquired
|
|
439.5
|
|
|
Less: Cash acquired
|
|
35.4
|
|
|
Total consideration transferred, net of cash acquired
|
|
$
|
404.1
|
|
|
|
|
||
|
|
Non-controlling interest
|
||
|
|
(in millions)
|
||
Fair value of CVR Partners common units issued, as of the close of the East Dubuque Merger
|
|
$
|
335.7
|
|
Less: Change in CVR Energy's noncontrolling interest in CVR Partner's equity due to the East Dubuque Merger
|
|
292.8
|
|
|
Adjustment to additional paid-in capital, as of the close of the East Dubuque Merger
|
|
$
|
42.9
|
|
|
Restricted
Shares
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at December 31, 2014
|
48,011
|
|
|
$
|
45.89
|
|
|
$
|
1.9
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|||
Vested
|
(43,085
|
)
|
|
45.55
|
|
|
|
|||
Forfeited
|
(4,327
|
)
|
|
47.68
|
|
|
|
|||
Non-vested at December 31, 2015
|
599
|
|
|
$
|
57.23
|
|
|
$
|
—
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|||
Vested
|
(599
|
)
|
|
57.23
|
|
|
|
|||
Forfeited
|
—
|
|
|
—
|
|
|
|
|||
Non-vested at December 31, 2016
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Units
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at December 31, 2014
|
243,946
|
|
|
$
|
11.07
|
|
|
$
|
2.4
|
|
Granted
|
245,199
|
|
|
7.87
|
|
|
|
|||
Vested
|
(94,854
|
)
|
|
12.55
|
|
|
|
|||
Forfeited
|
(2,388
|
)
|
|
10.99
|
|
|
|
|||
Non-vested at December 31, 2015
|
391,903
|
|
|
$
|
8.71
|
|
|
$
|
3.1
|
|
Granted
|
680,718
|
|
|
6.20
|
|
|
|
|||
Vested
|
(292,536
|
)
|
|
8.78
|
|
|
|
|||
Forfeited
|
(8,299
|
)
|
|
8.72
|
|
|
|
|||
Non-vested at December 31, 2016
|
771,786
|
|
|
$
|
6.47
|
|
|
$
|
4.6
|
|
Granted
|
780,372
|
|
|
3.48
|
|
|
|
|||
Vested
|
(340,730
|
)
|
|
7.01
|
|
|
|
|||
Forfeited
|
(23,222
|
)
|
|
6.49
|
|
|
|
|||
Non-vested at December 31, 2017
|
1,188,206
|
|
|
$
|
4.35
|
|
|
$
|
3.9
|
|
|
Phantom Units
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at December 31, 2014
|
403,947
|
|
|
$
|
18.89
|
|
|
$
|
6.8
|
|
Granted
|
302,319
|
|
|
20.40
|
|
|
|
|||
Vested
|
(136,531
|
)
|
|
19.26
|
|
|
|
|||
Forfeited
|
(58,144
|
)
|
|
18.87
|
|
|
|
|||
Non-vested at December 31, 2015
|
511,591
|
|
|
$
|
19.68
|
|
|
$
|
9.7
|
|
Granted
|
644,148
|
|
|
9.43
|
|
|
|
|||
Vested
|
(218,351
|
)
|
|
19.78
|
|
|
|
|||
Forfeited
|
(32,533
|
)
|
|
19.13
|
|
|
|
|||
Non-vested at December 31, 2016
|
904,855
|
|
|
$
|
12.38
|
|
|
$
|
9.4
|
|
Granted
|
550,172
|
|
|
12.66
|
|
|
|
|||
Vested
|
(349,921
|
)
|
|
13.42
|
|
|
|
|||
Forfeited
|
(118,626
|
)
|
|
13.52
|
|
|
|
|||
Non-vested at December 31, 2017
|
986,480
|
|
|
$
|
12.03
|
|
|
$
|
16.3
|
|
|
Incentive Units
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at December 31, 2014
|
435,515
|
|
|
$
|
18.95
|
|
|
$
|
7.3
|
|
Granted
|
347,811
|
|
|
20.38
|
|
|
|
|||
Vested
|
(160,120
|
)
|
|
19.33
|
|
|
|
|||
Forfeited
|
(18,264
|
)
|
|
19.69
|
|
|
|
|||
Non-vested at December 31, 2015
|
604,942
|
|
|
$
|
19.64
|
|
|
$
|
11.5
|
|
Granted
|
678,469
|
|
|
9.46
|
|
|
|
|||
Vested
|
(256,016
|
)
|
|
19.69
|
|
|
|
|||
Forfeited
|
(39,598
|
)
|
|
19.52
|
|
|
|
|||
Non-vested at December 31, 2016
|
987,797
|
|
|
$
|
12.63
|
|
|
$
|
10.3
|
|
Granted
|
382,648
|
|
|
12.87
|
|
|
|
|||
Vested
|
(371,731
|
)
|
|
14.14
|
|
|
|
|||
Forfeited
|
(219,453
|
)
|
|
12.23
|
|
|
|
|||
Non-vested at December 31, 2017
|
779,261
|
|
|
$
|
12.14
|
|
|
$
|
12.9
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Finished goods
|
$
|
172.0
|
|
|
$
|
151.7
|
|
Raw materials and precious metals
|
113.8
|
|
|
98.4
|
|
||
In-process inventories
|
22.4
|
|
|
23.9
|
|
||
Parts and supplies
|
77.0
|
|
|
75.2
|
|
||
Total Inventories
|
$
|
385.2
|
|
|
$
|
349.2
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Land and improvements
|
$
|
47.4
|
|
|
$
|
46.5
|
|
Buildings
|
83.3
|
|
|
64.8
|
|
||
Machinery and equipment
|
3,733.8
|
|
|
3,656.5
|
|
||
Automotive equipment
|
24.7
|
|
|
24.7
|
|
||
Furniture and fixtures
|
32.4
|
|
|
28.9
|
|
||
Leasehold improvements
|
4.6
|
|
|
3.6
|
|
||
Aircraft
|
3.6
|
|
|
3.6
|
|
||
Railcars
|
16.8
|
|
|
16.8
|
|
||
Construction in progress
|
56.2
|
|
|
54.2
|
|
||
|
4,002.8
|
|
|
3,899.6
|
|
||
Less: Accumulated depreciation
|
1,431.0
|
|
|
1,227.5
|
|
||
Total Property, plant and equipment, net
|
$
|
2,571.8
|
|
|
$
|
2,672.1
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Current
|
|
|
|
|
|
||||||
Federal
|
$
|
(0.7
|
)
|
|
$
|
67.2
|
|
|
$
|
74.9
|
|
State
|
(22.1
|
)
|
|
(7.0
|
)
|
|
14.5
|
|
|||
Total current
|
(22.8
|
)
|
|
60.2
|
|
|
89.4
|
|
|||
Deferred
|
|
|
|
|
|
||||||
Federal
|
(181.4
|
)
|
|
(61.0
|
)
|
|
2.7
|
|
|||
State
|
(12.7
|
)
|
|
(19.0
|
)
|
|
(7.6
|
)
|
|||
Total deferred
|
(194.1
|
)
|
|
(80.0
|
)
|
|
(4.9
|
)
|
|||
Total income tax expense (benefit)
|
$
|
(216.9
|
)
|
|
$
|
(19.8
|
)
|
|
$
|
84.5
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Tax computed at federal statutory rate
|
$
|
0.0
|
|
|
$
|
(3.8
|
)
|
|
$
|
133.8
|
|
State income taxes, net of federal tax benefit
|
(15.7
|
)
|
|
(8.0
|
)
|
|
11.7
|
|
|||
State tax incentives, net of federal tax expense
|
(6.9
|
)
|
|
(8.8
|
)
|
|
(7.2
|
)
|
|||
Domestic production activities deduction
|
—
|
|
|
(4.3
|
)
|
|
(5.9
|
)
|
|||
Noncontrolling interest
|
6.1
|
|
|
5.5
|
|
|
(44.9
|
)
|
|||
Other, net
|
0.1
|
|
|
(0.4
|
)
|
|
(3.0
|
)
|
|||
Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate
|
(200.5
|
)
|
|
—
|
|
|
—
|
|
|||
Total income tax expense (benefit)
|
$
|
(216.9
|
)
|
|
$
|
(19.8
|
)
|
|
$
|
84.5
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
|
(in millions)
|
||||||
Deferred income tax assets:
|
|
|
|
||||
Personnel accruals
|
$
|
—
|
|
|
$
|
1.3
|
|
State tax credit carryforward, net
|
11.3
|
|
|
10.5
|
|
||
Net operating loss carryforward
|
7.2
|
|
|
—
|
|
||
Other
|
—
|
|
|
0.1
|
|
||
Total gross deferred income tax assets
|
18.5
|
|
|
11.9
|
|
||
Deferred income tax liabilities:
|
|
|
|
||||
Personnel accruals
|
(1.2
|
)
|
|
—
|
|
||
Property, plant, and equipment
|
(2.1
|
)
|
|
(3.8
|
)
|
||
Investment in CVR Partners
|
(54.6
|
)
|
|
(89.2
|
)
|
||
Investment in CVR Refining
|
(345.3
|
)
|
|
(497.8
|
)
|
||
Prepaid expenses
|
(0.2
|
)
|
|
(0.3
|
)
|
||
Other
|
(1.0
|
)
|
|
(0.7
|
)
|
||
Total gross deferred income tax liabilities
|
(404.4
|
)
|
|
(591.8
|
)
|
||
Net deferred income tax liabilities
|
$
|
(385.9
|
)
|
|
$
|
(579.9
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Balance beginning of year
|
$
|
44.1
|
|
|
$
|
49.0
|
|
|
$
|
55.5
|
|
Increase based on prior year tax positions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Decrease based on prior year tax positions
|
—
|
|
|
—
|
|
|
—
|
|
|||
Increases in current year tax positions
|
—
|
|
|
—
|
|
|
9.8
|
|
|||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|||
Reductions related to expirations of statute of limitations
|
(15.4
|
)
|
|
(4.9
|
)
|
|
(16.3
|
)
|
|||
Balance end of year
|
$
|
28.7
|
|
|
$
|
44.1
|
|
|
$
|
49.0
|
|
|
December 31, 2017
|
|
December 31, 2016
|
||||
|
(in millions)
|
||||||
6.5% Senior Notes due 2022
|
$
|
500.0
|
|
|
$
|
500.0
|
|
9.25% Senior Secured Notes due 2023
|
645.0
|
|
|
645.0
|
|
||
6.5% Senior Notes due 2021
|
2.2
|
|
|
2.2
|
|
||
Capital lease obligations
|
45.0
|
|
|
46.9
|
|
||
Total debt
|
1,192.2
|
|
|
1,194.1
|
|
||
Unamortized debt issuance cost
|
(12.2
|
)
|
|
(14.2
|
)
|
||
Unamortized debt discount
|
(13.5
|
)
|
|
(15.3
|
)
|
||
Current portion of capital lease obligations
|
(2.1
|
)
|
|
(1.8
|
)
|
||
Long-term debt, net of current portion
|
$
|
1,164.4
|
|
|
$
|
1,162.8
|
|
Year Ending December 31,
|
Capital Lease
|
||
|
(in millions)
|
||
2018
|
$
|
6.5
|
|
2019
|
6.5
|
|
|
2020
|
6.5
|
|
|
2021
|
6.5
|
|
|
2022
|
6.5
|
|
|
Thereafter
|
44.2
|
|
|
Total future payments
|
76.7
|
|
|
Less: amount representing interest
|
31.7
|
|
|
Present value of future minimum payments
|
45.0
|
|
|
|
|
||
Less: current portion
|
2.1
|
|
|
Long-term portion
|
$
|
42.9
|
|
|
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
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
|
||||||
Amount paid to IEP
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
142.4
|
|
Amounts paid to public stockholders
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
31.3
|
|
|||||
Total amount paid
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
173.7
|
|
Per common share
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
2.00
|
|
Shares outstanding
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
|
|
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
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
|
||||||
Amount paid to IEP
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
35.6
|
|
|
$
|
142.4
|
|
Amounts paid to public stockholders
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
7.8
|
|
|
31.2
|
|
|||||
Total amount paid
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
43.4
|
|
|
$
|
173.6
|
|
Per common share
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
2.00
|
|
Shares outstanding
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions, except per share data)
|
||||||||||
Net income attributable to CVR Energy stockholders
|
$
|
234.4
|
|
|
$
|
24.7
|
|
|
$
|
169.6
|
|
|
|
|
|
|
|
||||||
Weighted-average shares of common stock outstanding - Basic and Diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|||
|
|
|
|
|
|
||||||
Basic and Diluted earnings per share
|
$
|
2.70
|
|
|
$
|
0.28
|
|
|
$
|
1.95
|
|
Year Ending December 31,
|
Operating
Leases
|
|
Unconditional
Purchase
Obligations
(1)
|
||||
|
(in millions)
|
||||||
2018
|
$
|
7.4
|
|
|
$
|
165.0
|
|
2019
|
6.5
|
|
|
124.3
|
|
||
2020
|
5.9
|
|
|
100.6
|
|
||
2021
|
5.3
|
|
|
89.8
|
|
||
2022
|
4.8
|
|
|
84.7
|
|
||
Thereafter
|
2.4
|
|
|
542.7
|
|
||
|
$
|
32.3
|
|
|
$
|
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.
|
Year Ending December 31,
|
Amount
|
||
|
(in millions)
|
||
2018
|
$
|
2.9
|
|
2019
|
1.1
|
|
|
2020
|
—
|
|
|
2021
|
—
|
|
|
2022
|
—
|
|
|
Thereafter
|
—
|
|
|
Undiscounted total
|
4.0
|
|
|
Less amounts representing interest at 1.98%
|
0.1
|
|
|
Accrued environmental liabilities at December 31, 2017
|
$
|
3.9
|
|
•
|
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)
|
|
December 31, 2017
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Location and Description
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
15.2
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15.2
|
|
Other current assets (investments)
|
0.1
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
||||
Total Assets
|
$
|
15.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15.3
|
|
Other current liabilities (derivative agreements)
|
$
|
—
|
|
|
$
|
(64.3
|
)
|
|
$
|
—
|
|
|
$
|
(64.3
|
)
|
Other current liabilities (biofuel blending obligation)
|
—
|
|
|
(1.0
|
)
|
|
—
|
|
|
(1.0
|
)
|
||||
Total Liabilities
|
$
|
—
|
|
|
$
|
(65.3
|
)
|
|
$
|
—
|
|
|
$
|
(65.3
|
)
|
|
December 31, 2016
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Location and Description
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
15.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15.8
|
|
Other current assets (investments)
|
0.1
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
||||
Total Assets
|
$
|
15.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
15.9
|
|
Other current liabilities (derivative agreements)
|
$
|
—
|
|
|
$
|
(11.1
|
)
|
|
$
|
—
|
|
|
$
|
(11.1
|
)
|
Other current liabilities (biofuel blending obligation & benzene obligation)
|
—
|
|
|
(187.0
|
)
|
|
—
|
|
|
(187.0
|
)
|
||||
Total Liabilities
|
$
|
—
|
|
|
$
|
(198.1
|
)
|
|
$
|
—
|
|
|
$
|
(198.1
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Current period settlement on derivative contracts
|
$
|
(16.6
|
)
|
|
$
|
36.4
|
|
|
$
|
(26.0
|
)
|
Loss on derivatives, net
|
(69.8
|
)
|
|
(19.4
|
)
|
|
(28.6
|
)
|
|
As of December 31, 2017
|
||||||||||||||||||
Description
|
Gross
Current Assets
|
|
Gross
Amounts
Offset
|
|
Net
Current Assets
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
7.0
|
|
|
$
|
(7.0
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
7.0
|
|
|
$
|
(7.0
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
As of December 31, 2017
|
||||||||||||||||||
Description
|
Gross
Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
71.3
|
|
|
$
|
(7.0
|
)
|
|
$
|
64.3
|
|
|
$
|
—
|
|
|
$
|
64.3
|
|
Total
|
$
|
71.3
|
|
|
$
|
(7.0
|
)
|
|
$
|
64.3
|
|
|
$
|
—
|
|
|
$
|
64.3
|
|
|
As of December 31, 2016
|
||||||||||||||||||
Description
|
Gross
Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
Total
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Net sales
|
|
|
|
|
|
||||||
Petroleum
|
$
|
5,664.2
|
|
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
Nitrogen Fertilizer
|
330.8
|
|
|
356.3
|
|
|
289.2
|
|
|||
Intersegment elimination
|
(6.6
|
)
|
|
(5.2
|
)
|
|
(18.6
|
)
|
|||
Total
|
$
|
5,988.4
|
|
|
$
|
4,782.4
|
|
|
$
|
5,432.5
|
|
Cost of materials and other
|
|
|
|
|
|
||||||
Petroleum
|
$
|
4,804.7
|
|
|
$
|
3,759.2
|
|
|
$
|
4,143.6
|
|
Nitrogen Fertilizer
|
84.9
|
|
|
93.7
|
|
|
65.2
|
|
|||
Intersegment elimination
|
(6.7
|
)
|
|
(5.4
|
)
|
|
(18.4
|
)
|
|||
Total
|
$
|
4,882.9
|
|
|
$
|
3,847.5
|
|
|
$
|
4,190.4
|
|
Direct operating expenses (exclusive of depreciation and amortization)
|
|
|
|
|
|
||||||
Petroleum
|
$
|
443.8
|
|
|
$
|
393.4
|
|
|
$
|
478.5
|
|
Nitrogen Fertilizer
|
155.5
|
|
|
148.3
|
|
|
106.1
|
|
|||
Other
|
0.2
|
|
|
0.1
|
|
|
0.1
|
|
|||
Total
|
$
|
599.5
|
|
|
$
|
541.8
|
|
|
$
|
584.7
|
|
Depreciation and amortization
|
|
|
|
|
|
||||||
Petroleum
|
$
|
133.1
|
|
|
$
|
129.0
|
|
|
$
|
130.2
|
|
Nitrogen Fertilizer
|
74.0
|
|
|
58.2
|
|
|
28.4
|
|
|||
Other
|
6.9
|
|
|
5.9
|
|
|
5.5
|
|
|||
Total
|
$
|
214.0
|
|
|
$
|
193.1
|
|
|
$
|
164.1
|
|
Operating income (loss)
|
|
|
|
|
|
||||||
Petroleum
|
$
|
203.8
|
|
|
$
|
77.8
|
|
|
$
|
361.7
|
|
Nitrogen Fertilizer
|
(9.2
|
)
|
|
26.8
|
|
|
68.7
|
|
|||
Other
|
(16.8
|
)
|
|
(13.7
|
)
|
|
(8.8
|
)
|
|||
Total
|
$
|
177.8
|
|
|
$
|
90.9
|
|
|
$
|
421.6
|
|
Capital expenditures
|
|
|
|
|
|
||||||
Petroleum
|
$
|
99.7
|
|
|
$
|
102.3
|
|
|
$
|
194.7
|
|
Nitrogen fertilizer
|
14.5
|
|
|
23.2
|
|
|
17.0
|
|
|||
Other
|
4.4
|
|
|
7.2
|
|
|
7.0
|
|
|||
Total
|
$
|
118.6
|
|
|
$
|
132.7
|
|
|
$
|
218.7
|
|
|
Year Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
|
(in millions)
|
||||||||||
Total assets
|
|
|
|
|
|
||||||
Petroleum
|
$
|
2,269.9
|
|
|
$
|
2,331.9
|
|
|
$
|
2,189.0
|
|
Nitrogen Fertilizer
|
1,234.3
|
|
|
1,312.2
|
|
|
536.3
|
|
|||
Other
|
302.5
|
|
|
406.1
|
|
|
574.1
|
|
|||
Total
|
$
|
3,806.7
|
|
|
$
|
4,050.2
|
|
|
$
|
3,299.4
|
|
Goodwill
|
|
|
|
|
|
||||||
Petroleum
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Nitrogen Fertilizer
|
41.0
|
|
|
41.0
|
|
|
41.0
|
|
|||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total
|
$
|
41.0
|
|
|
$
|
41.0
|
|
|
$
|
41.0
|
|
|
Year Ended December 31, 2017
|
||||||||||||||
|
Quarter
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in millions, except per share data)
|
||||||||||||||
Net sales
|
$
|
1,507.1
|
|
|
$
|
1,434.4
|
|
|
$
|
1,453.8
|
|
|
$
|
1,593.1
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of materials and other
|
1,221.2
|
|
|
1,228.6
|
|
|
1,132.4
|
|
|
1,300.7
|
|
||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
138.1
|
|
|
124.2
|
|
|
161.1
|
|
|
176.1
|
|
||||
Depreciation and amortization
|
48.6
|
|
|
51.7
|
|
|
51.3
|
|
|
51.7
|
|
||||
Cost of sales
|
1,407.9
|
|
|
1,404.5
|
|
|
1,344.8
|
|
|
1,528.5
|
|
||||
Selling, general and administrative (exclusive of depreciation and amortization as reflected below)
|
29.1
|
|
|
26.3
|
|
|
27.3
|
|
|
31.5
|
|
||||
Depreciation and amortization
|
2.5
|
|
|
2.3
|
|
|
2.8
|
|
|
3.1
|
|
||||
Total operating costs and expenses
|
1,439.5
|
|
|
1,433.1
|
|
|
1,374.9
|
|
|
1,563.1
|
|
||||
Operating income
|
67.6
|
|
|
1.3
|
|
|
78.9
|
|
|
30.0
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs
|
(27.0
|
)
|
|
(27.6
|
)
|
|
(27.6
|
)
|
|
(27.9
|
)
|
||||
Interest income
|
0.2
|
|
|
0.3
|
|
|
0.2
|
|
|
0.4
|
|
||||
Gain (loss) on derivatives, net
|
12.2
|
|
|
—
|
|
|
(17.0
|
)
|
|
(65.0
|
)
|
||||
Other income, net
|
—
|
|
|
0.1
|
|
|
—
|
|
|
0.9
|
|
||||
Total other expense
|
(14.6
|
)
|
|
(27.2
|
)
|
|
(44.4
|
)
|
|
(91.6
|
)
|
||||
Income (loss) before income taxes
|
53.0
|
|
|
(25.9
|
)
|
|
34.5
|
|
|
(61.6
|
)
|
||||
Income tax expense (benefit)
|
14.8
|
|
|
(6.6
|
)
|
|
9.2
|
|
|
(234.3
|
)
|
||||
Net income (loss)
|
38.2
|
|
|
(19.3
|
)
|
|
25.3
|
|
|
172.7
|
|
||||
Less: Net income (loss) attributable to noncontrolling interest
|
16.0
|
|
|
(8.8
|
)
|
|
3.1
|
|
|
(27.8
|
)
|
||||
Net income (loss) attributable to CVR Energy stockholders
|
$
|
22.2
|
|
|
$
|
(10.5
|
)
|
|
$
|
22.2
|
|
|
$
|
200.5
|
|
|
|
|
|
|
|
|
|
||||||||
Basic and diluted earnings (loss) per share
|
$
|
0.26
|
|
|
$
|
(0.12
|
)
|
|
$
|
0.26
|
|
|
$
|
2.31
|
|
Dividends declared per share
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common shares outstanding - basic and diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
Quarter
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in millions, except per share data)
|
||||||||||||||
Net sales
|
$
|
905.5
|
|
|
$
|
1,283.2
|
|
|
$
|
1,240.3
|
|
|
$
|
1,353.4
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of materials and other
|
736.8
|
|
|
976.9
|
|
|
1,005.7
|
|
|
1,128.1
|
|
||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
141.4
|
|
|
138.3
|
|
|
129.5
|
|
|
132.6
|
|
||||
Depreciation and amortization
|
37.9
|
|
|
48.5
|
|
|
48.2
|
|
|
49.9
|
|
||||
Cost of sales
|
916.1
|
|
|
1,163.7
|
|
|
1,183.4
|
|
|
1,310.6
|
|
||||
Selling, general and administrative (exclusive of depreciation and amortization as reflected below)
|
27.2
|
|
|
26.6
|
|
|
27.8
|
|
|
27.5
|
|
||||
Depreciation and amortization
|
2.1
|
|
|
2.2
|
|
|
1.9
|
|
|
2.4
|
|
||||
Total operating costs and expenses
|
945.4
|
|
|
1,192.5
|
|
|
1,213.1
|
|
|
1,340.5
|
|
||||
Operating income (loss)
|
(39.9
|
)
|
|
90.7
|
|
|
27.2
|
|
|
12.9
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs
|
(12.1
|
)
|
|
(18.5
|
)
|
|
(26.2
|
)
|
|
(27.1
|
)
|
||||
Interest income
|
0.2
|
|
|
0.1
|
|
|
0.2
|
|
|
0.2
|
|
||||
Loss on derivatives, net
|
(1.2
|
)
|
|
(1.9
|
)
|
|
(1.7
|
)
|
|
(14.6
|
)
|
||||
Gain (loss) on extinguishment of debt
|
—
|
|
|
(5.1
|
)
|
|
—
|
|
|
0.2
|
|
||||
Other income, net
|
0.3
|
|
|
0.1
|
|
|
5.0
|
|
|
0.3
|
|
||||
Total other expense
|
(12.8
|
)
|
|
(25.3
|
)
|
|
(22.7
|
)
|
|
(41.0
|
)
|
||||
Income (loss) before income taxes
|
(52.7
|
)
|
|
65.4
|
|
|
4.5
|
|
|
(28.1
|
)
|
||||
Income tax expense (benefit)
|
(21.8
|
)
|
|
21.6
|
|
|
2.5
|
|
|
(22.1
|
)
|
||||
Net income (loss)
|
(30.9
|
)
|
|
43.8
|
|
|
2.0
|
|
|
(6.0
|
)
|
||||
Less: Net income (loss) attributable to noncontrolling interest
|
(14.7
|
)
|
|
15.4
|
|
|
(3.4
|
)
|
|
(13.1
|
)
|
||||
Net income (loss) attributable to CVR Energy stockholders
|
$
|
(16.2
|
)
|
|
$
|
28.4
|
|
|
$
|
5.4
|
|
|
$
|
7.1
|
|
|
|
|
|
|
|
|
|
||||||||
Basic and diluted earnings (loss) per share
|
$
|
(0.19
|
)
|
|
$
|
0.33
|
|
|
$
|
0.06
|
|
|
$
|
0.08
|
|
Dividends declared per share
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
$
|
0.50
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
||||||||
Basic and diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
Exhibit Number
|
Exhibit Title
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
*
|
|
Filed herewith.
|
|
|
|
**
|
|
Previously filed.
|
|
|
|
†
|
|
Furnished herewith.
|
|
|
|
+
|
|
Denotes management contract or compensatory plan or arrangement.
|
|
|
|
|
CVR Energy, Inc.
|
||
|
By:
|
/s/ DAVID L. LAMP
|
|
|
|
Name:
|
David L. Lamp
|
|
|
Title:
|
President and Chief Executive Officer
|
Signature
|
Title
|
Date
|
|
|
|
/s/ DAVID L. LAMP
|
President, Chief Executive Officer and Director (Principal Executive Officer)
|
February 26, 2018
|
David L. Lamp
|
|
|
|
|
|
/s/ SUSAN M. BALL
|
Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)
|
February 26, 2018
|
Susan M. Ball
|
|
|
|
|
|
|
Chairman of the Board of Directors
|
February 26, 2018
|
Carl C. Icahn
|
|
|
|
|
|
/s/ BOB G. ALEXANDER
|
Director
|
February 26, 2018
|
Bob G. Alexander
|
|
|
|
|
|
/s/ SUNGHWAN CHO
|
Director
|
February 26, 2018
|
SungHwan Cho
|
|
|
|
|
|
/s/ JONATHAN FRATES
|
Director
|
February 26, 2018
|
Jonathan Frates
|
|
|
|
|
|
/s/ STEPHEN MONGILLO
|
Director
|
February 26, 2018
|
Stephen Mongillo
|
|
|
|
|
|
/s/ LOUIS J. PASTOR
|
Director
|
February 26, 2018
|
Louis J. Pastor
|
|
|
|
|
|
/s/ JAMES M. STROCK
|
Director
|
February 26, 2018
|
James M. Strock
|
|
|
CVR ENERGY, INC.
______________________________
By:
Title:
|
GRANTEE
|
______________________________
|
|
Name:
|
|
|
Date: February 26, 2018
|
By:
|
/s/ DAVID L. LAMP
|
|
|
David L. Lamp
President and Chief Executive Officer
|
|
|
(Principal Executive Officer)
|
Date: February 26, 2018
|
By:
|
/s/ SUSAN M. BALL
|
|
|
Susan M. Ball
Executive Vice President, Chief Financial Officer and Treasurer
|
|
|
(Principal Financial and Accounting Officer)
|
Date: February 26, 2018
|
By:
|
/s/ DAVID L. LAMP
|
|
|
David L. Lamp
President and Chief Executive Officer
|
|
By:
|
/s/ SUSAN M. BALL
|
|
|
Susan M. Ball
Executive Vice President, Chief Financial Officer and Treasurer
|