(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, 2013
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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
þ
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Accelerated filer
o
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Non-accelerated filer
o
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Smaller reporting company
o
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(Do not check if a smaller reporting company)
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Class
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Outstanding at February 18, 2014
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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 2014 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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a crude oil gathering system with a gathering capacity of approximately
55,000
bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas which is supported by approximately
350
miles of owned and leased pipeline;
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•
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a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and to customers at throughput terminals on Magellan Midstream Partners, L.P. ("Magellan") and NuStar Energy, LP's ("NuStar") refined products distribution systems; and
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•
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a
145,000
bpd pipeline system that transports crude oil to the Coffeyville refinery with
1.2 million
barrels of associated company-owned storage tanks,
0.5 million
barrels of company-owned crude oil storage tanks in Wynnewood, Oklahoma,
1.0 million
barrels of company owned crude oil storage capacity in Cushing, Oklahoma and an additional
3.3 million
barrels of leased crude oil storage capacity located at Cushing.
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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 and Texas. The system has field offices in Bartlesville and Pauls Valley, Oklahoma and Plainville, Winfield and Iola, Kansas. The system is comprised of approximately
350
miles of feeder and trunk pipelines, approximately
150
crude oil transports, and associated storage facilities for gathering crude oils purchased from independent crude oil producers in our gathering area. The petroleum business also leases several sections of a pipeline from Magellan, which is incorporated into its crude oil gathering system. The crude oil gathering system has a gathering capacity of approximately
55,000
bpd. Gathered crude oil provides an attractive and competitive base supply of crude oil for the Coffeyville and Wynnewood refineries. During
2013
, the petroleum business gathered an average of approximately
53,000
bpd. We also have 35,000 bpd of contracted capacity on the Keystone and Spearhead pipelines that allow us to supply price-advantaged Canadian and Bakken crudes to our refineries.
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•
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Pipelines and Storage Tanks.
The petroleum business owns a proprietary pipeline system capable of transporting approximately
145,000
bpd of crude oil from its Broome Station tank farm located near Caney, Kansas to its Coffeyville refinery. Crude oils sourced outside of the proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to the Broome Station tank farm via a pipeline owned by Plains Pipeline L.P. ("Plains"). The petroleum business also controls associated crude oil storage tanks with a capacity of approximately
1.2 million
barrels located outside the Coffeyville refinery,
0.5 million
barrels of crude oil storage capacity at Wynnewood, Oklahoma,
1.0 million
barrels of crude oil storage capacity in Cushing, Oklahoma and leases an additional
3.3 million
barrels of crude oil storage capacity located at Cushing. In addition to crude oil storage, the petroleum business owns approximately
4.5 million
barrels of combined refinery related storage capacity.
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restrictions on operations or the need to install enhanced or additional controls;
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the need to obtain and comply with permits, licenses and authorizations;
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requirements for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability for off-site waste disposal locations; and
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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 2017
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Total
Estimated
Costs
Through 2017
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(in millions)
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Coffeyville Refinery
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$
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0.5
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$
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—
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$
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0.6
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$
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1.1
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Phillipsburg Terminal
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0.7
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—
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1.0
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1.7
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Wynnewood Refinery
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—
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—
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0.3
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0.3
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Total Estimated Costs
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$
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1.2
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$
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—
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$
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1.9
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$
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3.1
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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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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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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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denial or delay in obtaining regulatory approvals and/or permits;
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unplanned increases in the cost of equipment, materials or labor;
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disruptions in transportation of equipment and materials;
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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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shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
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market-related increases in a project's debt or equity financing costs; and/or
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nonperformance or force majeure by, or disputes with, the petroleum business' vendors, suppliers, contractors or sub-contractors.
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weather patterns and field conditions (particularly during periods of traditionally high nitrogen fertilizer consumption);
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quantities of nitrogen fertilizers imported to and exported from North America;
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current and projected grain inventories and prices, which are heavily influenced by U.S. exports and world-wide grain markets; and
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U.S. governmental policies, including farm and biofuel policies, which may directly or indirectly influence the number of acres planted, the level of grain inventories, the mix of crops planted or crop prices.
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Although we believe the petroleum business has sufficient liquidity under its 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 revolving 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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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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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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major unplanned maintenance requirements
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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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labor supply shortages, or labor difficulties that result in a work stoppage or slowdown;
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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 a pre-loss condition.
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unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business;
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failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition;
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strain on the operational and managerial controls and procedures of the petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources;
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difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;
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assumption of unknown material liabilities or regulatory non-compliance issues;
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amortization of acquired assets, which would reduce future reported earnings;
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possible adverse short-term effects on our cash flows or operating results; and
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diversion of management's attention from the ongoing operations of our business.
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a significant portion of their cash flows could be used to service their indebtedness, reducing available cash and their ability to make distributions on their common units (including distributions to us);
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a high level of debt would increase their vulnerability to general adverse economic and industry conditions;
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the covenants contained in their debt agreements will limit their ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;
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a high level of debt may place them at a competitive disadvantage compared to competitors that are less leveraged and who therefore may be able to take advantage of opportunities that their indebtedness would prevent them from pursuing;
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their debt covenants may also affect flexibility in planning for, and reacting to, changes in the economy and in their industries;
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a high level of debt may make it more likely that a reduction in the petroleum business' borrowing base following a periodic redetermination could require the Refining Partnership to repay a portion of its then-outstanding bank borrowings under its ABL credit facility; and
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a high level of debt may impair their ability to obtain additional financing in the future for working capital, capital expenditures, debt service requirements, acquisitions, general corporate or other purposes.
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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 our control; and
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the Refining Partnership's ability to borrow under its Amended and Restated ABL Credit Facility and the intercompany credit facility between the Refining Partnership and us, and the Nitrogen Fertilizer Partnership's ability to borrow under its revolving credit facility, the availability of which depends on, among other things, compliance with their respective covenants.
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incur, assume or guarantee additional debt or issue redeemable or preferred units
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make distributions or prepay, redeem, or repurchase certain debt;
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enter into agreements that restrict distributions from restricted subsidiaries;
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incur liens;
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sell or otherwise dispose of assets, including capital stock of subsidiaries;
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enter into transactions with affiliates; and
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merge, consolidate or sell substantially all of their assets.
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the election and appointment of directors;
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business strategy and policies;
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mergers or other business combinations;
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acquisition or disposition of assets;
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future issuances of common stock, common units or other securities;
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incurrence of debt or obtaining other sources of financing; and
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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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the requirement that a majority of our board of directors consist of independent directors;
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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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the requirement that we have a compensation committee that is composed entirely of independent directors.
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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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limitations on the ability of stockholders to call special meetings of stockholders;
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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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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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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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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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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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Oil refinery, office buildings, refined oil storage
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Montgomery County, KS (Coffeyville Station)
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20
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Own
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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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Crude oil storage
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Cowley County, KS (Hooser Station)
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80
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Own
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Crude oil storage
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Cushing, OK
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138
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Own
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Crude oil storage
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2013
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High
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Low
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||||
First Quarter
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$
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62.50
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$
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46.29
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Second Quarter
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72.32
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44.95
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Third Quarter
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49.94
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38.06
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Fourth Quarter
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43.44
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33.03
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2012
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High
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Low
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||||
First Quarter
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$
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30.11
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$
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19.19
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Second Quarter
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31.71
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23.54
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Third Quarter
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38.35
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26.53
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Fourth Quarter
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49.63
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34.52
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February 19, 2013
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May 17, 2013
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June 10, 2013
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August 19, 2013
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November 18, 2013
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Total Dividends
Paid in 2013
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||||||||||||
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(in millions, except per share amounts)
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||||||||||||||||||||||
Dividend type
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Special
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Quarterly
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Special
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Quarterly
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Quarterly
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|||||||
Amount paid to IEP
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$
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391.6
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$
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53.4
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$
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462.8
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$
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53.4
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$
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53.4
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$
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1,014.6
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Amounts paid to public stockholders
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86.0
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11.7
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101.6
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11.7
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11.7
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222.7
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||||||
Total amount paid
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$
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477.6
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$
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65.1
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$
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564.4
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$
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65.1
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$
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65.1
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$
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1,237.3
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Per common share
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$
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5.50
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$
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0.75
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$
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6.50
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$
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0.75
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$
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0.75
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$
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14.25
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Shares outstanding
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86.8
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86.8
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86.8
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86.8
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86.8
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December 31, 2012
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March 31, 2013
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June 30, 2013
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September 30, 2013
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Total Cash
Distributions
Paid in 2013
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||||||||||
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(in millions, except per common unit amounts)
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Amount paid to CRLLC
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$
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9.8
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$
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31.1
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$
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22.7
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$
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14.0
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$
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77.5
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Amounts paid to public unitholders
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4.2
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13.5
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19.9
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12.3
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50.0
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|||||
Total amount paid
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$
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14.0
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$
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44.6
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$
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42.6
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$
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26.3
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$
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127.5
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Per common unit
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$
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0.192
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$
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0.610
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$
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0.583
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$
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0.360
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$
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1.745
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Common units outstanding
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73.1
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73.1
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73.1
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73.1
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December 31, 2011
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March 31, 2012
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June 30, 2012
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September 30, 2012
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Total Cash
Distributions
Paid in 2012
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||||||||||
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(in millions, except per common unit amounts)
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||||||||||||||||||
Amount paid to CRLLC
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$
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29.9
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$
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26.6
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$
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30.5
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$
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25.3
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|
|
$
|
112.4
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Amounts paid to public unitholders
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13.0
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|
|
11.6
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13.3
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10.9
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48.8
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|||||
Total amount paid
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$
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42.9
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|
$
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38.2
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|
|
$
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43.8
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|
|
$
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36.2
|
|
|
$
|
161.2
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Per common unit
|
$
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0.588
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|
|
$
|
0.523
|
|
|
$
|
0.600
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|
|
$
|
0.496
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|
|
$
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2.207
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|
Common units outstanding
|
73.0
|
|
|
73.0
|
|
|
73.0
|
|
|
73.0
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|
|
|
|
|
March 31, 2013
(1)
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June 30, 2013
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September 30, 2013
|
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Total Cash
Distributions
Paid in 2013
|
||||||||
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(in millions, except per common unit amounts)
|
|||||||||||||||
Amount paid to CVR Refining Holdings, LLC
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|
$
|
189.6
|
|
|
$
|
141.5
|
|
|
$
|
31.4
|
|
|
$
|
362.5
|
|
Amounts paid to public unitholders
|
|
43.6
|
|
|
57.8
|
|
|
12.9
|
|
|
114.2
|
|
||||
Total amount paid
|
|
$
|
233.2
|
|
|
$
|
199.3
|
|
|
$
|
44.3
|
|
|
$
|
476.7
|
|
Per common unit
|
|
$
|
1.58
|
|
|
$
|
1.35
|
|
|
$
|
0.30
|
|
|
$
|
3.23
|
|
Common units outstanding
|
|
147.6
|
|
|
147.6
|
|
|
147.6
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|
|
|
|
(1)
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The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).
|
|
Jan '09
|
|
Mar '09
|
|
Jun '09
|
|
Sep '09
|
|
Dec '09
|
|
Mar '10
|
|
Jun '10
|
|
Sep '10
|
|
Dec '10
|
|
Mar '11
|
|
Jun '11
|
|||||||||||
CVR Energy, Inc.
|
100.00
|
|
|
138.50
|
|
|
183.25
|
|
|
311.00
|
|
|
171.50
|
|
|
218.75
|
|
|
188.00
|
|
|
206.25
|
|
|
379.50
|
|
|
579.00
|
|
|
615.50
|
|
Russell 2000 Index
|
100.00
|
|
|
84.64
|
|
|
101.77
|
|
|
120.99
|
|
|
125.22
|
|
|
135.88
|
|
|
122.03
|
|
|
135.38
|
|
|
156.90
|
|
|
168.90
|
|
|
165.67
|
|
Peer Group
|
100.00
|
|
|
134.01
|
|
|
107.25
|
|
|
117.98
|
|
|
99.56
|
|
|
108.81
|
|
|
101.13
|
|
|
103.59
|
|
|
139.60
|
|
|
224.32
|
|
|
229.32
|
|
|
Sep '11
|
|
Dec '11
|
|
Mar '12
|
|
Jun '12
|
|
Sep '12
|
|
Dec '12
|
|
Mar '13
|
|
Jun '13
|
|
Sep '13
|
|
Dec '13
|
||||||||||
CVR Energy, Inc.
|
528.50
|
|
|
468.25
|
|
|
668.75
|
|
|
664.50
|
|
|
918.75
|
|
|
1,219.75
|
|
|
1,113.50
|
|
|
1,142.25
|
|
|
943.50
|
|
|
1,085.75
|
|
Russell 2000 Index
|
128.97
|
|
|
148.35
|
|
|
166.24
|
|
|
159.87
|
|
|
167.67
|
|
|
170.06
|
|
|
190.52
|
|
|
195.71
|
|
|
214.99
|
|
|
232.98
|
|
Peer Group
|
166.11
|
|
|
176.59
|
|
|
228.50
|
|
|
244.42
|
|
|
329.02
|
|
|
356.26
|
|
|
443.72
|
|
|
357.68
|
|
|
318.93
|
|
|
452.33
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2013
|
|
2012
|
|
2011(1)
|
|
2010
|
|
2009
|
||||||||||
|
(in millions, except per share data)
|
||||||||||||||||||
Statements of Operations Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net sales
|
$
|
8,985.8
|
|
|
$
|
8,567.3
|
|
|
$
|
5,029.1
|
|
|
$
|
4,079.8
|
|
|
$
|
3,136.3
|
|
Cost of product sold(2)
|
7,563.2
|
|
|
6,696.9
|
|
|
3,943.5
|
|
|
3,568.1
|
|
|
2,547.7
|
|
|||||
Direct operating expenses(2)
|
455.8
|
|
|
522.1
|
|
|
334.1
|
|
|
239.8
|
|
|
226.6
|
|
|||||
Insurance recovery-business interruption
|
—
|
|
|
—
|
|
|
(3.4
|
)
|
|
—
|
|
|
—
|
|
|||||
Selling, general and administrative expenses(2)
|
113.5
|
|
|
183.4
|
|
|
98.0
|
|
|
92.0
|
|
|
68.9
|
|
|||||
Depreciation and amortization
|
142.8
|
|
|
130.0
|
|
|
90.3
|
|
|
86.8
|
|
|
84.9
|
|
|||||
Operating income
|
$
|
710.5
|
|
|
$
|
1,034.9
|
|
|
$
|
566.6
|
|
|
$
|
93.1
|
|
|
$
|
208.2
|
|
Interest expense and other financing costs
|
(50.5
|
)
|
|
(75.4
|
)
|
|
(55.8
|
)
|
|
(50.3
|
)
|
|
(44.2
|
)
|
|||||
Interest income
|
1.2
|
|
|
0.9
|
|
|
0.5
|
|
|
2.2
|
|
|
1.7
|
|
|||||
Gain (loss) on derivatives, net
|
57.1
|
|
|
(285.6
|
)
|
|
78.1
|
|
|
(1.5
|
)
|
|
(65.3
|
)
|
|||||
Loss on extinguishment of debt
|
(26.1
|
)
|
|
(37.5
|
)
|
|
(2.1
|
)
|
|
(16.6
|
)
|
|
(2.1
|
)
|
|||||
Other income, net
|
13.5
|
|
|
0.9
|
|
|
0.8
|
|
|
1.2
|
|
|
0.3
|
|
|||||
Income before income tax expense
|
$
|
705.7
|
|
|
$
|
638.2
|
|
|
$
|
588.1
|
|
|
$
|
28.1
|
|
|
$
|
98.6
|
|
Income tax expense
|
183.7
|
|
|
225.6
|
|
|
209.5
|
|
|
13.8
|
|
|
29.2
|
|
|||||
Net income
|
522.0
|
|
|
412.6
|
|
|
378.6
|
|
|
14.3
|
|
|
69.4
|
|
|||||
Less: Net income attributable to noncontrolling interest
|
151.3
|
|
|
34.0
|
|
|
32.8
|
|
|
—
|
|
|
—
|
|
|||||
Net income attributable to CVR Energy stockholders
|
$
|
370.7
|
|
|
$
|
378.6
|
|
|
$
|
345.8
|
|
|
$
|
14.3
|
|
|
$
|
69.4
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic earnings per share
|
$
|
4.27
|
|
|
$
|
4.36
|
|
|
$
|
4.00
|
|
|
$
|
0.17
|
|
|
$
|
0.80
|
|
Diluted earnings per share
|
$
|
4.27
|
|
|
$
|
4.33
|
|
|
$
|
3.94
|
|
|
$
|
0.16
|
|
|
$
|
0.80
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
86.8
|
|
|
86.8
|
|
|
86.5
|
|
|
86.3
|
|
|
86.2
|
|
|||||
Diluted
|
86.8
|
|
|
87.4
|
|
|
87.8
|
|
|
86.8
|
|
|
86.3
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2013
|
|
2012
|
|
2011(1)
|
|
2010
|
|
2009
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
842.1
|
|
|
$
|
896.0
|
|
|
$
|
388.3
|
|
|
$
|
200.0
|
|
|
$
|
36.9
|
|
Working capital
|
1,230.2
|
|
|
1,135.4
|
|
|
769.2
|
|
|
333.6
|
|
|
235.4
|
|
|||||
Total assets
|
3,665.8
|
|
|
3,610.9
|
|
|
3,119.3
|
|
|
1,740.2
|
|
|
1,614.5
|
|
|||||
Total debt, including current portion
|
676.2
|
|
|
898.2
|
|
|
863.8
|
|
|
477.0
|
|
|
491.3
|
|
|||||
Total CVR stockholders' equity
|
1,188.6
|
|
|
1,525.1
|
|
|
1,151.6
|
|
|
689.6
|
|
|
653.8
|
|
|||||
Cash Flow Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
440.1
|
|
|
762.6
|
|
|
278.6
|
|
|
225.4
|
|
|
85.3
|
|
|||||
Investing activities
|
(250.3
|
)
|
|
(210.7
|
)
|
|
(674.4
|
)
|
|
(31.3
|
)
|
|
(48.3
|
)
|
|||||
Financing activities
|
(243.7
|
)
|
|
(44.2
|
)
|
|
584.1
|
|
|
(31.0
|
)
|
|
(9.0
|
)
|
|||||
Net cash flow
|
(53.9
|
)
|
|
507.7
|
|
|
188.3
|
|
|
163.1
|
|
|
28.0
|
|
|||||
Other Financial Data:
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures for property, plant and equipment
|
256.5
|
|
|
212.2
|
|
|
91.2
|
|
|
32.4
|
|
|
48.8
|
|
(1)
|
We acquired WEC on December 15, 2011 and its results of operations are included from the date of acquisition.
|
(2)
|
Amounts are shown exclusive of depreciation and amortization.
|
•
|
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 performance, future capital sources and other matters; 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.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2013
|
|
2012
|
|
2011
|
||||||
|
|
(in millions)
|
||||||||||
Loss on extinguishment of debt (a)
|
|
$
|
26.1
|
|
|
$
|
37.5
|
|
|
$
|
2.1
|
|
Transaction expenses (b)
|
|
—
|
|
|
44.2
|
|
|
—
|
|
|||
Expenses associated with the acquisition of Gary-Williams (c)
|
|
—
|
|
|
11.0
|
|
|
9.1
|
|
|||
Share-based compensation (d)
|
|
18.4
|
|
|
39.1
|
|
|
27.2
|
|
|||
Gain (loss) on derivatives, net
|
|
57.1
|
|
|
(285.6
|
)
|
|
78.1
|
|
|||
Major scheduled turnaround expenses (e)
|
|
—
|
|
|
128.5
|
|
|
66.4
|
|
|
December 31, 2012
|
|
March 31, 2013
|
|
June 30, 2013
|
|
September 30, 2013
|
|
Total Cash
Distributions
Paid in 2013
|
||||||||||
|
(in millions, except per common unit amounts)
|
||||||||||||||||||
Amount paid to CRLLC
|
$
|
9.8
|
|
|
$
|
31.1
|
|
|
$
|
22.7
|
|
|
$
|
14.0
|
|
|
$
|
77.5
|
|
Amounts paid to public unitholders
|
4.2
|
|
|
13.5
|
|
|
19.9
|
|
|
12.3
|
|
|
50.0
|
|
|||||
Total amount paid
|
$
|
14.0
|
|
|
$
|
44.6
|
|
|
$
|
42.6
|
|
|
$
|
26.3
|
|
|
$
|
127.5
|
|
Per common unit
|
$
|
0.192
|
|
|
$
|
0.610
|
|
|
$
|
0.583
|
|
|
$
|
0.360
|
|
|
$
|
1.745
|
|
Common units outstanding
|
73.1
|
|
|
73.1
|
|
|
73.1
|
|
|
73.1
|
|
|
|
|
December 31, 2011
|
|
March 31, 2012
|
|
June 30, 2012
|
|
September 30, 2012
|
|
Total Cash
Distributions
Paid in 2012
|
||||||||||
|
(in millions, except per common units amounts)
|
||||||||||||||||||
Amount paid to CRLLC
|
$
|
29.9
|
|
|
$
|
26.6
|
|
|
$
|
30.5
|
|
|
$
|
25.3
|
|
|
$
|
112.4
|
|
Amounts paid to public unitholders
|
13.0
|
|
|
11.6
|
|
|
13.3
|
|
|
10.9
|
|
|
48.8
|
|
|||||
Total amount paid
|
$
|
42.9
|
|
|
$
|
38.2
|
|
|
$
|
43.8
|
|
|
$
|
36.2
|
|
|
$
|
161.2
|
|
Per common unit
|
$
|
0.588
|
|
|
$
|
0.523
|
|
|
$
|
0.600
|
|
|
$
|
0.496
|
|
|
$
|
2.207
|
|
Common units outstanding
|
73.0
|
|
|
73.0
|
|
|
73.0
|
|
|
73.0
|
|
|
|
|
|
|
March 31, 2013
(1)
|
|
June 30, 2013
|
|
September 30, 2013
|
|
Total Cash
Distributions
Paid in 2013
|
||||||||
|
(in millions, except per common unit amounts)
|
|||||||||||||||
Amount paid to CVR Refining Holdings, LLC
|
|
$
|
189.6
|
|
|
$
|
141.5
|
|
|
$
|
31.4
|
|
|
$
|
362.5
|
|
Amounts paid to public unitholders
|
|
43.6
|
|
|
57.8
|
|
|
12.9
|
|
|
114.2
|
|
||||
Total amount paid
|
|
$
|
233.2
|
|
|
$
|
199.3
|
|
|
$
|
44.3
|
|
|
$
|
476.7
|
|
Per common unit
|
|
$
|
1.58
|
|
|
$
|
1.35
|
|
|
$
|
0.30
|
|
|
$
|
3.23
|
|
Common units outstanding
|
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
|
|
|
(1)
|
The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).
|
|
February 19, 2013
|
|
May 17, 2013
|
|
June 10, 2013
|
|
August 19, 2013
|
|
November 18, 2013
|
|
Total Dividends
Paid in 2013 |
||||||||||||
|
(in millions, expect per share amounts)
|
||||||||||||||||||||||
Dividend type
|
Special
|
|
|
Quarterly
|
|
|
Special
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
|
|||||||
Amount paid to IEP
|
$
|
391.6
|
|
|
$
|
53.4
|
|
|
$
|
462.8
|
|
|
$
|
53.4
|
|
|
$
|
53.4
|
|
|
$
|
1,014.6
|
|
Amounts paid to public stockholders
|
86.0
|
|
|
11.7
|
|
|
101.6
|
|
|
11.7
|
|
|
11.7
|
|
|
222.7
|
|
||||||
Total amount paid
|
$
|
477.6
|
|
|
$
|
65.1
|
|
|
$
|
564.4
|
|
|
$
|
65.1
|
|
|
$
|
65.1
|
|
|
$
|
1,237.3
|
|
Per common share
|
$
|
5.50
|
|
|
$
|
0.75
|
|
|
$
|
6.50
|
|
|
$
|
0.75
|
|
|
$
|
0.75
|
|
|
$
|
14.25
|
|
Shares outstanding
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Consolidated Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
8,985.8
|
|
|
$
|
8,567.3
|
|
|
$
|
5,029.1
|
|
Cost of product sold(1)
|
7,563.2
|
|
|
6,696.9
|
|
|
3,943.5
|
|
|||
Direct operating expenses(1)
|
455.8
|
|
|
522.1
|
|
|
334.1
|
|
|||
Insurance recovery — business interruption
|
—
|
|
|
—
|
|
|
(3.4
|
)
|
|||
Selling, general and administrative expense(1)
|
113.5
|
|
|
183.4
|
|
|
98.0
|
|
|||
Depreciation and amortization(1)
|
142.8
|
|
|
130.0
|
|
|
90.3
|
|
|||
Operating income
|
$
|
710.5
|
|
|
$
|
1,034.9
|
|
|
$
|
566.6
|
|
Net income
|
522.0
|
|
|
412.6
|
|
|
378.6
|
|
|||
Less: Net income attributable to noncontrolling interest
|
151.3
|
|
|
34.0
|
|
|
32.8
|
|
|||
Net income attributable to CVR Energy Stockholders
|
$
|
370.7
|
|
|
$
|
378.6
|
|
|
$
|
345.8
|
|
Adjusted EBITDA(2)
|
$
|
659.7
|
|
|
$
|
1,264.5
|
|
|
$
|
691.3
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization.
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Consolidated Financial Results
|
|
|
|
|
|
||||||
Depreciation and amortization excluded from cost of product sold
|
$
|
5.0
|
|
|
$
|
3.7
|
|
|
$
|
2.5
|
|
Depreciation and amortization excluded from direct operating expenses
|
134.5
|
|
|
124.1
|
|
|
86.0
|
|
|||
Depreciation and amortization excluded from selling, general and administrative expense
|
3.3
|
|
|
2.2
|
|
|
1.8
|
|
|||
Total depreciation and amortization
|
$
|
142.8
|
|
|
$
|
130.0
|
|
|
$
|
90.3
|
|
(2)
|
EBITDA and Adjusted EBITDA.
EBITDA represents net income before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, loss on disposition of fixed assets, gain (loss) on derivatives, net, current period settlements on derivative contracts, loss on extinguishment of debt and expenses associated with the acquisition of Gary-Williams. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income or cash flow from operations. Management believes that EBITDA and Adjusted EBITDA enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in reviewing our overall financial, operational and economic performance. EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the years ended December 31,
2013
,
2012
and
2011
:
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
|
(unaudited)
|
||||||||||
Net income attributable to CVR Energy stockholders
|
$
|
370.7
|
|
|
$
|
378.6
|
|
|
$
|
345.8
|
|
Add:
|
|
|
|
|
|
||||||
Interest expense and other financing costs, net of interest income
|
49.3
|
|
|
74.5
|
|
|
55.3
|
|
|||
Income tax expense
|
183.7
|
|
|
225.6
|
|
|
209.5
|
|
|||
Depreciation and amortization
|
142.8
|
|
|
130.0
|
|
|
90.3
|
|
|||
EBITDA adjustments included in noncontrolling interest
|
(50.1
|
)
|
|
(7.4
|
)
|
|
(5.2
|
)
|
|||
EBITDA
|
696.4
|
|
|
801.3
|
|
|
695.7
|
|
|||
Add:
|
|
|
|
|
|
||||||
FIFO impacts, (favorable) unfavorable
|
(21.3
|
)
|
|
58.4
|
|
|
(25.6
|
)
|
|||
Share-based compensation
|
18.4
|
|
|
39.1
|
|
|
27.2
|
|
|||
Major scheduled turnaround expenses
|
—
|
|
|
128.5
|
|
|
66.4
|
|
|||
(Gain) loss on derivatives, net
|
(57.1
|
)
|
|
285.6
|
|
|
(78.1
|
)
|
|||
Current period settlement on derivative contracts (a)
|
6.4
|
|
|
(137.6
|
)
|
|
(7.2
|
)
|
|||
Loss on extinguishment of debt
|
26.1
|
|
|
37.5
|
|
|
2.1
|
|
|||
Loss on disposition of fixed assets
|
—
|
|
|
—
|
|
|
2.5
|
|
|||
Expenses associated with proxy matter
|
—
|
|
|
44.2
|
|
|
—
|
|
|||
Expenses associated with the acquisition of Gary-Williams (b)
|
—
|
|
|
11.0
|
|
|
9.1
|
|
|||
Adjustments included in noncontrolling interest
|
(9.2
|
)
|
|
(3.5
|
)
|
|
(0.8
|
)
|
|||
Adjusted EBITDA
|
$
|
659.7
|
|
|
$
|
1,264.5
|
|
|
$
|
691.3
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Consolidated Petroleum Business Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
8,683.5
|
|
|
$
|
8,281.5
|
|
|
$
|
4,751.8
|
|
Cost of product sold(1)
|
7,526.7
|
|
|
6,667.3
|
|
|
3,926.6
|
|
|||
Direct operating expenses(1)(2)
|
361.7
|
|
|
302.8
|
|
|
181.3
|
|
|||
Major scheduled turnaround expenses
|
—
|
|
|
123.7
|
|
|
66.4
|
|
|||
Depreciation and amortization
|
114.3
|
|
|
107.6
|
|
|
69.9
|
|
|||
Gross profit(3)
|
$
|
680.8
|
|
|
$
|
1,080.1
|
|
|
$
|
507.6
|
|
Plus:
|
|
|
|
|
|
||||||
Direct operating expenses and major scheduled turnaround expenses(1)
|
361.7
|
|
|
426.5
|
|
|
247.7
|
|
|||
Depreciation and amortization
|
114.3
|
|
|
107.6
|
|
|
69.9
|
|
|||
Refining margin(4)
|
$
|
1,156.8
|
|
|
$
|
1,614.2
|
|
|
$
|
825.2
|
|
Operating income
|
$
|
603.0
|
|
|
$
|
1,012.5
|
|
|
$
|
465.7
|
|
Adjusted Petroleum EBITDA(5)
|
$
|
712.0
|
|
|
$
|
1,178.9
|
|
|
$
|
580.9
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(dollars per barrel)
|
||||||||||
Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Refining margin(4)
|
$
|
16.90
|
|
|
$
|
26.04
|
|
|
$
|
21.80
|
|
Gross profit(3)
|
$
|
9.94
|
|
|
$
|
17.42
|
|
|
$
|
13.41
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(2)
|
$
|
5.28
|
|
|
$
|
6.88
|
|
|
$
|
6.54
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(6)
|
$
|
5.00
|
|
|
$
|
6.38
|
|
|
$
|
6.38
|
|
Barrels sold (barrels per day)(6)
|
198,142
|
|
|
182,701
|
|
|
106,397
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
||||||
Refining Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Sweet
|
149,147
|
|
|
75.4
|
|
130,414
|
|
|
72.4
|
|
83,538
|
|
|
76.7
|
|||
Medium
|
19,151
|
|
|
9.7
|
|
21,334
|
|
|
11.8
|
|
1,704
|
|
|
1.6
|
|||
Heavy sour
|
19,270
|
|
|
9.8
|
|
17,608
|
|
|
9.8
|
|
18,460
|
|
|
16.9
|
|||
Total crude oil throughput
|
187,568
|
|
|
94.9
|
|
169,356
|
|
|
94.0
|
|
103,702
|
|
|
95.2
|
|||
All other feedstocks and blendstocks
|
10,121
|
|
|
5.1
|
|
10,791
|
|
|
6.0
|
|
5,231
|
|
|
4.8
|
|||
Total throughput
|
197,689
|
|
|
100.0
|
|
180,147
|
|
|
100.0
|
|
108,933
|
|
|
100.0
|
|||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gasoline
|
94,561
|
|
|
47.7
|
|
89,787
|
|
|
49.9
|
|
48,486
|
|
|
44.3
|
|||
Distillate
|
82,089
|
|
|
41.4
|
|
72,804
|
|
|
40.6
|
|
45,535
|
|
|
41.6
|
|||
Other (excluding internally produced fuel)
|
21,617
|
|
|
10.9
|
|
17,262
|
|
|
9.5
|
|
15,385
|
|
|
14.1
|
|||
Total refining production (excluding internally produced fuel)
|
198,267
|
|
|
100.0
|
|
179,853
|
|
|
100.0
|
|
109,406
|
|
|
100.0
|
|||
Product price (dollars per gallon):
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gasoline
|
$
|
2.72
|
|
|
|
|
$
|
2.86
|
|
|
|
|
$
|
2.82
|
|
|
|
Distillate
|
$
|
3.02
|
|
|
|
|
$
|
3.08
|
|
|
|
|
$
|
3.03
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Market Indicators (dollars per barrel)
|
|
|
|
|
|
||||||
West Texas Intermediate (WTI) NYMEX
|
$
|
98.05
|
|
|
$
|
94.15
|
|
|
$
|
95.11
|
|
Crude Oil Differentials:
|
|
|
|
|
|
||||||
WTI less WTS (light/medium sour)
|
2.64
|
|
|
5.40
|
|
|
2.06
|
|
|||
WTI less WCS (heavy sour)
|
24.58
|
|
|
22.53
|
|
|
16.54
|
|
|||
NYMEX Crack Spreads:
|
|
|
|
|
|
||||||
Gasoline
|
21.44
|
|
|
28.55
|
|
|
23.54
|
|
|||
Heating Oil
|
27.60
|
|
|
32.94
|
|
|
29.12
|
|
|||
NYMEX 2-1-1 Crack Spread
|
24.52
|
|
|
30.75
|
|
|
26.33
|
|
|||
PADD II Group 3 Basis:
|
|
|
|
|
|
||||||
Gasoline
|
(4.54
|
)
|
|
(3.11
|
)
|
|
(1.09
|
)
|
|||
Ultra-Low Sulfur Diesel
|
0.58
|
|
|
2.17
|
|
|
1.98
|
|
|||
PADD II Group 3 Product Crack Spread:
|
|
|
|
|
|
||||||
Gasoline
|
16.90
|
|
|
25.45
|
|
|
22.44
|
|
|||
Ultra-Low Sulfur Diesel
|
28.18
|
|
|
35.11
|
|
|
31.10
|
|
|||
PADD II Group 3 2-1-1
|
22.54
|
|
|
30.28
|
|
|
26.77
|
|
(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 does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.
|
(3)
|
Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses and depreciation and amortization. Each of the components used in this calculation are taken directly from the petroleum business' financial results. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.
|
(4)
|
Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating the refineries' performance as a general indication of the amount above the cost of product sold that it is able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from the petroleum business' financial results. Our calculation of refining margin may differ from similar calculations of other companies in the industry, thereby limiting 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 is important to enable investors to better understand and evaluate the petroleum business' ongoing operating results and for greater transparency in the review of our overall business, financial, operational and economic financial performance.
|
(5)
|
Adjusted Petroleum EBITDA represents operating income for the petroleum segment adjusted for (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) major scheduled turnaround expenses, (iv) current period settlements on derivatives contracts, (v) loss on disposition of fixed assets, (vi) depreciation and amortization and (vii) and other income (expense). We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership’s available cash for distribution. Adjusted Petroleum EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted Petroleum EBITDA enables investors to better understand the Refining Partnership’s ability to make distributions to its common unitholders, evaluate the petroleum segment’s ongoing operating results and allows for greater transparency in reviewing our overall financial, operational and economic performance. Adjusted Petroleum EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of operating income for the petroleum segment to Adjusted Petroleum EBITDA for the years ended
December 31, 2013
,
2012
and
2011
:
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
|
(unaudited)
|
||||||||||
Petroleum:
|
|
|
|
|
|
||||||
Petroleum operating income
|
$
|
603.0
|
|
|
$
|
1,012.5
|
|
|
$
|
465.7
|
|
FIFO impacts (favorable), unfavorable(a)
|
(21.3
|
)
|
|
58.4
|
|
|
(25.6
|
)
|
|||
Share-based compensation, non-cash
|
9.5
|
|
|
13.5
|
|
|
8.7
|
|
|||
Major scheduled turnaround expenses(b)
|
—
|
|
|
123.7
|
|
|
66.4
|
|
|||
Current period settlements on derivative contracts(c)
|
6.4
|
|
|
(137.6
|
)
|
|
(7.2
|
)
|
|||
Loss on disposition of assets(d)
|
—
|
|
|
—
|
|
|
2.5
|
|
|||
Depreciation and amortization
|
114.3
|
|
|
107.6
|
|
|
69.9
|
|
|||
Other income, net
|
0.1
|
|
|
0.8
|
|
|
0.5
|
|
|||
Adjusted Petroleum EBITDA
|
$
|
712.0
|
|
|
$
|
1,178.9
|
|
|
$
|
580.9
|
|
(a)
|
FIFO is the petroleum business' basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. 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 a major scheduled turnaround at the Coffeyville refinery in 2011 and 2012 and the Wynnewood refinery in 2012.
|
(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)
|
During the second quarter of 2011, the Company wrote-off an amount associated with the closure of the Phillipsburg terminal.
|
(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 direct operating expenses, which does not include depreciation or amortization expense, and divide the applicable number of barrels sold for the period to derive the metric.
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Coffeyville Refinery Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
5,370.8
|
|
|
$
|
5,692.4
|
|
|
$
|
4,643.9
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
4,648.6
|
|
|
4,566.0
|
|
|
3,823.5
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization)
|
219.4
|
|
|
189.1
|
|
|
177.1
|
|
|||
Major scheduled turnaround expenses
|
—
|
|
|
21.2
|
|
|
66.4
|
|
|||
Depreciation and amortization
|
70.8
|
|
|
69.6
|
|
|
66.0
|
|
|||
Gross profit
|
$
|
432.0
|
|
|
$
|
846.5
|
|
|
$
|
510.9
|
|
Plus:
|
|
|
|
|
|
||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
219.4
|
|
|
210.3
|
|
|
243.5
|
|
|||
Depreciation and amortization
|
70.8
|
|
|
69.6
|
|
|
66.0
|
|
|||
Refining margin
|
$
|
722.2
|
|
|
$
|
1,126.4
|
|
|
$
|
820.4
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(dollars per barrel)
|
||||||||||
Coffeyville Refinery Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Refining margin
|
$
|
17.90
|
|
|
$
|
26.81
|
|
|
$
|
22.34
|
|
Gross profit
|
$
|
10.71
|
|
|
$
|
20.15
|
|
|
$
|
13.91
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
$
|
5.44
|
|
|
$
|
5.01
|
|
|
$
|
6.63
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold
|
$
|
5.00
|
|
|
$
|
4.66
|
|
|
$
|
6.45
|
|
Barrels sold (barrels per day)
|
120,166
|
|
|
123,418
|
|
|
103,430
|
|
|
Year Ended December 31,
|
|||||||||||||
|
2013
|
|
2012
|
|
2011
|
|||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
|||
Coffeyville Refinery Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Sweet
|
90,818
|
|
|
77.1
|
|
91,580
|
|
|
74.3
|
|
80,835
|
|
|
76.5
|
Medium
|
453
|
|
|
0.4
|
|
5,601
|
|
|
4.6
|
|
1,323
|
|
|
1.3
|
Heavy sour
|
19,270
|
|
|
16.3
|
|
17,608
|
|
|
14.3
|
|
18,460
|
|
|
17.5
|
Total crude oil throughput
|
110,541
|
|
|
93.8
|
|
114,789
|
|
|
93.2
|
|
100,618
|
|
|
95.3
|
All other feedstocks and blendstocks
|
7,253
|
|
|
6.2
|
|
8,412
|
|
|
6.8
|
|
4,921
|
|
|
4.7
|
Total throughput
|
117,794
|
|
|
100.0
|
|
123,201
|
|
|
100.0
|
|
105,539
|
|
|
100.0
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Gasoline
|
56,262
|
|
|
46.8
|
|
61,998
|
|
|
49.6
|
|
46,707
|
|
|
44.0
|
Distillate
|
50,353
|
|
|
41.9
|
|
52,429
|
|
|
41.9
|
|
44,414
|
|
|
41.9
|
Other (excluding internally produced fuel)
|
13,499
|
|
|
11.3
|
|
10,629
|
|
|
8.5
|
|
15,000
|
|
|
14.1
|
Total refining production (excluding internally produced fuel)
|
120,114
|
|
|
100.0
|
|
125,056
|
|
|
100.0
|
|
106,121
|
|
|
100.0
|
|
Year Ended December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in millions)
|
||||||
Wynnewood Refinery Financial Results
|
|
|
|
||||
Net sales
|
$
|
3,308.4
|
|
|
$
|
2,587.6
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
2,877.5
|
|
|
2,101.4
|
|
||
Direct operating expenses (exclusive of depreciation and amortization)
|
142.4
|
|
|
113.7
|
|
||
Major scheduled turnaround expenses
|
—
|
|
|
102.5
|
|
||
Depreciation and amortization
|
38.6
|
|
|
34.5
|
|
||
Gross profit
|
$
|
249.9
|
|
|
$
|
235.5
|
|
Plus:
|
|
|
|
||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
142.4
|
|
|
216.2
|
|
||
Depreciation and amortization
|
38.6
|
|
|
34.5
|
|
||
Refining margin
|
$
|
430.9
|
|
|
$
|
486.2
|
|
|
Year Ended December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(dollars per barrel)
|
||||||
Wynnewood Refinery Key Operating Statistics
|
|
|
|
||||
Per crude oil throughput barrel:
|
|
|
|
||||
Refining margin
|
$
|
15.33
|
|
|
$
|
24.34
|
|
Gross profit
|
$
|
8.89
|
|
|
$
|
11.79
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
$
|
5.06
|
|
|
$
|
10.83
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold
|
$
|
5.00
|
|
|
$
|
9.96
|
|
Barrels sold (barrels per day)
|
77,976
|
|
|
59,282
|
|
|
Year Ended December 31,
|
||||||||
|
2013
|
|
2012
|
||||||
|
|
|
%
|
|
|
|
%
|
||
Wynnewood Refinery Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
||
Throughput:
|
|
|
|
|
|
|
|
||
Sweet
|
58,329
|
|
|
73.0
|
|
38,834
|
|
|
68.2
|
Medium
|
18,698
|
|
|
23.4
|
|
15,733
|
|
|
27.6
|
Heavy sour
|
—
|
|
|
—
|
|
—
|
|
|
—
|
Total crude oil throughput
|
77,027
|
|
|
96.4
|
|
54,567
|
|
|
95.8
|
All other feedstocks and blendstocks
|
2,868
|
|
|
3.6
|
|
2,379
|
|
|
4.2
|
Total throughput
|
79,895
|
|
|
100.0
|
|
56,946
|
|
|
100.0
|
Production:
|
|
|
|
|
|
|
|
||
Gasoline
|
38,299
|
|
|
49.0
|
|
27,789
|
|
|
50.6
|
Distillate
|
31,736
|
|
|
40.6
|
|
20,375
|
|
|
37.2
|
Other (excluding internally produced fuel)
|
8,118
|
|
|
10.4
|
|
6,633
|
|
|
12.2
|
Total refining production (excluding internally produced fuel)
|
78,153
|
|
|
100.0
|
|
54,797
|
|
|
100.0
|
|
Year Ended December 31, 2013
|
|
Year Ended December 31, 2012
|
|
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
|
37.8
|
|
|
$
|
114.29
|
|
|
$
|
4,330.0
|
|
|
35.6
|
|
|
$
|
120.14
|
|
|
$
|
4,283.1
|
|
|
2.2
|
|
|
$
|
46.9
|
|
|
$
|
(221.8
|
)
|
|
$
|
268.7
|
|
Distillate
|
30.6
|
|
|
$
|
126.79
|
|
|
$
|
3,880.6
|
|
|
27.5
|
|
|
$
|
129.51
|
|
|
$
|
3,563.9
|
|
|
3.1
|
|
|
$
|
316.7
|
|
|
$
|
(83.4
|
)
|
|
$
|
400.1
|
|
(1)
|
Barrels in millions
|
(2)
|
Sales dollars in millions
|
|
Year Ended December 31, 2012
|
|
Year Ended December 31, 2011
|
|
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
|
35.6
|
|
|
$
|
120.14
|
|
|
$
|
4,283.1
|
|
|
19.7
|
|
|
$
|
118.38
|
|
|
$
|
2,337.7
|
|
|
15.9
|
|
|
$
|
1,945.4
|
|
|
$
|
63.1
|
|
|
$
|
1,882.3
|
|
Distillate
|
27.5
|
|
|
$
|
129.51
|
|
|
$
|
3,563.9
|
|
|
16.6
|
|
|
$
|
127.27
|
|
|
$
|
2,115.3
|
|
|
10.9
|
|
|
$
|
1,448.6
|
|
|
$
|
61.5
|
|
|
$
|
1,387.1
|
|
(1)
|
Barrels in millions
|
(2)
|
Sales dollars in millions
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Nitrogen Fertilizer Business Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
323.7
|
|
|
$
|
302.3
|
|
|
$
|
302.9
|
|
Cost of product sold(1)
|
58.1
|
|
|
46.1
|
|
|
42.5
|
|
|||
Direct operating expenses(1)
|
94.1
|
|
|
90.8
|
|
|
86.5
|
|
|||
Major scheduled turnaround expenses
|
—
|
|
|
4.8
|
|
|
—
|
|
|||
Insurance recovery — business interruption
|
—
|
|
|
—
|
|
|
(3.4
|
)
|
|||
Selling, general and administrative(1)
|
21.0
|
|
|
24.1
|
|
|
22.2
|
|
|||
Depreciation and amortization
|
25.6
|
|
|
20.7
|
|
|
18.9
|
|
|||
Operating income
|
$
|
124.9
|
|
|
$
|
115.8
|
|
|
$
|
136.2
|
|
Adjusted Nitrogen Fertilizer EBITDA(2)
|
$
|
152.8
|
|
|
$
|
148.2
|
|
|
$
|
162.6
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Key Operating Statistics
|
|
|
|
|
|
||||||
Production (thousand tons):
|
|
|
|
|
|
||||||
Ammonia (gross produced)(3)
|
402.0
|
|
|
390.0
|
|
|
411.2
|
|
|||
Ammonia (net available for sale)(3)(4)
|
37.9
|
|
|
124.6
|
|
|
116.8
|
|
|||
UAN
|
930.6
|
|
|
643.8
|
|
|
714.1
|
|
|||
Pet coke consumed (thousand tons)
|
487.0
|
|
|
487.3
|
|
|
517.3
|
|
|||
Pet coke (cost per ton)
|
$
|
30
|
|
|
$
|
33
|
|
|
$
|
33
|
|
Sales (thousand tons)(5):
|
|
|
|
|
|
||||||
Ammonia
|
40.5
|
|
|
127.8
|
|
|
112.8
|
|
|||
UAN
|
904.6
|
|
|
643.5
|
|
|
709.3
|
|
|||
Product pricing (plant gate) (dollars per ton)(5):
|
|
|
|
|
|
||||||
Ammonia
|
$
|
643
|
|
|
$
|
613
|
|
|
$
|
579
|
|
UAN
|
$
|
282
|
|
|
$
|
303
|
|
|
$
|
284
|
|
On-stream factor(6):
|
|
|
|
|
|
||||||
Gasification
|
95.6
|
%
|
|
92.6
|
%
|
|
99.0
|
%
|
|||
Ammonia
|
94.4
|
%
|
|
91.1
|
%
|
|
97.7
|
%
|
|||
UAN
|
91.9
|
%
|
|
86.4
|
%
|
|
95.5
|
%
|
|||
Reconciliation to net sales (dollars in millions):
|
|
|
|
|
|
||||||
Sales net plate gate
|
$
|
281.5
|
|
|
$
|
273.5
|
|
|
$
|
266.6
|
|
Freight in revenue
|
30.2
|
|
|
22.4
|
|
|
22.1
|
|
|||
Hydrogen
|
11.4
|
|
|
6.4
|
|
|
14.2
|
|
|||
Other revenue
|
0.6
|
|
|
—
|
|
|
—
|
|
|||
Total net sales
|
$
|
323.7
|
|
|
$
|
302.3
|
|
|
$
|
302.9
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Market Indicators
|
|
|
|
|
|
||||||
Natural gas NYMEX (dollars per MMBtu)
|
$
|
3.73
|
|
|
$
|
2.83
|
|
|
$
|
4.03
|
|
Ammonia — Southern Plains (dollars per ton)
|
$
|
581
|
|
|
$
|
647
|
|
|
$
|
619
|
|
UAN — Corn belt (dollars per ton)
|
$
|
337
|
|
|
$
|
369
|
|
|
$
|
379
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization.
|
(2)
|
Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for (i) share-based compensation, non-cash, (ii) major scheduled turnaround expenses, (iii) depreciation and amortization and (iv) other income (expense). We present Adjusted Nitrogen Fertilizer EBITDA because it is a key measure used in material covenants in the Nitrogen Fertilizer Partnership's credit facility and because it is the starting point for the Nitrogen Fertilizer Partnership's available cash for distribution. Adjusted Nitrogen Fertilizer EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted EBITDA enables investors to better understand and evaluate the Nitrogen Fertilizer Partnership’s ability to make distributions to its common unitholders and its compliance with the covenants contained in the Nitrogen Fertilizer Partnership's credit facility. Adjusted Nitrogen Fertilizer EBITDA presented by other companies may not be comparable to our presentation, since each company may define this term differently. Below is a reconciliation of operating income to Adjusted EBITDA for the nitrogen fertilizer segment for the years ended
December 31, 2013
,
2012
and
2011
:
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
|
(unaudited)
|
||||||||||
Nitrogen Fertilizer:
|
|
|
|
|
|
||||||
Nitrogen fertilizer operating income
|
$
|
124.9
|
|
|
$
|
115.8
|
|
|
$
|
136.2
|
|
Share-based compensation, non-cash
|
2.2
|
|
|
6.8
|
|
|
7.3
|
|
|||
Depreciation and amortization
|
25.6
|
|
|
20.7
|
|
|
18.9
|
|
|||
Major scheduled turnaround expenses(a)
|
—
|
|
|
4.8
|
|
|
—
|
|
|||
Other income, net
|
0.1
|
|
|
0.1
|
|
|
0.2
|
|
|||
Adjusted Nitrogen Fertilizer EBITDA
|
$
|
152.8
|
|
|
$
|
148.2
|
|
|
$
|
162.6
|
|
(a)
|
Represents expense associated with a major scheduled turnaround at the nitrogen fertilizer plant.
|
(3)
|
Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. As a result of the completion of the UAN expansion project in February 2013, the Nitrogen Fertilizer Partnership now upgrades substantially all of the ammonia it produces into UAN. Net tons available for sale represent the ammonia available for sale that was not upgraded into UAN.
|
(4)
|
In addition to produced ammonia, the Nitrogen Fertilizer Partnership acquired approximately
17,000
tons of ammonia, which was upgraded to UAN during the year ended
December 31, 2013
.
|
(5)
|
Plant gate sales per ton represent net sales less freight costs and hydrogen revenue divided by product sales volume in tons in the reporting period and is shown in order to provide a pricing measure that is comparable across the fertilizer industry.
|
(6)
|
On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is included as a measure of operating efficiency. Excluding the impacts of the UAN expansion coming on-line, the planned downtime associated with replacement of damaged catalyst, the unplanned Linde air separation unit outages and the unplanned downtime associated with weather issues, (i) the on-stream factors in
2013
would have been
99.5%
for gasifier,
98.9%
for ammonia and
98.0%
for UAN. Excluding the impact of the Linde air separation unit outage and the major scheduled turnaround, (ii) the on-stream factors in
2012
would have been
98.1%
for gasifier,
97.1%
for ammonia and
92.8%
for UAN. Excluding the impact of the Linde air separation unit outage, (iii) the on-stream factors in
2011
would have been
99.2%
for gasifier,
98.0%
for ammonia and
95.7%
for UAN.
|
|
Year Ended December 31, 2013
|
|
Year Ended December 31, 2012
|
|
Total Variance
|
|
|
|
|
|||||||||||||||||||||||||||
|
Volume(1)
|
|
$ per ton(2)
|
|
Sales $(3)
|
|
Volume(1)
|
|
$ per ton(2)
|
|
Sales $(3)
|
|
Volume(1)
|
|
Sales $(3)
|
|
Price
Variance
|
|
Volume
Variance
|
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|||||||||||||||||||
UAN
|
904,596
|
|
|
$
|
315
|
|
|
$
|
284.9
|
|
|
643,514
|
|
|
$
|
334
|
|
|
$
|
215.1
|
|
|
261,082
|
|
|
$
|
69.8
|
|
|
$
|
(12.4
|
)
|
|
$
|
82.2
|
|
Ammonia
|
40,535
|
|
|
$
|
660
|
|
|
$
|
26.8
|
|
|
127,843
|
|
|
$
|
632
|
|
|
$
|
80.8
|
|
|
(87,308
|
)
|
|
$
|
(54.0
|
)
|
|
$
|
3.6
|
|
|
$
|
(57.6
|
)
|
Hydrogen
|
1,165,300
|
|
|
$
|
10
|
|
|
$
|
11.4
|
|
|
624,242
|
|
|
$
|
10
|
|
|
$
|
6.4
|
|
|
541,058
|
|
|
$
|
5.0
|
|
|
$
|
(0.3
|
)
|
|
$
|
5.3
|
|
(1)
|
UAN and ammonia sales volumes are in tons. Hydrogen sales volumes are in MSCF.
|
(2)
|
Includes freight charges.
|
(3)
|
Sales dollars in millions.
|
|
Year Ended December 31, 2012
|
|
Year Ended December 31, 2011
|
|
Total Variance
|
|
|
|
|
|||||||||||||||||||||||||||
|
Volume(1)
|
|
$ per ton(2)
|
|
Sales $(3)
|
|
Volume(1)
|
|
$ per ton(2)
|
|
Sales $(3)
|
|
Volume(1)
|
|
Sales $(3)
|
|
Price
Variance
|
|
Volume
Variance
|
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|||||||||||||||||||
UAN
|
643,514
|
|
|
$
|
334
|
|
|
$
|
215.1
|
|
|
709,280
|
|
|
$
|
312
|
|
|
$
|
221.5
|
|
|
(65,766
|
)
|
|
$
|
(6.4
|
)
|
|
$
|
14.2
|
|
|
$
|
(20.6
|
)
|
Ammonia
|
127,843
|
|
|
$
|
632
|
|
|
$
|
80.8
|
|
|
112,775
|
|
|
$
|
596
|
|
|
$
|
67.2
|
|
|
15,068
|
|
|
$
|
13.6
|
|
|
$
|
4.6
|
|
|
$
|
9.0
|
|
Hydrogen
|
624,242
|
|
|
$
|
10
|
|
|
$
|
6.4
|
|
|
1,389,796
|
|
|
$
|
10
|
|
|
$
|
14.2
|
|
|
(765,554
|
)
|
|
$
|
(7.8
|
)
|
|
$
|
(0.1
|
)
|
|
$
|
(7.7
|
)
|
(1)
|
Ammonia and UAN sales volumes are in tons. Hydrogen sales volumes are in MSCF.
|
(2)
|
Includes freight charges.
|
(3)
|
Sales dollars in millions.
|
|
Year Ended December 31,
|
||||||
|
2013 Actual
|
|
2014 Estimate
|
||||
|
(in millions)
|
||||||
Petroleum Business (the Refining Partnership):
|
|
|
|
||||
Coffeyville refinery:
|
|
|
|
||||
Maintenance
|
$
|
52.6
|
|
|
$
|
115.9
|
|
Growth
|
3.6
|
|
|
26.3
|
|
||
Coffeyville refinery total capital
|
56.2
|
|
|
142.2
|
|
||
Wynnewood refinery:
|
|
|
|
||||
Maintenance
|
105.3
|
|
|
108.7
|
|
||
Growth
|
24.9
|
|
|
70.4
|
|
||
Wynnewood refinery total capital
|
130.2
|
|
|
179.1
|
|
||
Other Petroleum
:
|
|
|
|
||||
Maintenance
|
11.7
|
|
|
15.5
|
|
||
Growth
|
6.4
|
|
|
6.4
|
|
||
Other petroleum total capital
|
18.1
|
|
|
21.9
|
|
||
Petroleum business total capital
|
204.5
|
|
|
343.2
|
|
||
Nitrogen Fertilizer Business (the Nitrogen Fertilizer Partnership):
|
|
|
|
||||
Maintenance
|
3.5
|
|
|
11.0
|
|
||
Growth
|
40.3
|
|
|
7.0
|
|
||
Nitrogen fertilizer business total capital
|
43.8
|
|
|
18.0
|
|
||
Corporate
|
8.2
|
|
|
1.7
|
|
||
Total capital spending
|
$
|
256.5
|
|
|
$
|
362.9
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
$
|
440.1
|
|
|
$
|
762.6
|
|
|
$
|
278.6
|
|
Investing activities
|
(250.3
|
)
|
|
(210.7
|
)
|
|
(674.4
|
)
|
|||
Financing activities
|
(243.7
|
)
|
|
(44.2
|
)
|
|
584.1
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
$
|
(53.9
|
)
|
|
$
|
507.7
|
|
|
$
|
188.3
|
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
Thereafter
|
||||||||||||||
|
(in millions)
|
||||||||||||||||||||||||||
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Long-term debt(1)
|
$
|
625.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
125.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
500.0
|
|
Operating leases(2)
|
36.7
|
|
|
9.5
|
|
|
7.9
|
|
|
6.9
|
|
|
4.2
|
|
|
3.0
|
|
|
5.2
|
|
|||||||
Capital lease obligations(3)
|
51.2
|
|
|
1.3
|
|
|
1.4
|
|
|
1.6
|
|
|
1.8
|
|
|
2.1
|
|
|
43.0
|
|
|||||||
Unconditional purchase obligations(4)
|
1,418.4
|
|
|
121.4
|
|
|
109.5
|
|
|
102.4
|
|
|
101.2
|
|
|
101.2
|
|
|
882.7
|
|
|||||||
Environmental liabilities(5)
|
1.8
|
|
|
0.3
|
|
|
0.2
|
|
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
|
1.0
|
|
|||||||
Interest payments(6)
|
354.3
|
|
|
42.2
|
|
|
42.1
|
|
|
38.6
|
|
|
37.1
|
|
|
36.9
|
|
|
157.4
|
|
|||||||
Total
|
$
|
2,487.4
|
|
|
$
|
174.7
|
|
|
$
|
161.1
|
|
|
$
|
274.6
|
|
|
$
|
144.4
|
|
|
$
|
143.3
|
|
|
$
|
1,589.3
|
|
Other Commercial Commitments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Standby letters of credit(7)
|
$
|
27.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
(1)
|
Consists of the 2022 Notes and the Nitrogen Fertilizer Partnership's term loan facility outstanding on
December 31, 2013
.
|
(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.
|
(3)
|
The amount includes commitments under capital lease arrangements for equipment and for two leases associated with pipelines and storage and terminal equipment associated with the Wynnewood Acquisition.
|
(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 electric supply agreement with the city of Coffeyville, (c) a product supply agreement with Linde, (d) a pet coke supply agreement with HollyFrontier Corporation with a term ending in December 2014, subject to renewal, (e) commitments related to our biofuels blending obligation and (f) approximately
$973.0 million
payable ratably over
seventeen
years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP ("TransCanada"). Under the agreements, CRRM receives transportation of at least
25,000
barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of
twenty
years on TransCanada's Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011.
|
(5)
|
Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. 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 "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 obligations as of
December 31, 2013
.
|
(7)
|
Standby letters of credit issued against our Amended and Restated ABL Credit Facility include
$0.2 million
of letters of credit issued in connection with environmental liabilities,
$26.3 million
in letters of credit to secure transportation services for crude oil and a
$0.6 million
letter of credit issued to guarantee a portion of our insurance policy.
|
•
|
general economic conditions;
|
•
|
fertilizer pricing;
|
•
|
input costs; and
|
•
|
customer outlook.
|
•
|
lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows;
|
•
|
hedge the value of inventories in excess of minimum required inventories; and
|
•
|
manage existing derivative positions related to a change in anticipated operations and market conditions.
|
•
|
Time Basis
— In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will be weighted differently than the swap price as the result of timing.
|
•
|
Location Basis
— In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area.
|
Audited Financial Statements:
|
Page
Number
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in millions, except share data)
|
||||||
ASSETS
|
|||||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
842.1
|
|
|
$
|
896.0
|
|
Accounts receivable, net of allowance for doubtful accounts of $0.9 and $2.0, respectively
|
241.9
|
|
|
210.6
|
|
||
Inventories
|
526.6
|
|
|
528.1
|
|
||
Prepaid expenses and other current assets
|
82.5
|
|
|
54.4
|
|
||
Insurance receivable
|
—
|
|
|
1.3
|
|
||
Income tax receivable
|
10.8
|
|
|
4.1
|
|
||
Deferred income taxes
|
27.8
|
|
|
57.4
|
|
||
Due from parent
|
—
|
|
|
9.2
|
|
||
Total current assets
|
1,731.7
|
|
|
1,761.1
|
|
||
Property, plant, and equipment, net of accumulated depreciation
|
1,864.4
|
|
|
1,782.9
|
|
||
Intangible assets, net
|
0.3
|
|
|
0.3
|
|
||
Goodwill
|
41.0
|
|
|
41.0
|
|
||
Deferred financing costs, net
|
11.2
|
|
|
16.6
|
|
||
Other long-term assets
|
17.2
|
|
|
9.0
|
|
||
Total assets
|
$
|
3,665.8
|
|
|
$
|
3,610.9
|
|
LIABILITIES AND EQUITY
|
|||||||
Current liabilities:
|
|
|
|
||||
Note payable and capital lease obligations
|
$
|
1.3
|
|
|
$
|
1.1
|
|
Accounts payable
|
377.9
|
|
|
440.1
|
|
||
Personnel accruals
|
45.8
|
|
|
51.2
|
|
||
Accrued taxes other than income taxes
|
31.5
|
|
|
36.7
|
|
||
Due to parent
|
0.1
|
|
|
—
|
|
||
Deferred revenue
|
0.7
|
|
|
1.0
|
|
||
Other current liabilities
|
44.2
|
|
|
95.6
|
|
||
Total current liabilities
|
501.5
|
|
|
625.7
|
|
||
Long-term liabilities:
|
|
|
|
||||
Long-term debt and capital lease obligations, net of current portion
|
674.9
|
|
|
897.1
|
|
||
Accrued environmental liabilities, net of current portion
|
1.2
|
|
|
1.6
|
|
||
Deferred income taxes
|
601.7
|
|
|
386.9
|
|
||
Other long-term liabilities
|
51.1
|
|
|
39.5
|
|
||
Total long-term liabilities
|
1,328.9
|
|
|
1,325.1
|
|
||
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
|
1,114.4
|
|
|
582.3
|
|
||
Retained earnings
|
76.2
|
|
|
945.4
|
|
||
Treasury stock, 98,610 shares at cost
|
(2.3
|
)
|
|
(2.3
|
)
|
||
Accumulated other comprehensive loss, net of tax
|
(0.6
|
)
|
|
(1.2
|
)
|
||
Total CVR stockholders' equity
|
1,188.6
|
|
|
1,525.1
|
|
||
Noncontrolling interest
|
646.8
|
|
|
135.0
|
|
||
Total equity
|
1,835.4
|
|
|
1,660.1
|
|
||
Total liabilities and equity
|
$
|
3,665.8
|
|
|
$
|
3,610.9
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions, except per share data)
|
||||||||||
Net sales
|
$
|
8,985.8
|
|
|
$
|
8,567.3
|
|
|
$
|
5,029.1
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of product sold (exclusive of depreciation and amortization)
|
7,563.2
|
|
|
6,696.9
|
|
|
3,943.5
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization)
|
455.8
|
|
|
522.1
|
|
|
334.1
|
|
|||
Insurance recovery — business interruption
|
—
|
|
|
—
|
|
|
(3.4
|
)
|
|||
Selling, general and administrative expenses (exclusive of depreciation and amortization)
|
113.5
|
|
|
183.4
|
|
|
98.0
|
|
|||
Depreciation and amortization
|
142.8
|
|
|
130.0
|
|
|
90.3
|
|
|||
Total operating costs and expenses
|
8,275.3
|
|
|
7,532.4
|
|
|
4,462.5
|
|
|||
Operating income
|
710.5
|
|
|
1,034.9
|
|
|
566.6
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense and other financing costs
|
(50.5
|
)
|
|
(75.4
|
)
|
|
(55.8
|
)
|
|||
Interest income
|
1.2
|
|
|
0.9
|
|
|
0.5
|
|
|||
Gain (loss) on derivatives, net
|
57.1
|
|
|
(285.6
|
)
|
|
78.1
|
|
|||
Loss on extinguishment of debt
|
(26.1
|
)
|
|
(37.5
|
)
|
|
(2.1
|
)
|
|||
Other income, net
|
13.5
|
|
|
0.9
|
|
|
0.8
|
|
|||
Total other income (expense)
|
(4.8
|
)
|
|
(396.7
|
)
|
|
21.5
|
|
|||
Income before income taxes
|
705.7
|
|
|
638.2
|
|
|
588.1
|
|
|||
Income tax expense
|
183.7
|
|
|
225.6
|
|
|
209.5
|
|
|||
Net income
|
522.0
|
|
|
412.6
|
|
|
378.6
|
|
|||
Less: Net income attributable to noncontrolling interest
|
151.3
|
|
|
34.0
|
|
|
32.8
|
|
|||
Net income attributable to CVR Energy Stockholders
|
$
|
370.7
|
|
|
$
|
378.6
|
|
|
$
|
345.8
|
|
|
|
|
|
|
|
||||||
Basic earnings per share
|
$
|
4.27
|
|
|
$
|
4.36
|
|
|
$
|
4.00
|
|
Diluted earnings per share
|
$
|
4.27
|
|
|
$
|
4.33
|
|
|
$
|
3.94
|
|
|
|
|
|
|
|
||||||
Weighted-average common shares outstanding:
|
|
|
|
|
|
||||||
Basic
|
86.8
|
|
|
86.8
|
|
|
86.5
|
|
|||
Diluted
|
86.8
|
|
|
87.4
|
|
|
87.8
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Net income
|
$
|
522.0
|
|
|
$
|
412.6
|
|
|
$
|
378.6
|
|
Other comprehensive income (loss):
|
|
|
|
|
|
||||||
Unrealized gain on available-for-sale securities, net of tax of $2.4, $0 and $0, respectively
|
3.7
|
|
|
—
|
|
|
—
|
|
|||
Net gain reclassified into income on sale of available-for-sale-securities, net of tax of $(2.4), $0 and $0, respectively (Note 16)
|
(3.7
|
)
|
|
—
|
|
|
—
|
|
|||
Change in fair value of interest rate swap, net of tax of $0, $(0.4) and $(1.2), respectively
|
(0.2
|
)
|
|
(1.0
|
)
|
|
(1.9
|
)
|
|||
Net loss reclassified into income on settlement of interest rate swap, net of tax of $0.3, $0.3 and $0.1, respectively (Note 17)
|
0.8
|
|
|
0.7
|
|
|
0.2
|
|
|||
Total other comprehensive income (loss)
|
0.6
|
|
|
(0.3
|
)
|
|
(1.7
|
)
|
|||
Comprehensive income
|
522.6
|
|
|
412.3
|
|
|
376.9
|
|
|||
Less: Comprehensive income attributable to noncontrolling interest
|
151.5
|
|
|
33.9
|
|
|
32.1
|
|
|||
Comprehensive income attributable to CVR Energy Stockholders
|
$
|
371.1
|
|
|
$
|
378.4
|
|
|
$
|
344.8
|
|
|
Common Stockholders
|
|
|
|
|
|||||||||||||||||||||||||||||
|
Shares
Issued
|
|
$0.01 Par
Value
Common
Stock
|
|
Additional
Paid-In
Capital
|
|
Retained
Earnings
|
|
Treasury
Stock
|
|
Accumulated
Other
Comprehensive
Income (loss)
|
|
Total CVR
Stockholders'
Equity
|
|
Noncontrolling
Interest
|
|
Total
Equity
|
|||||||||||||||||
|
(in millions, except share data)
|
|||||||||||||||||||||||||||||||||
Balance at December 31, 2010
|
86,435,672
|
|
|
$
|
0.9
|
|
|
$
|
467.9
|
|
|
$
|
221.0
|
|
|
$
|
(0.2
|
)
|
|
$
|
—
|
|
|
$
|
689.6
|
|
|
$
|
10.6
|
|
|
$
|
700.2
|
|
Impact from the issuance of CVR Partners common units to the public
|
—
|
|
|
—
|
|
|
118.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
118.2
|
|
|
136.9
|
|
|
255.1
|
|
||||||||
Purchase of Managing General Partnership Interest and incentive distribution rights
|
—
|
|
|
—
|
|
|
(15.4
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(15.4
|
)
|
|
(10.6
|
)
|
|
(26.0
|
)
|
||||||||
Distributions to noncontrolling interest holders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(21.6
|
)
|
|
(21.6
|
)
|
||||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
15.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
15.8
|
|
|
0.7
|
|
|
16.5
|
|
||||||||
Excess tax benefit of share-based compensation
|
—
|
|
|
—
|
|
|
2.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.3
|
|
|
—
|
|
|
2.3
|
|
||||||||
Issuance of common stock to directors
|
831
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Issuance of stock from treasury
|
—
|
|
|
—
|
|
|
(1.5
|
)
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Purchase of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3.6
|
)
|
|
—
|
|
|
(3.6
|
)
|
|
—
|
|
|
(3.6
|
)
|
||||||||
Vesting of non-vested stock awards
|
470,257
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Redemption of common units
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
(0.1
|
)
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
345.8
|
|
|
—
|
|
|
—
|
|
|
345.8
|
|
|
32.8
|
|
|
378.6
|
|
||||||||
Net loss on interest rate swaps, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1.0
|
)
|
|
(1.0
|
)
|
|
(0.7
|
)
|
|
(1.7
|
)
|
||||||||
Balance at December 31, 2011
|
86,906,760
|
|
|
$
|
0.9
|
|
|
$
|
587.2
|
|
|
$
|
566.8
|
|
|
$
|
(2.3
|
)
|
|
$
|
(1.0
|
)
|
|
$
|
1,151.6
|
|
|
$
|
148.1
|
|
|
$
|
1,299.7
|
|
Distributions to noncontrolling interest holders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(48.8
|
)
|
|
(48.8
|
)
|
||||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
5.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5.1
|
|
|
2.1
|
|
|
7.2
|
|
||||||||
Modification and reclassification of equity share-based compensation award to liability based award
|
—
|
|
|
—
|
|
|
(9.9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(9.9
|
)
|
|
—
|
|
|
(9.9
|
)
|
||||||||
Modification and reclassification of subsidiary equity share-based compensation award to liability based award
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
(0.2
|
)
|
|
(0.5
|
)
|
||||||||
Exercise of stock options
|
22,900
|
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
0.4
|
|
||||||||
Redemption of common units
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
(0.1
|
)
|
|
(0.3
|
)
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
378.6
|
|
|
—
|
|
|
—
|
|
|
378.6
|
|
|
34.0
|
|
|
412.6
|
|
||||||||
Net loss on interest rate swaps, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
|
(0.1
|
)
|
|
(0.3
|
)
|
||||||||
Balance at December 31, 2012
|
86,929,660
|
|
|
$
|
0.9
|
|
|
$
|
582.3
|
|
|
$
|
945.4
|
|
|
$
|
(2.3
|
)
|
|
$
|
(1.2
|
)
|
|
$
|
1,525.1
|
|
|
$
|
135.0
|
|
|
$
|
1,660.1
|
|
January issuance of CVR Refining's common units to the public, net of $148.0 tax impact
|
—
|
|
|
—
|
|
|
229.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
229.3
|
|
|
276.4
|
|
|
505.7
|
|
||||||||
May issuance of CVR Refining's common units to the public, net of $96.0 tax impact
|
—
|
|
|
—
|
|
|
148.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
148.9
|
|
|
148.7
|
|
|
297.6
|
|
||||||||
Sale of CVR Refining's common units to affiliate, net of $15.2 tax impact
|
—
|
|
|
—
|
|
|
23.6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
23.6
|
|
|
22.7
|
|
|
46.3
|
|
||||||||
Secondary offering of CVR Partners' common units to public, net of $88.5 tax impact
|
—
|
|
|
—
|
|
|
129.7
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
129.9
|
|
|
74.1
|
|
|
204.0
|
|
||||||||
Dividends paid to CVR Energy stockholders
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,237.3
|
)
|
|
—
|
|
|
—
|
|
|
(1,237.3
|
)
|
|
—
|
|
|
(1,237.3
|
)
|
||||||||
Distributions from CVR Partners to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(50.0
|
)
|
|
(50.0
|
)
|
||||||||
Distributions from CVR Refining to public unitholders
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(114.2
|
)
|
|
(114.2
|
)
|
||||||||
Share-based compensation
|
—
|
|
|
—
|
|
|
1.0
|
|
|
(2.6
|
)
|
|
—
|
|
|
—
|
|
|
(1.6
|
)
|
|
2.8
|
|
|
1.2
|
|
||||||||
Excess tax deficiency from share-based compensation
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
(0.1
|
)
|
||||||||
Redemption of common units
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
(0.2
|
)
|
|
(0.5
|
)
|
||||||||
Net income
|
—
|
|
|
—
|
|
|
—
|
|
|
370.7
|
|
|
—
|
|
|
—
|
|
|
370.7
|
|
|
151.3
|
|
|
522.0
|
|
||||||||
Net gain on interest rate swaps, net of tax
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
0.4
|
|
|
0.2
|
|
|
0.6
|
|
||||||||
Balance at December 31, 2013
|
86,929,660
|
|
|
$
|
0.9
|
|
|
$
|
1,114.4
|
|
|
$
|
76.2
|
|
|
$
|
(2.3
|
)
|
|
$
|
(0.6
|
)
|
|
$
|
1,188.6
|
|
|
$
|
646.8
|
|
|
$
|
1,835.4
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
522.0
|
|
|
$
|
412.6
|
|
|
$
|
378.6
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
142.8
|
|
|
130.0
|
|
|
90.3
|
|
|||
Allowance for doubtful accounts
|
(1.1
|
)
|
|
0.7
|
|
|
0.6
|
|
|||
Amortization of deferred financing costs
|
2.9
|
|
|
7.4
|
|
|
4.6
|
|
|||
Amortization of original issue discount
|
—
|
|
|
0.5
|
|
|
0.5
|
|
|||
Amortization of original issue premium
|
—
|
|
|
(2.8
|
)
|
|
(0.1
|
)
|
|||
Deferred income taxes
|
(93.3
|
)
|
|
(17.3
|
)
|
|
62.7
|
|
|||
Excess income tax (benefit) deficiency of share-based compensation
|
0.1
|
|
|
—
|
|
|
(2.3
|
)
|
|||
Loss on disposition of assets
|
0.1
|
|
|
1.6
|
|
|
3.4
|
|
|||
Loss on extinguishment of debt
|
26.1
|
|
|
37.5
|
|
|
2.1
|
|
|||
Share-based compensation
|
18.4
|
|
|
39.1
|
|
|
27.2
|
|
|||
Gain on sale of available-for-sale securities
|
(6.1
|
)
|
|
—
|
|
|
—
|
|
|||
(Gain) loss on derivatives, net
|
(57.1
|
)
|
|
285.6
|
|
|
(78.1
|
)
|
|||
Current period settlements on derivative contracts
|
6.4
|
|
|
(137.6
|
)
|
|
(7.2
|
)
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(30.2
|
)
|
|
(28.1
|
)
|
|
55.4
|
|
|||
Inventories
|
1.5
|
|
|
108.0
|
|
|
(175.5
|
)
|
|||
Prepaid expenses and other current assets
|
(30.0
|
)
|
|
(9.3
|
)
|
|
(8.8
|
)
|
|||
Insurance receivable
|
—
|
|
|
(1.0
|
)
|
|
(12.3
|
)
|
|||
Due (to) from parent
|
9.1
|
|
|
(9.2
|
)
|
|
—
|
|
|||
Business interruption insurance proceeds
|
—
|
|
|
—
|
|
|
3.4
|
|
|||
Insurance proceeds on Coffeyville Refinery incident
|
1.3
|
|
|
0.7
|
|
|
4.0
|
|
|||
Other long-term assets
|
(0.5
|
)
|
|
0.3
|
|
|
(1.6
|
)
|
|||
Accounts payable
|
(38.7
|
)
|
|
(54.4
|
)
|
|
5.8
|
|
|||
Accrued income taxes
|
(6.6
|
)
|
|
23.6
|
|
|
(35.8
|
)
|
|||
Deferred revenue
|
(0.3
|
)
|
|
(8.1
|
)
|
|
(9.7
|
)
|
|||
Other current liabilities
|
(26.7
|
)
|
|
(17.3
|
)
|
|
(27.3
|
)
|
|||
Accrued environmental liabilities
|
(0.4
|
)
|
|
0.1
|
|
|
(1.1
|
)
|
|||
Other long-term liabilities
|
0.4
|
|
|
—
|
|
|
(0.2
|
)
|
|||
Net cash provided by operating activities
|
440.1
|
|
|
762.6
|
|
|
278.6
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(256.5
|
)
|
|
(212.2
|
)
|
|
(91.2
|
)
|
|||
Proceeds from sale of assets
|
0.1
|
|
|
0.5
|
|
|
0.1
|
|
|||
Insurance proceeds for UAN reactor rupture
|
—
|
|
|
1.0
|
|
|
2.7
|
|
|||
Purchase of available-for-sale securities
|
(18.6
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of available for-sale securities
|
24.7
|
|
|
—
|
|
|
—
|
|
|||
Acquisition of Gary-Williams
|
—
|
|
|
—
|
|
|
(586.0
|
)
|
|||
Net cash used in investing activities
|
(250.3
|
)
|
|
(210.7
|
)
|
|
(674.4
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Proceeds, gross of original issue premium on issuance of senior notes
|
—
|
|
|
—
|
|
|
206.0
|
|
|||
Proceeds, gross on issuance of CVR Refining's senior notes
|
—
|
|
|
500.0
|
|
|
—
|
|
|||
Principal payments on senior secured notes
|
(243.4
|
)
|
|
(478.7
|
)
|
|
(2.7
|
)
|
|||
Proceeds from issuance of CVR Partners' long-term debt
|
—
|
|
|
—
|
|
|
125.0
|
|
|||
Payment of capital lease obligations
|
(1.2
|
)
|
|
(1.0
|
)
|
|
(5.0
|
)
|
|||
Payment of deferred financing costs
|
(0.4
|
)
|
|
(12.8
|
)
|
|
(15.1
|
)
|
|||
Deferred costs of CVR Refining's initial public offering
|
—
|
|
|
(3.0
|
)
|
|
—
|
|
|||
Proceeds from CVR Refining's initial public offering in January, net of offering costs
|
655.7
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from CVR Refining's offering in May, net of offering costs
|
393.6
|
|
|
—
|
|
|
—
|
|
|||
Proceeds from the sale of CVR Refining's common units to affiliate
|
61.5
|
|
|
—
|
|
|
—
|
|
|||
Purchase of managing general partner interest & incentive distribution rights
|
—
|
|
|
—
|
|
|
(26.0
|
)
|
|||
Proceeds from CVR Partners initial public offering, net of offering costs
|
—
|
|
|
—
|
|
|
324.9
|
|
|||
Proceeds from CVR Partners' secondary offering, net of offering costs
|
292.6
|
|
|
—
|
|
|
—
|
|
|||
Dividends to CVR Energy's stockholders
|
(1,237.3
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to CVR Refining's noncontrolling interest holders
|
(114.2
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to CVR Partners' noncontrolling interest holders
|
(50.0
|
)
|
|
(48.8
|
)
|
|
(21.6
|
)
|
|||
Repurchase of common stock
|
—
|
|
|
—
|
|
|
(3.6
|
)
|
|||
Excess tax benefit (deficiency) of share-based compensation
|
(0.1
|
)
|
|
—
|
|
|
2.3
|
|
|||
Exercise of stock options
|
—
|
|
|
0.4
|
|
|
—
|
|
|||
Redemption of common units
|
(0.5
|
)
|
|
(0.3
|
)
|
|
(0.1
|
)
|
|||
Net cash provided by (used in) financing activities
|
(243.7
|
)
|
|
(44.2
|
)
|
|
584.1
|
|
|||
Net (decrease) increase in cash and cash equivalents
|
(53.9
|
)
|
|
507.7
|
|
|
188.3
|
|
|||
Cash and cash equivalents, beginning of period
|
896.0
|
|
|
388.3
|
|
|
200.0
|
|
|||
Cash and cash equivalents, end of period
|
$
|
842.1
|
|
|
$
|
896.0
|
|
|
$
|
388.3
|
|
Supplemental disclosures:
|
|
|
|
|
|
||||||
Cash paid for income taxes, net of refunds (received)
|
$
|
274.5
|
|
|
$
|
228.4
|
|
|
$
|
182.6
|
|
Cash paid for interest net of capitalized interest of $3.6, $10.8 and $3.9 for the years ended December 31, 2013, 2012 and 2011, respectively
|
$
|
54.9
|
|
|
$
|
73.9
|
|
|
$
|
45.2
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Construction in process additions included in accounts payable
|
$
|
32.8
|
|
|
$
|
56.2
|
|
|
$
|
29.8
|
|
Change in accounts payable related to construction in process additions
|
$
|
(23.4
|
)
|
|
$
|
26.4
|
|
|
$
|
19.1
|
|
Reduction of proceeds for underwriting discount and financing costs
|
$
|
—
|
|
|
$
|
7.5
|
|
|
$
|
4.0
|
|
•
|
common units representing limited partner interests; and
|
•
|
a general partner interest, which is not entitled to any distributions, and which is held by the Nitrogen Fertilizer Partnership's general partner.
|
•
|
approximately
$18.4 million
was distributed to CRLLC to satisfy the Nitrogen Fertilizer Partnership's obligation to reimburse it for certain capital expenditures made on behalf of the nitrogen fertilizer business prior to October 24, 2007;
|
•
|
approximately
$117.1 million
was distributed to CRLLC through a special distribution in order to, among other things, fund the offer to purchase CRLLC's Old Notes required upon the consummation of the Nitrogen Fertilizer Partnership IPO;
|
•
|
$26.0 million
was used by the Nitrogen Fertilizer Partnership to purchase and extinguish the IDRs owned by the general partner;
|
•
|
approximately
$4.8 million
was used to pay financing fees and associated legal and professional fees resulting from the Nitrogen Fertilizer Partnership's credit facility; and
|
•
|
the balance of the proceeds were utilized by the Nitrogen Fertilizer Partnership for general partnership purposes, including the funding of the UAN expansion that was completed in February 2013 at a cost of approximately
$130.0 million
, excluding capitalized interest.
|
•
|
common units representing limited partner interests; and
|
•
|
a general partner interest, which is not entitled to any distributions, and which is held by the Refining Partnership's general partner.
|
•
|
approximately
$253.0 million
was used to repurchase the
10.875%
senior secured notes due 2017 (including accrued interest);
|
•
|
approximately
$160.0 million
will be used to fund certain maintenance and environmental capital expenditures through 2014;
|
•
|
approximately
$54.0 million
was used to fund the turnaround expenses at the Wynnewood refinery that were incurred during the fourth quarter of 2012;
|
•
|
approximately
$85.1 million
was distributed to CRLLC; and
|
•
|
the balance of the proceeds of approximately
$101.5 million
has been allocated to be utilized by the Refining Partnership for general partnership purposes.
|
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 40
|
Cash and cash equivalents
|
$
|
6.3
|
|
Accounts receivable
|
159.0
|
|
|
Inventories
|
213.5
|
|
|
Prepaid expenses and other current assets
|
6.0
|
|
|
Property, plant and equipment
|
577.0
|
|
|
Accounts payable and accrued liabilities
|
(316.1
|
)
|
|
Long-term debt
|
(52.3
|
)
|
|
Total fair values of net assets acquired
|
593.4
|
|
|
Less: cash acquired
|
6.3
|
|
|
Total consideration transferred, net of cash acquired
|
$
|
587.1
|
|
|
Year Ended
December 31, 2011
|
||
|
(in millions)
|
||
|
(unaudited)
|
||
Net sales
|
$
|
7,674.5
|
|
Net income
|
468.8
|
|
|
Benchmark
Value
(per Unit)
|
|
Original
Awards
Issued
|
|
|
|
*Compensation
Expense
for the
Year Ended
December 31,
|
|||||
Award Type
|
Grant Date
|
|
2011
|
|||||||||
|
|
|
|
|
|
|
(in millions)
|
|||||
Override Value Units
|
$
|
11.31
|
|
|
1,839,265
|
|
|
June 2005
|
|
$
|
5.0
|
|
Override Value Units
|
$
|
34.72
|
|
|
144,966
|
|
|
December 2006
|
|
0.4
|
|
|
Override Units
|
$
|
10.00
|
|
|
642,219
|
|
|
February 2008
|
|
0.2
|
|
|
|
|
|
|
|
Total
|
|
$
|
5.6
|
|
*
|
As CVR Energy's common stock price increased or decreased, compensation expense associated with the unvested CALLC and CALLC II override units increased or was reversed in correlation with the calculation of the fair value under the probability-weighted expected return method.
|
|
Restricted
Shares
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at December 31, 2010
|
1,369,182
|
|
|
$
|
10.94
|
|
|
$
|
20.8
|
|
Granted
|
826,959
|
|
|
18.79
|
|
|
|
|
||
Vested
|
(557,355
|
)
|
|
11.83
|
|
|
|
|
||
Forfeited
|
(4,632
|
)
|
|
8.67
|
|
|
|
|
||
Non-vested at December 31, 2011
|
1,634,154
|
|
|
$
|
14.61
|
|
|
$
|
30.6
|
|
Granted
|
318,508
|
|
|
43.66
|
|
|
|
|
||
Vested
|
(740,811
|
)
|
|
13.59
|
|
|
|
|
||
Forfeited
|
(66,240
|
)
|
|
16.54
|
|
|
|
|
||
Non-vested at December 31, 2012
|
1,145,611
|
|
|
$
|
23.24
|
|
|
$
|
55.9
|
|
Granted
|
2,600
|
|
|
54.75
|
|
|
|
|
||
Vested
|
(709,959
|
)
|
|
18.73
|
|
|
|
|
||
Forfeited
|
(78,700
|
)
|
|
42.80
|
|
|
|
|
||
Non-vested at December 31, 2013
|
359,552
|
|
|
$
|
28.09
|
|
|
$
|
15.6
|
|
|
Shares
|
|
Weighted-
Average
Exercise
Price
|
|
Weighted-
Average
Remaining
Contractual
Term
|
||||
Outstanding, December 31, 2010
|
22,900
|
|
|
$
|
18.03
|
|
|
8.35
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
Exercised
|
—
|
|
|
—
|
|
|
|
|
|
Forfeited
|
—
|
|
|
—
|
|
|
|
|
|
Expired
|
—
|
|
|
—
|
|
|
|
|
|
Outstanding, December 31, 2011
|
22,900
|
|
|
$
|
18.03
|
|
|
7.35
|
|
Granted
|
—
|
|
|
—
|
|
|
|
|
|
Exercised
|
(22,900
|
)
|
|
—
|
|
|
|
|
|
Forfeited
|
—
|
|
|
—
|
|
|
|
|
|
Expired
|
—
|
|
|
—
|
|
|
|
|
|
Outstanding, December 31, 2012
|
—
|
|
|
$
|
—
|
|
|
—
|
|
|
Phantom Units
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at January 16, 2013
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
187,177
|
|
|
21.55
|
|
|
|
|||
Vested
|
—
|
|
|
—
|
|
|
|
|||
Forfeited
|
—
|
|
|
—
|
|
|
|
|||
Non-vested at December 31, 2013
|
187,177
|
|
|
$
|
21.55
|
|
|
$
|
4.2
|
|
|
Incentive Units
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at December 31, 2012
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Granted
|
251,431
|
|
|
22.62
|
|
|
|
|||
Vested
|
—
|
|
|
—
|
|
|
|
|||
Forfeited
|
—
|
|
|
—
|
|
|
|
|||
Non-vested at December 31, 2013
|
251,431
|
|
|
$
|
22.62
|
|
|
$
|
5.7
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in millions)
|
||||||
Finished goods
|
$
|
268.2
|
|
|
$
|
275.2
|
|
Raw materials and precious metals
|
177.0
|
|
|
164.3
|
|
||
In-process inventories
|
36.9
|
|
|
42.8
|
|
||
Parts and supplies
|
44.5
|
|
|
45.8
|
|
||
|
$
|
526.6
|
|
|
$
|
528.1
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in millions)
|
||||||
Land and improvements
|
$
|
36.1
|
|
|
$
|
31.0
|
|
Buildings
|
42.6
|
|
|
40.6
|
|
||
Machinery and equipment
|
2,312.5
|
|
|
2,089.5
|
|
||
Automotive equipment
|
19.2
|
|
|
15.0
|
|
||
Furniture and fixtures
|
18.3
|
|
|
13.7
|
|
||
Leasehold improvements
|
2.5
|
|
|
2.5
|
|
||
Aircraft
|
2.3
|
|
|
—
|
|
||
Railcars
|
7.9
|
|
|
2.5
|
|
||
Construction in progress
|
164.9
|
|
|
189.2
|
|
||
|
2,606.3
|
|
|
2,384.0
|
|
||
Accumulated depreciation
|
741.9
|
|
|
601.1
|
|
||
|
$
|
1,864.4
|
|
|
$
|
1,782.9
|
|
•
|
general economic conditions;
|
•
|
fertilizer pricing;
|
•
|
input costs; and
|
•
|
customer outlook.
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Current
|
|
|
|
|
|
||||||
Federal
|
$
|
265.8
|
|
|
$
|
237.3
|
|
|
$
|
141.3
|
|
State
|
21.5
|
|
|
25.4
|
|
|
8.0
|
|
|||
Total current
|
287.3
|
|
|
262.7
|
|
|
149.3
|
|
|||
Deferred
|
|
|
|
|
|
||||||
Federal
|
(93.5
|
)
|
|
(39.8
|
)
|
|
40.3
|
|
|||
State
|
(10.1
|
)
|
|
2.7
|
|
|
19.9
|
|
|||
Total deferred
|
(103.6
|
)
|
|
(37.1
|
)
|
|
60.2
|
|
|||
Total income tax expense
|
$
|
183.7
|
|
|
$
|
225.6
|
|
|
$
|
209.5
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Tax computed at federal statutory rate
|
$
|
247.0
|
|
|
$
|
223.4
|
|
|
$
|
205.8
|
|
State income taxes, net of federal tax benefit
|
16.5
|
|
|
23.9
|
|
|
20.6
|
|
|||
State tax incentives, net of federal tax expense
|
(9.0
|
)
|
|
(5.4
|
)
|
|
(3.2
|
)
|
|||
Domestic production activities deduction
|
(18.5
|
)
|
|
(16.5
|
)
|
|
(10.6
|
)
|
|||
Non-deductible share-based compensation
|
1.5
|
|
|
7.3
|
|
|
2.0
|
|
|||
Non-deductible transaction costs
|
—
|
|
|
4.2
|
|
|
—
|
|
|||
IRS interest expense, net
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|||
Noncontrolling interest
|
(53.0
|
)
|
|
(11.9
|
)
|
|
(11.5
|
)
|
|||
Partnership basis adjustment
|
—
|
|
|
—
|
|
|
4.2
|
|
|||
Other, net
|
(0.8
|
)
|
|
0.5
|
|
|
2.1
|
|
|||
Total income tax expense
|
$
|
183.7
|
|
|
$
|
225.6
|
|
|
$
|
209.5
|
|
|
Year Ended December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in millions)
|
||||||
Deferred income tax assets:
|
|
|
|
||||
Allowance for doubtful accounts
|
$
|
—
|
|
|
$
|
0.8
|
|
Personnel accruals
|
8.8
|
|
|
12.9
|
|
||
Inventories
|
—
|
|
|
3.6
|
|
||
Unrealized derivative losses, net
|
—
|
|
|
26.2
|
|
||
Accrued expenses
|
—
|
|
|
2.1
|
|
||
State tax credit carryforward, net of federal expense
|
19.6
|
|
|
14.4
|
|
||
Contingent liabilities
|
10.3
|
|
|
10.8
|
|
||
Other
|
—
|
|
|
2.1
|
|
||
Total gross deferred income tax assets
|
38.7
|
|
|
72.9
|
|
||
Deferred income tax liabilities:
|
|
|
|
||||
Property, plant, and equipment
|
(2.0
|
)
|
|
(282.2
|
)
|
||
Investment in CVR Partners
|
(87.6
|
)
|
|
(109.7
|
)
|
||
Investment in CVR Refining
|
(522.1
|
)
|
|
—
|
|
||
Deferred financing
|
—
|
|
|
(1.1
|
)
|
||
Prepaid expenses
|
(0.4
|
)
|
|
(9.4
|
)
|
||
Other
|
(0.5
|
)
|
|
—
|
|
||
Total gross deferred income tax liabilities
|
(612.6
|
)
|
|
(402.4
|
)
|
||
Net deferred income tax liabilities
|
$
|
(573.9
|
)
|
|
$
|
(329.5
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Balance beginning of year
|
$
|
36.9
|
|
|
$
|
17.7
|
|
|
$
|
0.2
|
|
Increase based on prior year tax positions
|
—
|
|
|
4.8
|
|
|
—
|
|
|||
Decrease based on prior year tax positions
|
(6.4
|
)
|
|
(0.1
|
)
|
|
—
|
|
|||
Increases in current year tax positions
|
14.7
|
|
|
14.7
|
|
|
17.5
|
|
|||
Settlements
|
—
|
|
|
—
|
|
|
—
|
|
|||
Reductions related to expirations of statute of limitations
|
—
|
|
|
(0.2
|
)
|
|
—
|
|
|||
Balance end of year
|
$
|
45.2
|
|
|
$
|
36.9
|
|
|
$
|
17.7
|
|
|
December 31,
|
||||||
|
2013
|
|
2012
|
||||
|
(in millions)
|
||||||
10.875% Second Lien Senior Secured Notes, due 2017, net of unamortized discount of $1.8 million as of December 31, 2012
|
$
|
—
|
|
|
$
|
220.9
|
|
6.5% Second Lien Senior Secured Notes, due 2022
|
500.0
|
|
|
500.0
|
|
||
CRNF credit facility
|
125.0
|
|
|
125.0
|
|
||
Capital lease obligations
|
49.9
|
|
|
51.2
|
|
||
Long-term debt
|
$
|
674.9
|
|
|
$
|
897.1
|
|
|
|
||
Year Ending December 31,
|
Deferred
Financing
|
||
|
(in millions)
|
||
2014
|
$
|
2.8
|
|
2015
|
2.8
|
|
|
2016
|
2.2
|
|
|
2017
|
1.9
|
|
|
2018
|
0.9
|
|
|
Thereafter
|
3.5
|
|
|
|
$
|
14.1
|
|
Year Ending December 31,
|
Capital Lease
|
||
|
(in millions)
|
||
2014
|
$
|
6.3
|
|
2015
|
6.4
|
|
|
2016
|
6.4
|
|
|
2017
|
6.4
|
|
|
2018
|
6.5
|
|
|
2019 and thereafter
|
70.3
|
|
|
Total future payments
|
102.3
|
|
|
Less: amount representing interest
|
51.1
|
|
|
Present value of future minimum payments
|
51.2
|
|
|
Less: current portion
|
1.3
|
|
|
Long-term portion
|
$
|
49.9
|
|
|
February 19, 2013
|
|
May 17, 2013
|
|
June 10, 2013
|
|
August 19, 2013
|
|
November 18, 2013
|
|
Total Dividends
Paid in 2013
|
||||||||||||
|
(in millions, except per share amounts)
|
||||||||||||||||||||||
Dividend type
|
Special
|
|
|
Quarterly
|
|
|
Special
|
|
|
Quarterly
|
|
|
Quarterly
|
|
|
|
|||||||
Amount paid to IEP
|
$
|
391.6
|
|
|
$
|
53.4
|
|
|
$
|
462.8
|
|
|
$
|
53.4
|
|
|
$
|
53.4
|
|
|
$
|
1,014.6
|
|
Amounts paid to public stockholders
|
86.0
|
|
|
11.7
|
|
|
101.6
|
|
|
11.7
|
|
|
11.7
|
|
|
222.7
|
|
||||||
Total amount paid
|
$
|
477.6
|
|
|
$
|
65.1
|
|
|
$
|
564.4
|
|
|
$
|
65.1
|
|
|
$
|
65.1
|
|
|
$
|
1,237.3
|
|
Per common share
|
$
|
5.50
|
|
|
$
|
0.75
|
|
|
$
|
6.50
|
|
|
$
|
0.75
|
|
|
$
|
0.75
|
|
|
$
|
14.25
|
|
Shares outstanding
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
|
|
For the Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions, except per share data)
|
||||||||||
Net income attributable to CVR Energy stockholders
|
$
|
370.7
|
|
|
$
|
378.6
|
|
|
$
|
345.8
|
|
Weighted-average number of shares of common stock outstanding
|
86.8
|
|
|
86.8
|
|
|
86.5
|
|
|||
Effect of dilutive securities:
|
|
|
|
|
|
||||||
Non-vested restricted shares
|
—
|
|
|
0.6
|
|
|
1.3
|
|
|||
Weighted-average number of shares of common stock outstanding assuming dilution
|
86.8
|
|
|
87.4
|
|
|
87.8
|
|
|||
Basic earnings per share
|
$
|
4.27
|
|
|
$
|
4.36
|
|
|
$
|
4.00
|
|
Diluted earnings per share
|
$
|
4.27
|
|
|
$
|
4.33
|
|
|
$
|
3.94
|
|
Year Ending December 31,
|
Operating
Leases
|
|
Unconditional
Purchase
Obligations(1)
|
||||
|
(in millions)
|
||||||
2014
|
$
|
9.5
|
|
|
$
|
121.4
|
|
2015
|
7.9
|
|
|
109.5
|
|
||
2016
|
6.9
|
|
|
102.4
|
|
||
2017
|
4.2
|
|
|
101.2
|
|
||
2018
|
3.0
|
|
|
101.2
|
|
||
Thereafter
|
5.2
|
|
|
882.7
|
|
||
|
$
|
36.7
|
|
|
$
|
1,418.4
|
|
(1)
|
This amount includes approximately
$973.0 million
payable ratably over
seventeen
years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP ("TransCanada"). Under the agreements, CRRM receives transportation of at least
25,000
barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of
twenty
years on TransCanada's Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.
|
Year Ending December 31,
|
Amount
|
||
|
(in millions)
|
||
2014
|
$
|
0.3
|
|
2015
|
0.2
|
|
|
2016
|
0.1
|
|
|
2017
|
0.1
|
|
|
2018
|
0.1
|
|
|
Thereafter
|
1.0
|
|
|
Undiscounted total
|
1.8
|
|
|
Less amounts representing interest at 2.73%
|
0.3
|
|
|
Accrued environmental liabilities at December 31, 2013
|
$
|
1.5
|
|
•
|
Level 1 — Quoted prices in active markets for identical assets and liabilities
|
•
|
Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)
|
•
|
Level 3 — Significant unobservable inputs (including the Company's own assumptions in determining the fair value)
|
|
December 31, 2013
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Location and Description
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
81.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
81.0
|
|
Other current assets (other derivative agreements)
|
—
|
|
|
0.9
|
|
|
—
|
|
|
0.9
|
|
||||
Other long-term assets (other derivative agreements)
|
—
|
|
|
0.1
|
|
|
—
|
|
|
0.1
|
|
||||
Total Assets
|
$
|
81.0
|
|
|
$
|
1.0
|
|
|
$
|
—
|
|
|
$
|
82.0
|
|
Other current liabilities (other derivative agreements)
|
—
|
|
|
(15.3
|
)
|
|
—
|
|
|
(15.3
|
)
|
||||
Other current liabilities (interest rate swap)
|
—
|
|
|
(0.9
|
)
|
|
—
|
|
|
(0.9
|
)
|
||||
Other current liabilities (biofuel blending obligations)
|
—
|
|
|
(16.2
|
)
|
|
—
|
|
|
(16.2
|
)
|
||||
Other long-term liabilities (other derivative agreements)
|
—
|
|
|
(1.8
|
)
|
|
—
|
|
|
(1.8
|
)
|
||||
Other long-term liabilities (interest rate swap)
|
—
|
|
|
(1.0
|
)
|
|
—
|
|
|
(1.0
|
)
|
||||
Total Liabilities
|
$
|
—
|
|
|
$
|
(35.2
|
)
|
|
$
|
—
|
|
|
$
|
(35.2
|
)
|
|
December 31, 2012
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Location and Description
|
|
|
|
|
|
|
|
||||||||
Cash equivalents
|
$
|
134.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
134.0
|
|
Other long-term assets (other derivative agreements)
|
—
|
|
|
0.9
|
|
|
—
|
|
|
0.9
|
|
||||
Total Assets
|
$
|
134.0
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
134.9
|
|
Other current liabilities (other derivative agreements)
|
—
|
|
|
(67.7
|
)
|
|
—
|
|
|
(67.7
|
)
|
||||
Other current liabilities (interest rate swap)
|
—
|
|
|
(0.9
|
)
|
|
—
|
|
|
(0.9
|
)
|
||||
Other current liabilities (biofuel blending obligations)
|
—
|
|
|
(1.1
|
)
|
|
—
|
|
|
(1.1
|
)
|
||||
Other long-term liabilities (interest rate swap)
|
—
|
|
|
(1.9
|
)
|
|
—
|
|
|
(1.9
|
)
|
||||
Total Liabilities
|
$
|
—
|
|
|
$
|
(71.6
|
)
|
|
$
|
—
|
|
|
$
|
(71.6
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Current period settlement on derivative contracts
|
$
|
6.4
|
|
|
$
|
(137.6
|
)
|
|
$
|
(7.2
|
)
|
Gain (loss) on derivatives, net
|
57.1
|
|
|
(285.6
|
)
|
|
78.1
|
|
|
As of December 31, 2013
|
||||||||||||||||||
Description
|
Gross
Current Assets
|
|
Gross
Amounts
Offset
|
|
Net
Current Assets
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
4.3
|
|
|
$
|
(3.4
|
)
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
Total
|
$
|
4.3
|
|
|
$
|
(3.4
|
)
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
As of December 31, 2013
|
||||||||||||||||||
Description
|
Gross
Non-Current Assets
|
|
Gross
Amounts
Offset
|
|
Net
Non-Current Assets
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
Total
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
As of December 31, 2013
|
||||||||||||||||||
Description
|
Gross
Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
31.4
|
|
|
$
|
(16.1
|
)
|
|
$
|
15.3
|
|
|
$
|
—
|
|
|
$
|
15.3
|
|
Total
|
$
|
31.4
|
|
|
$
|
(16.1
|
)
|
|
$
|
15.3
|
|
|
$
|
—
|
|
|
$
|
15.3
|
|
|
As of December 31, 2013
|
||||||||||||||||||
Description
|
Gross
Non-Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Non-Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
1.9
|
|
|
$
|
(0.1
|
)
|
|
$
|
1.8
|
|
|
$
|
—
|
|
|
$
|
1.8
|
|
Total
|
$
|
1.9
|
|
|
$
|
(0.1
|
)
|
|
$
|
1.8
|
|
|
$
|
—
|
|
|
$
|
1.8
|
|
|
As of December 31, 2012
|
||||||||||||||||||
Description
|
Gross
Non-Current Assets
|
|
Gross
Amounts
Offset
|
|
Net
Non-Current Assets
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
Total
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
$
|
—
|
|
|
$
|
0.9
|
|
|
As of December 31, 2012
|
||||||||||||||||||
Description
|
Gross
Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
74.2
|
|
|
$
|
(6.5
|
)
|
|
$
|
67.7
|
|
|
$
|
—
|
|
|
$
|
67.7
|
|
Total
|
$
|
74.2
|
|
|
$
|
(6.5
|
)
|
|
$
|
67.7
|
|
|
$
|
—
|
|
|
$
|
67.7
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Net sales
|
|
|
|
|
|
||||||
Petroleum
|
$
|
8,683.5
|
|
|
$
|
8,281.5
|
|
|
$
|
4,751.8
|
|
Nitrogen Fertilizer
|
323.7
|
|
|
302.3
|
|
|
302.9
|
|
|||
Intersegment elimination
|
(21.4
|
)
|
|
(16.5
|
)
|
|
(25.6
|
)
|
|||
Total
|
$
|
8,985.8
|
|
|
$
|
8,567.3
|
|
|
$
|
5,029.1
|
|
Cost of product sold (exclusive of depreciation and amortization)
|
|
|
|
|
|
||||||
Petroleum
|
$
|
7,526.7
|
|
|
$
|
6,667.3
|
|
|
$
|
3,926.6
|
|
Nitrogen Fertilizer
|
58.1
|
|
|
46.1
|
|
|
42.5
|
|
|||
Intersegment elimination
|
(21.6
|
)
|
|
(16.5
|
)
|
|
(25.6
|
)
|
|||
Total
|
$
|
7,563.2
|
|
|
$
|
6,696.9
|
|
|
$
|
3,943.5
|
|
Direct operating expenses (exclusive of depreciation and amortization)
|
|
|
|
|
|
||||||
Petroleum
|
$
|
361.7
|
|
|
$
|
426.5
|
|
|
$
|
247.7
|
|
Nitrogen Fertilizer
|
94.1
|
|
|
95.6
|
|
|
86.5
|
|
|||
Other
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|||
Total
|
$
|
455.8
|
|
|
$
|
522.1
|
|
|
$
|
334.1
|
|
Depreciation and amortization
|
|
|
|
|
|
||||||
Petroleum
|
$
|
114.3
|
|
|
$
|
107.6
|
|
|
$
|
69.9
|
|
Nitrogen Fertilizer
|
25.6
|
|
|
20.7
|
|
|
18.9
|
|
|||
Other
|
2.9
|
|
|
1.7
|
|
|
1.5
|
|
|||
Total
|
$
|
142.8
|
|
|
$
|
130.0
|
|
|
$
|
90.3
|
|
Operating income
|
|
|
|
|
|
||||||
Petroleum
|
$
|
603.0
|
|
|
$
|
1,012.5
|
|
|
$
|
465.7
|
|
Nitrogen Fertilizer
|
124.9
|
|
|
115.8
|
|
|
136.2
|
|
|||
Other
|
(17.4
|
)
|
|
(93.4
|
)
|
|
(35.3
|
)
|
|||
Total
|
$
|
710.5
|
|
|
$
|
1,034.9
|
|
|
$
|
566.6
|
|
Capital expenditures
|
|
|
|
|
|
||||||
Petroleum
|
$
|
204.5
|
|
|
$
|
120.0
|
|
|
$
|
68.6
|
|
Nitrogen fertilizer
|
43.8
|
|
|
82.2
|
|
|
19.1
|
|
|||
Other
|
8.2
|
|
|
10.0
|
|
|
3.5
|
|
|||
Total
|
$
|
256.5
|
|
|
$
|
212.2
|
|
|
$
|
91.2
|
|
|
Year Ended December 31,
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
|
(in millions)
|
||||||||||
Total assets
|
|
|
|
|
|
||||||
Petroleum
|
$
|
2,533.3
|
|
|
$
|
2,258.5
|
|
|
$
|
2,322.1
|
|
Nitrogen Fertilizer
|
593.5
|
|
|
623.0
|
|
|
659.3
|
|
|||
Other
|
539.0
|
|
|
729.4
|
|
|
137.9
|
|
|||
Total
|
$
|
3,665.8
|
|
|
$
|
3,610.9
|
|
|
$
|
3,119.3
|
|
Goodwill
|
|
|
|
|
|
||||||
Petroleum
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Nitrogen Fertilizer
|
41.0
|
|
|
41.0
|
|
|
41.0
|
|
|||
Other
|
—
|
|
|
—
|
|
|
—
|
|
|||
Total
|
$
|
41.0
|
|
|
$
|
41.0
|
|
|
$
|
41.0
|
|
|
Year Ended December 31, 2013
|
||||||||||||||
|
Quarter
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in millions except per share data)
|
||||||||||||||
Net sales
|
$
|
2,352.4
|
|
|
$
|
2,220.3
|
|
|
$
|
1,977.1
|
|
|
$
|
2,436.0
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of product sold (exclusive of depreciation and amortization)
|
1,813.6
|
|
|
1,785.4
|
|
|
1,744.4
|
|
|
2,219.7
|
|
||||
Direct operating expenses (exclusive of depreciation and amortization)
|
108.5
|
|
|
108.3
|
|
|
128.4
|
|
|
110.6
|
|
||||
Selling, general and administrative (exclusive of depreciation and amortization)
|
28.4
|
|
|
28.9
|
|
|
27.7
|
|
|
28.6
|
|
||||
Depreciation and amortization
|
34.2
|
|
|
35.0
|
|
|
36.2
|
|
|
37.4
|
|
||||
Total operating costs and expenses
|
1,984.7
|
|
|
1,957.6
|
|
|
1,936.7
|
|
|
2,396.3
|
|
||||
Operating income
|
367.7
|
|
|
262.7
|
|
|
40.4
|
|
|
39.7
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs
|
(15.4
|
)
|
|
(12.5
|
)
|
|
(11.7
|
)
|
|
(10.9
|
)
|
||||
Interest income
|
0.3
|
|
|
0.3
|
|
|
0.3
|
|
|
0.3
|
|
||||
Gain (loss) on derivatives, net
|
(20.0
|
)
|
|
120.5
|
|
|
72.5
|
|
|
(115.9
|
)
|
||||
Loss on extinguishment of debt
|
(26.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Other income, net
|
—
|
|
|
0.2
|
|
|
6.2
|
|
|
7.1
|
|
||||
Total other income (expense)
|
(61.2
|
)
|
|
108.5
|
|
|
67.3
|
|
|
(119.4
|
)
|
||||
Income (loss) before income tax expense
|
306.5
|
|
|
371.2
|
|
|
107.7
|
|
|
(79.7
|
)
|
||||
Income tax expense (benefit)
|
93.8
|
|
|
99.5
|
|
|
29.5
|
|
|
(39.1
|
)
|
||||
Net income (loss)
|
212.7
|
|
|
271.7
|
|
|
78.2
|
|
|
(40.6
|
)
|
||||
Less: Net income (loss) attributable to noncontrolling interest
|
47.7
|
|
|
88.3
|
|
|
34.2
|
|
|
(18.9
|
)
|
||||
Net income (loss) attributable to CVR Energy stockholders
|
$
|
165.0
|
|
|
$
|
183.4
|
|
|
$
|
44.0
|
|
|
$
|
(21.7
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net earnings (loss) per share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
1.90
|
|
|
$
|
2.11
|
|
|
$
|
0.51
|
|
|
$
|
(0.25
|
)
|
Diluted
|
$
|
1.90
|
|
|
$
|
2.11
|
|
|
$
|
0.51
|
|
|
$
|
(0.25
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
||||||||
Basic
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
||||
Diluted
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
Year Ended December 31, 2012
|
||||||||||||||
|
Quarter
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in millions except per share data)
|
||||||||||||||
Net sales
|
$
|
1,968.6
|
|
|
$
|
2,308.3
|
|
|
$
|
2,409.6
|
|
|
$
|
1,880.8
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of product sold (exclusive of depreciation and amortization)
|
1,635.2
|
|
|
1,874.2
|
|
|
1,702.5
|
|
|
1,485.1
|
|
||||
Direct operating expenses (exclusive of depreciation and amortization)
|
115.5
|
|
|
94.1
|
|
|
109.9
|
|
|
202.5
|
|
||||
Selling, general and administrative (exclusive of depreciation and amortization)
|
45.3
|
|
|
72.0
|
|
|
30.4
|
|
|
35.7
|
|
||||
Depreciation and amortization
|
32.1
|
|
|
32.2
|
|
|
33.1
|
|
|
32.6
|
|
||||
Total operating costs and expenses
|
1,828.1
|
|
|
2,072.5
|
|
|
1,875.9
|
|
|
1,755.9
|
|
||||
Operating income
|
140.5
|
|
|
235.8
|
|
|
533.7
|
|
|
124.9
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs
|
(19.2
|
)
|
|
(19.0
|
)
|
|
(18.9
|
)
|
|
(18.2
|
)
|
||||
Interest income
|
—
|
|
|
0.2
|
|
|
0.3
|
|
|
0.3
|
|
||||
Gain (loss) on derivatives, net
|
(147.2
|
)
|
|
38.8
|
|
|
(168.9
|
)
|
|
(8.2
|
)
|
||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(37.5
|
)
|
||||
Other income (expense), net
|
0.1
|
|
|
0.6
|
|
|
(0.1
|
)
|
|
0.2
|
|
||||
Total other income (expense)
|
(166.3
|
)
|
|
20.6
|
|
|
(187.6
|
)
|
|
(63.4
|
)
|
||||
Income (loss) before income tax expense
|
(25.8
|
)
|
|
256.4
|
|
|
346.1
|
|
|
61.5
|
|
||||
Income tax expense (benefit)
|
(9.8
|
)
|
|
91.1
|
|
|
127.6
|
|
|
16.7
|
|
||||
Net income (loss)
|
(16.0
|
)
|
|
165.3
|
|
|
218.5
|
|
|
44.8
|
|
||||
Less: Net income attributable to noncontrolling interest
|
9.2
|
|
|
10.6
|
|
|
9.6
|
|
|
4.6
|
|
||||
Net income (loss) attributable to CVR Energy stockholders
|
$
|
(25.2
|
)
|
|
$
|
154.7
|
|
|
$
|
208.9
|
|
|
$
|
40.2
|
|
|
|
|
|
|
|
|
|
||||||||
Net earnings (loss) per share
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
(0.29
|
)
|
|
$
|
1.78
|
|
|
$
|
2.41
|
|
|
$
|
0.46
|
|
Diluted
|
$
|
(0.29
|
)
|
|
$
|
1.75
|
|
|
$
|
2.41
|
|
|
$
|
0.46
|
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common shares outstanding
|
|
|
|
|
|
|
|
||||||||
Basic
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
|
86.8
|
|
||||
Diluted
|
86.8
|
|
|
88.5
|
|
|
86.8
|
|
|
86.8
|
|
Exhibit Number
|
Exhibit Title
|
10.3**
|
Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, as collateral agent (incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on February 12, 2007).
|
|
|
10.4**
|
ABL Intercreditor Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Finance Inc., Deutsche Bank Trust Company Americas, as collateral agent for the ABL secured parties, Wells Fargo Bank, National Association, as collateral trustee for the secured parties in respect of the outstanding first lien obligations, and the outstanding second lien notes and certain subordinated liens, respectively, and the Guarantors (as defined therein) (incorporated by reference to Exhibit 1.3 to the Company's Form 8-K filed on February 28, 2011).
|
|
|
10.5**
|
First Amended and Restated Collateral Trust and Intercreditor Agreement, dated as of April 6, 2010, among Coffeyville Resources, LLC, Coffeyville Finance Inc., the other grantors from time to time party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent, Wells Fargo Bank, National Association, as indenture agent, J. Aron & Company, as hedging counterparty, each additional first lien representative and Wells Fargo Bank, National Association, as collateral trustee (incorporated by reference to Exhibit 10.33 to the Company's Form 10-K for the year ended December 31, 2011, filed on February 29, 2012).
|
|
|
10.6**
|
Omnibus Amendment Agreement and Consent under the Intercreditor Agreement, dated as of April 6, 2010, by and among Coffeyville Resources, LLC, Coffeyville Finance Inc., Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, and certain subsidiaries of the foregoing as Guarantors, the Requisite Lenders, Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, Collateral Agent and Revolving Issuing Bank, J. Aron & Company, as a hedge counterparty and Wells Fargo Bank, National Association, as Collateral Trustee (incorporated by reference to Exhibit 1.4 to the Company's Form 8-K filed on April 12, 2010).
|
|
|
10.7**
|
Credit and Guaranty Agreement, dated as of April 13, 2011, among Coffeyville Resources Nitrogen Fertilizers, LLC, CVR Partners, LP, the lenders party thereto and Goldman Sachs Lending Partners LLC, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.8 to the Company's Form 8-K filed on May 23, 2011).
|
|
|
10.8†**
|
License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between GE Energy (USA), LLC (as successor in interest to Texaco Development Corporation) and Coffeyville Resources Nitrogen Fertilizers, LLC (as successor in interest to Farmland Industries, Inc.), as amended (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007).
|
|
|
10.9†**
|
Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, by and between The BOC Group, Inc. (n/k/a Linde LLC) and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007).
|
|
|
10.9.1**
|
First Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of October 31, 2008, by and between Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc. (n/k/a Linde LLC) (incorporated by reference to Exhibit 10.3 to the Company's Form 10-Q for the quarter ended September 30, 2008, filed on November 13, 2008).
|
|
|
10.10†**
|
Amended and Restated Crude Oil Supply Agreement, dated August 31, 2012, by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q for the quarter ended September 30, 2012, filed on November 6, 2012).
|
|
|
10.11†**
|
Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, by and between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.14 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on April 18, 2007).
|
|
|
10.12**
|
Amended and Restated Electric Services Agreement dated as of August 1, 2010, by and between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on August 25, 2010).
|
|
|
10.13*++
|
Fourth Amended and Restated Employment Agreement, dated as of December 19, 2013, by and between CVR Energy, Inc. and John J. Lipinski.
|
|
|
Exhibit Number
|
Exhibit Title
|
10.14**++
|
Third Amended and Restated Employment Agreement, dated as of July 27, 2012, by and between CVR Energy, Inc. and Susan M. Ball (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended September 30, 2012, filed on November 6, 2012).
|
|
|
10.14.1*++
|
Amendment Number 1 to Third Amended and Restated Employment Agreement, dated as of December 31, 2013, by and between CVR Energy, Inc. and Susan M. Ball.
|
|
|
10.15**++
|
Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Stanley A. Riemann (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011).
|
|
|
10.15.1*++
|
Letter Agreement, dated November 29, 2013, by and between CVR Energy, Inc. and Stanley A. Riemann.
|
|
|
10.16**++
|
Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Edmund S. Gross (incorporated by reference to Exhibit 10.4 to the Company's Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011).
|
|
|
10.16.1*++
|
Amendment Number 1 to Third Amended and Restated Employment Agreement, dated as of December 31, 2013, by and between CVR Energy, Inc. and Edmund S. Gross.
|
|
|
10.17**++
|
Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.5 to the Company's Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011).
|
|
|
10.17.1*++
|
Amendment Number 1 to Third Amended and Restated Employment Agreement, dated as of December 31, 2013, by and between CVR Energy, Inc. and Robert W. Haugen.
|
|
|
10.18**
|
Second Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated April 13, 2011 (incorporated by reference to Exhibit 10.7 to the Company's Form 8-K/A filed on May 23, 2011).
|
|
|
10.19**
|
Amended and Restated Contribution, Conveyance and Assumption Agreement, dated as of April 7, 2011, among Coffeyville Resources, LLC, CVR GP, LLC, Coffeyville Acquisition III LLC, CVR Special GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K/A filed on May 23, 2011).
|
|
|
10.20**
|
Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7 to the Company's Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007).
|
|
|
10.20.1**
|
Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 to the Company's Form 10-K for the year ended December 31, 2007, filed on March 28, 2008).
|
|
|
10.20.2**
|
Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.1 to the Company's Form 10-Q for the quarter ended June 30, 2008, filed on August 14, 2008).
|
|
|
10.21**
|
Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.4 to the Company's Form 8-K/A filed on May 23, 2011).
|
|
|
10.21.1*
|
Amendment to Amended and Restated Feedstock and Shared Services Agreement, dated as of December 30, 2013, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
|
|
|
10.22**
|
Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.9 to the Company's Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007).
|
|
|
10.23**
|
Second Amended and Restated Services Agreement, dated as of May 4, 2012, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on August 2, 2012).
|
|
|
Exhibit Number
|
Exhibit Title
|
10.24**
|
Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc., CVR GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.2 to the Company's Form 8-K/A filed on May 23, 2011).
|
|
|
10.25**
|
Amended and Restated Registration Rights Agreement, dated as of April 13, 2011, among CVR Partners, LP and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.6 to the Company's Form 8-K/A filed by on May 23, 2011).
|
|
|
10.26**
|
Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company's Form 10-Q for the quarter ended September 30, 2007, filed on December 6, 2007).
|
|
|
10.27**
|
Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Company's Form 8-K/A filed on May 23, 2011).
|
|
|
10.28**
|
GP Services Agreement, dated as of November 29, 2011, by and between CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.22 to the Form 10-K for the year ended December 31, 2011, filed by CVR Partners, LP on February 24, 2012 (Commission File No. 001-35120)).
|
|
|
10.29**
|
Trademark License Agreement, dated as of April 13, 2011, by and between CVR Energy, Inc. and CVR Partners, LP (incorporated by reference to Exhibit 10.9 to the Company's Form 8-K/A filed on May 23, 2011).
|
|
|
10.30**
|
Lease and Operating Agreement, dated as of May 4, 2012, by and between Coffeyville Resources Terminal, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.2 to the Company's Form 10-Q filed on August 2, 2012).
|
|
|
10.31**
|
Form of Indemnification Agreement between CVR Energy, Inc. and each of its directors and officers (incorporated by reference to Exhibit 10.49 to the Company's Form 10-K for the year ended December 31, 2008, filed on March 13, 2009).
|
|
|
10.32*++
|
Amended and Restated CVR Energy, Inc. 2007 Long Term Incentive Plan, dated as of December 26, 2013.
|
|
|
10.32.1**++
|
Form of Nonqualified Stock Option Agreement (incorporated by reference to Exhibit 10.33.1 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007).
|
|
|
10.32.2**++
|
Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.33.2 to the Company's Registration Statement on Form S-1/A, File No. 333-137588, filed on June 5, 2007).
|
|
|
10.32.3**++
|
Form of Director Restricted Stock Agreement (incorporated by reference to Exhibit 10.28.3 to the Company's Form 10-K for the year ended December 31, 2009, filed on March 12, 2010).
|
|
|
10.32.4**++
|
Form of Restricted Stock Agreement (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on December 23, 2011).
|
|
|
10.32.5**++
|
Form of Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 to the Company's Form 8-K filed on January 4, 2013).
|
|
|
10.32.6*++
|
Form of Incentive Unit Agreement.
|
|
|
10.33*++
|
Performance Unit Agreement (Award 1 and 2), dated as of December 19, 2013, by and between CVR Energy, Inc. and John J. Lipinski.
|
|
|
10.34*++
|
Performance Unit Agreement (Award 3), dated as of December 19, 2013, by and between CVR Energy, Inc. and John J. Lipinski.
|
|
|
10.35**++
|
CVR Partners, LP Long-Term Incentive Plan (adopted March 16, 2011) (incorporated by reference to Exhibit 10.1 to the Form S-8 filed by CVR Partners, LP on April 12, 2011 (Commission File No. 333-173444)).
|
|
|
10.35.1**++
|
Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.4 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)).
|
|
|
10.35.2**++
|
Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.18.5 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)).
|
|
|
Exhibit Number
|
Exhibit Title
|
10.36**++
|
CVR Energy, Inc. Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)).
|
|
|
10.37**++
|
CVR Partners, LP Performance Incentive Plan (incorporated by reference to Exhibit 10.24 to the Form 10-K filed by CVR Partners, LP on March 1, 2013 (Commission File No. 001-35120)).
|
|
|
10.38**
|
Third Amended and Restated Limited Liability Company Agreement of CVR GP, LLC, dated April 13, 2011 (incorporated by reference to Exhibit 3.4 to the Form 10-K for the year ended December 31, 2011 filed by CVR Partners, LP on February 24, 2012 (Commission File No. 001-35120)).
|
|
|
10.39**
|
First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, dated as of January 23, 2013 (incorporated by reference to Exhibit 3.1 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).
|
|
|
10.40**
|
Contribution Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form S-1/A filed by CVR Refining, LP on January 8, 2013 (Commission File No. 333-184200)).
|
|
|
10.41**++
|
CVR Refining, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership's Form 8-K filed on January 23, 2013 (Commission File No. 001-35781)).
|
|
|
10.41.1*++
|
Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement.
|
|
|
10.42**
|
Services Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).
|
|
|
10.43**
|
Trademark License Agreement, dated as of January 23, 2013, by and among CVR Refining, LP and CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).
|
|
|
10.44**
|
Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and among CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K filed by CVR Refining, LP on January 29, 2013 (Commission File No. 001-35781)).
|
|
|
10.45**
|
Reorganization Agreement, dated as of January 16, 2013, by and among CVR Refining, LP, CVR Refining GP, LLC, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Form 8-K filed by CVR Refining, LP on January 23, 2013 (Commission File No. 001-35781)).
|
|
|
21.1**
|
List of Subsidiaries of CVR Energy, Inc. (incorporated by reference to Exhibit 21.1 to the Company's Form 10-K for the year ended December 31, 2012, filed on March 14, 2013)
|
|
|
23.1*
|
Consent of Grant Thornton LLP.
|
|
|
23.2*
|
Consent of KPMG LLP.
|
|
|
31.1*
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
|
|
|
31.2*
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
|
|
|
32.1*
|
Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.
|
|
|
101*
|
The following financial information for CVR Energy, Inc.'s Annual Report on Form 10-K for the year ended December 31, 2013, formatted in XBRL ("Extensible Business Reporting Language") includes: (1) Consolidated Balance Sheets, (2) Consolidated Statements of Operations, (3) Consolidated Statements of Comprehensive Income, (4) Consolidated Statements of Changes in Equity, (5) Consolidated Statements of Cash Flows and (6) the Notes to Consolidated Financial Statements, tagged in detail.
|
*
|
|
Filed herewith.
|
|
|
|
**
|
|
Previously filed.
|
|
|
|
†
|
|
Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment which has been granted by the SEC.
|
|
|
|
++
|
|
Denotes management contract or compensatory plan or arrangement.
|
|
CVR Energy, Inc.
|
||
|
By:
|
/s/ JOHN J. LIPINSKI
|
|
|
|
Name:
|
John J. Lipinski
|
|
|
Title:
|
Chief Executive Officer and President
|
Signature
|
Title
|
Date
|
|
|
|
/s/ JOHN J. LIPINSKI
|
Chief Executive Officer, President and Director (Principal Executive Officer)
|
February 26, 2014
|
John J. Lipinski
|
|
|
|
|
|
/s/ SUSAN M. BALL
|
Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)
|
February 26, 2014
|
Susan M. Ball
|
|
|
|
|
|
|
Chairman of the Board of Directors
|
February 26, 2014
|
Carl C. Icahn
|
|
|
|
|
|
/s/ BOB G. ALEXANDER
|
Director
|
February 26, 2014
|
Bob G. Alexander
|
|
|
|
|
|
/s/ SUNGHWAN CHO
|
Director
|
February 26, 2014
|
SungHwan Cho
|
|
|
|
|
|
|
Director
|
February 26, 2014
|
Vincent J. Intrieri
|
|
|
|
|
|
/s/ SAMUEL MERKSAMER
|
Director
|
February 26, 2014
|
Samuel Merksamer
|
|
|
|
|
|
/s/ STEPHEN MONGILLO
|
Director
|
February 26, 2014
|
Stephen Mongillo
|
|
|
|
|
|
/s/ ANDREW ROBERTO
|
Director
|
February 26, 2014
|
Andrew Roberto
|
|
|
|
|
|
/s/ JAMES M. STROCK
|
Director
|
February 26, 2014
|
James M. Strock
|
|
|
Section 1.
|
Employment
.
|
Section 2.
|
Compensation
.
|
Section 3.
|
Employment Termination
.
|
Section 4.
|
Unauthorized Disclosure; Non-Solicitation; Non-Competition; Proprietary Rights
.
|
Section 5.
|
Representation
.
|
Section 6.
|
Withholding; Taxes
.
|
Section 7.
|
Effect of Section 280G of the Code
.
|
Section 8.
|
Miscellaneous
.
|
If to the Company:
|
CVR Energy, Inc.
10 E. Cambridge Circle, Suite 250 Kansas City, KS 66103 Attention: General Counsel Facsimile: (913) 982-5651 |
with a copy to:
|
Fried, Frank, Harris, Shriver & Jacobson LLP
One New York Plaza New York, NY 10004 Attention: Donald P. Carleen, Esq. Facsimile: (212) 859-4000 |
If to the Executive:
|
John J. Lipinski
2277 Plaza Drive, Suite 500 Sugar Land, TX 77479 Facsimile: (281) 207-3505 |
|
CVR Energy, Inc.
|
||
|
|
|
|
|
/s/ John J. Lipinski
|
By:
|
/s/ Stanley A. Riemann
|
|
JOHN J. LIPINSKI
|
Name:
|
Stanley A. Riemann
|
|
|
Title:
|
Chief Operating Officer
|
(i)
|
"Affiliate" means any Person that a Person either directly or indirectly through one or more intermediaries is in common control with, is controlled by or controls, each within the meaning of the Securities Act of 1933, as amended.
|
(ii)
|
"Control" means the possession, directly or indirectly, of the power to direct or cause the direction of management and policies of a Person, whether through the ownership of stock, by agreement or otherwise and "Controlled" has a corresponding meaning.
|
(iii)
|
"Principal" means Carl Icahn.
|
(iv)
|
"Principal Stockholder" means any of IEP Energy LLC, any Affiliate of IEP Energy LLC, the Principal and any Related Party.
|
(v)
|
"Related Party" means (1) the Principal and his siblings, his and their respective spouses and descendants (including stepchildren and adopted children) and the spouses of such descendants (including stepchildren and adopted children) (collectively, the "
Family Group
"); (2) any trust, estate, partnership, corporation, company, limited liability
|
(vi)
|
"Shares" means the common stock, par value $.01 per share, of the Company and any other securities into which such shares are changed or for which such shares are exchanged.
|
1.
|
Section 1.1.
Term
. Section 1.1 of the Employment Agreement shall be amended to read in its entirety as follows:
|
2.
|
Section 3.2(a).
Termination by the Company Other Than For Cause or Disability; Resignation by the Executive for Good Reason
. The first sentence of Section 3.2(a) of the Employment Agreement shall be amended to read in its entirety as follows:
|
3.
|
Section 3.2(b).
Change in Control Termination
. Section 3.2(b) of the Employment Agreement shall be amended to read in its entirety as follows:
|
4.
|
Section 3.2(d)(7).
Retirement
. Section 3.2(d)(7) of the Employment Agreement shall be amended to read in its entirety as follows:
|
5.
|
Appendix A.
Change in Control
. Appendix A of the Employment Agreement shall be amended to read in its entirety as follows:
|
(i)
|
“
Affiliate
” means any Person that a Person either directly or indirectly through one or more intermediaries is in common control with, is controlled by or controls, each within the meaning of the Securities Act of 1933, as amended.
|
(i)
|
“
Control
” means the possession, directly or indirectly, of the power to direct or cause the direction of management and policies of a Person, whether through the ownership of stock, by agreement or otherwise and “Controlled” has a corresponding meaning.
|
(ii)
|
“
Principal
” means Carl Icahn.
|
(iii)
|
“
Principal Stockholder
” means any of IEP Energy LLC, any Affiliate of IEP Energy LLC, the Principal and any Related Party.
|
(iv)
|
“
Related Party
” means (1) the Principal and his siblings, his and their respective spouses and descendants (including stepchildren and adopted children) and the spouses of such descendants (including stepchildren and adopted children) (collectively, the “
Family Group
”); (2) any trust, estate, partnership, corporation, company, limited liability company or unincorporated association or organization (each, an “
Entity
” and collectively “
Entities
”) Controlled by one or more members of the Family Group; (3) any Entity over which one or more members of the Family Group, directly or indirectly, have rights that, either legally or in practical effect, enable them to make or veto significant management decisions with respect to such Entity, whether pursuant to the constituent documents of such Entity, by contract, through representation on a board of directors or other governing body of such Entity, through a management position with such Entity or in any other manner (such rights, hereinafter referred to as “
Veto Power
”); (4) the estate of any member of the Family Group; (5) any trust created (in whole or in part) by any one or more members of the Family Group; (6) any individual or Entity who receives an interest in any estate or trust listed in clauses (4) or (5), to the extent of such interest; (7) any trust or estate, substantially all the beneficiaries of which (other than charitable organizations or foundations) consist of one or more members of the Family Group; (8) any organization described in Section 501(c) of the Code, over which any one or more members of the Family Group and the trusts and estates listed in clauses (4), (5) and (7) have direct or indirect Veto Power, or to which they are substantial contributors (as such term is defined in Section 507 of the Code); (9) any organization described in Section 501(c) of the Code of which a member of the Family Group is an officer, director or trustee; or (10) any Entity, directly or indirectly (a) owned or Controlled by or (b) a majority of the economic interests in which are owned by, or are for or accrue to the benefit of, in either case, any Person or Persons identified in clauses (1) through (9) above. For the purposes of this definition, and for the avoidance of doubt, in addition to any Person or Persons that may be considered to possess Control, (x) a partnership shall be considered Controlled by a general partner or managing general partner thereof, (y) a limited liability company shall be considered Controlled by a managing member of such limited liability company and (z) a trust or estate shall be considered Controlled by any trustee, executor, personal representative, administrator or any other Person or Persons having authority over the control, management or disposition of the income and assets therefrom.
|
(v)
|
“
Shares
” means the common stock, par value $.01 per share, of the Company and any other securities into which such shares are changed or for which such shares are exchanged.
|
|
CVR ENERGY, INC.
|
/s/ Susan M. Ball
|
By:
/s/ John J. Lipinski
|
SUSAN M. BALL
|
Name: John J. Lipinski
Title: Chief Executive Officer and President
|
|
|
i.
|
You will be entitled to receive a Pro-Rata Bonus, based on the actual performance of the Company for 2014, payable at such time as annual bonuses for 2014 are paid generally for the Company's executive officers.
|
ii.
|
You will receive a cash payment in the amount of $600,000.00 within thirty (30) days following the date that the Release (as defined below) becomes effective (the
"Retention Payment").
|
iii.
|
Subject to your timely election of, and continued eligibility for, COBRA continuation coverage, for six (6) months following the last day of the Additional Employment Period (or, if earlier, the date of your termination by the Company without Cause), the Company shall pay (or reimburse you for) any applicable premium for such coverage to the extent it exceeds the premium payable by a then active employee of the Company (the
"Health Continuation Amounts").
The Health Continuation Amounts shall commence to be paid upon the Release becoming effective.
|
1.
|
Section 1.1.
Term
. Section 1.1 of the Employment Agreement shall be amended to read in its entirety as follows:
|
2.
|
Section 3.2(a).
Termination by the Company Other Than For Cause or Disability; Resignation by the Executive for Good Reason
. The first sentence of Section 3.2(a) of the Employment Agreement shall be amended to read in its entirety as follows:
|
3.
|
Section 3.2(b).
Change in Control Termination
. Section 3.2(b) of the Employment Agreement shall be amended to read in its entirety as follows:
|
4.
|
Appendix A.
Change in Control
. Appendix A of the Employment Agreement shall be amended to read in its entirety as follows:
|
(i)
|
“
Affiliate
” means any Person that a Person either directly or indirectly through one or more intermediaries is in common control with, is controlled by or controls, each within the meaning of the Securities Act of 1933, as amended.
|
(i)
|
“
Control
” means the possession, directly or indirectly, of the power to direct or cause the direction of management and policies of a Person, whether through the ownership of stock, by agreement or otherwise and “Controlled” has a corresponding meaning.
|
(ii)
|
“
Principal
” means Carl Icahn.
|
(iii)
|
“
Principal Stockholder
” means any of IEP Energy LLC, any Affiliate of IEP Energy LLC, the Principal and any Related Party.
|
(iv)
|
“
Related Party
” means (1) the Principal and his siblings, his and their respective spouses and descendants (including stepchildren and adopted children) and the spouses of such descendants (including stepchildren and adopted children) (collectively, the “
Family Group
”); (2) any trust, estate,
|
(v)
|
“
Shares
” means the common stock, par value $.01 per share, of the Company and any other securities into which such shares are changed or for which such shares are exchanged.
|
|
CVR ENERGY, INC.
|
/s/ Edmund S Gross
|
By:
/s/ John J. Lipinski
|
EDMUND S. GROSS
|
Name: John J. Lipinski
Title: Chief Executive Officer and President
|
|
|
1.
|
Section 1.1.
Term
. Section 1.1 of the Employment Agreement shall be amended to read in its entirety as follows:
|
2.
|
Section 3.2(a).
Termination by the Company Other Than For Cause or Disability; Resignation by the Executive for Good Reason
. The first sentence of Section 3.2(a) of the Employment Agreement shall be amended to read in its entirety as follows:
|
3.
|
Section 3.2(d)(7).
Retirement
. Section 3.2(d)(7) of the Employment Agreement shall be amended to read in its entirety as follows:
|
4.
|
Appendix A.
Change in Control
. Appendix A of the Employment Agreement shall be amended to read in its entirety as follows:
|
(i)
|
“
Affiliate
” means any Person that a Person either directly or indirectly through one or more intermediaries is in common control with, is controlled by or controls, each within the meaning of the Securities Act of 1933, as amended.
|
(i)
|
“
Control
” means the possession, directly or indirectly, of the power to direct or cause the direction of management and policies of a Person, whether through the ownership of stock, by agreement or otherwise and “Controlled” has a corresponding meaning.
|
(ii)
|
“
Principal
” means Carl Icahn.
|
(iii)
|
“
Principal Stockholder
” means any of IEP Energy LLC, any Affiliate of IEP Energy LLC, the Principal and any Related Party.
|
(iv)
|
“
Related Party
” means (1) the Principal and his siblings, his and their respective spouses and descendants (including stepchildren and adopted children) and the spouses of such descendants (including stepchildren and adopted children) (collectively, the “
Family Group
”); (2) any trust, estate, partnership, corporation, company, limited liability company or unincorporated association or organization (each, an “
Entity
” and collectively “
Entities
”) Controlled by one or more members of the Family Group; (3) any Entity over which one or more members of the Family Group, directly or indirectly, have rights that, either legally or in practical effect, enable them to make or veto significant management decisions with respect to such Entity, whether pursuant to the constituent documents of such Entity, by contract, through representation on a board of directors or other governing body of such Entity, through a management position with such Entity or in any other manner (such rights, hereinafter referred to as “
Veto Power
”); (4) the estate of any member of the Family Group; (5) any trust created (in whole or in part) by any one or more members of the Family Group; (6) any individual or Entity who receives an interest in any estate or trust listed in clauses (4) or (5), to the extent of such interest; (7) any trust or estate, substantially all the beneficiaries of which (other than charitable organizations or foundations) consist of one or more members of the Family Group; (8) any organization described in Section 501(c) of the Code, over which any one or more members of the Family Group and the trusts and estates listed in clauses (4), (5) and (7)
|
(v)
|
“
Shares
” means the common stock, par value $.01 per share, of the Company and any other securities into which such shares are changed or for which such shares are exchanged.
|
|
CVR ENERGY, INC.
|
/s/ Robert W. Haugen
|
By:
/s/ John J. Lipinski
|
ROBERT W. HAUGEN
|
Name: John J. Lipinski
Title: Chief Executive Officer and President
|
|
|
Coffeyville Resources Refining & Marketing, LLC
|
Coffeyville Resources Nitrogen Fertilizers, LLC
|
||
|
|
|
|
By:
|
/s/ Robert W. Haugen
|
By:
|
/s/ Byron R. Kelley
|
Name:
|
Robert W. Haugen
|
Name:
|
Byron R. Kelley
|
Title:
|
Executive Vice President, Refining Operations
|
Title:
|
Chief Executive Officer and President
|
|
|
- Gaseous
|
|
- Purity
|
99.99 mol. % (minimum) (5 ppm oxygen maximum)
|
- Pressure
|
180 psig (
+
10 psig)
|
- Flow
|
20,000 scfh (normal); 40,000 scfh (maximum)
|
- Temperature
|
Ambient
|
- Price
|
$0.25 per cscf based on a total electric energy cost of $0.035 per KWH; provided, however, that this price will increase or decrease in the same percentage as the Fertilizer Company's electric bill from the City of Coffeyville (or from such other electric utility provider as the Fertilizer Company may have from time to time in the future) increases or decreases on a per/KWH basis and each such price adjustment shall apply to any gaseous nitrogen sold by Fertilizer Company after the date of such adjustment to the date of the next adjustment.
|
- Flow measurement
|
All Nitrogen flows shall be measured by a standard sharp edge orifice plate and differential pressure transmitter located at the Fertilizer Plant. The measured flow shall be pressure and temperature compensated and totalized by the Fertilizer Plant's Honeywell process control computer (TDC 3000) or any replacement computer. All transmitter signals and computer calculations are available to the Refinery through the existing communications bus for verification. Calibration of the transmitter shall be done at least annually and may be done more frequently at Refinery Company's request.
|
|
|
Oxygen
|
|
|
|
-Gaseous
|
|
-Purity
|
99.6 mol. % (minimum)
|
-Pressure
|
65 psig (± 5 psig)
|
-Flow
|
29.8 STPD (maximum)
|
-Temperature
|
Ambient
|
- Price
|
$0 per short ton for daily tons up to 10 STPD
$70 per short ton for daily tons from 10 STPD to 29.8 STPD
|
Such prices per short ton are based on a total electric cost of $0.035 per KWH; provided, however, that these prices per short ton will increase or decrease in the same percentage as the Fertilizer Company's electric bill from the City of Coffeyville (or from such other electric utility provider as the Fertilizer Company may have from time to time in the future) increases or decreases on a per/KWH basis and each such price adjustment shall apply to any gaseous Oxygen sold by Fertilizer Company after the date of such adjustment to the date of the next adjustment.
|
- Flow measurement
|
All High Pressure Steam flows shall be measured by a standard sharp edge orifice plate and differential pressure transmitter located at the Fertilizer Plant. The measured flow shall be totalized by the Fertilizer Plant's Honeywell process control computer (TDC 3000) or any replacement computer. All transmitter signals and computer calculations are available to the Refinery through the existing communications bus for verification. Calibration of the transmitter shall be done at least annually and may be done more frequently at Refinery Company's request.
|
|
|
Low Pressure Steam
|
|
|
|
-Flow
|
Variable
|
-Pressure
|
Approximately 120-170 psi
|
-Price
|
zero dollars ($0)
|
|
|
Tail Gas
|
|
|
|
- Gaseous
|
|
- Flow measurement
|
All Tail Gas flows will be measured by a standard sharp edge orifice plate or annubar and differential pressure transmitter located at the Fertilizer Plant. The measured flow shall be pressure and temperature compensated and totalized by the Fertilizer Plant's Honeywell process control computer (TDC 3000) or any replacement computer. All transmitter signals and computer calculations are available to the Refinery through the existing communications bus for verification. Calibration of the transmitter shall be done at least annually and may be done more frequently at Refinery Company's request.
|
- LHV / HHV
|
LHV means the lower heating value, and HHV means the higher heating value.
|
|
|
Firewater
|
|
|
|
- Pressure
|
185 psig (maximum)
100 psig (minimum)
|
- Temperature
|
70°F (normal)
|
- Flow
|
2,000 gpm (maximum)
0 gpm (normal)
|
-Price
|
zero dollars ($0)
|
|
|
Instrument Air
|
|
|
|
- Purity
|
-40°F dew point (normal operating)
|
- Pressure
|
125 psig
+
10 psi (normal operating)
|
- Flow
|
4000 scfm maximum (normal operating)
|
- Temperature
|
ambient
|
- Price
|
|
|
|
To the Refinery Company:
|
$18,000 per month (prorated on a per diem basis to reflect the number of days, including partial days, in the applicable month that Instrument Air is provided) based on $.035 total laid in cost per KWH; provided, that this price will increase or decrease in the same percentage as the Fertilizer Company's total laid in cost for electricity from the City of Coffeyville (or from such other electric utility provider as the Fertilizer Company may have from time to time in the future) increases or decreases on a per/KWH basis and each such price adjustment shall apply to any Instrument Air sold by Fertilizer Company after the date of such adjustment until the date of the next adjustment; provided, however, that such cost shall be reduced on a pro-rata basis for each day that such Instrument Air is not available from the Linde Facility.
|
|
|
To the Fertilizer Company:
|
$18,000 per month (prorated on a per diem basis to reflect the number of days, including partial days, in the applicable month that Instrument Air is provided) based on $.039 total laid in cost per KWH; provided, that this price will increase or decrease in the same percentage as the Refinery Company's total cost for electricity from Kansas Gas and Electric Company (or from such other electric utility provider as the Refinery Company may have from time to time in the future) increases or decreases on a per/KWH basis and each such price adjustment shall apply to any Instrument Air sold by Refinery Company after the date of such adjustment until the date of the next adjustment.
|
- Flow measurement
|
All Instrument Air flows shall be measured by a standard sharp edge orifice plate and differential pressure transmitter located at the Fertilizer Plant. The measured flow shall be totalized by the Fertilizer Plant's Honeywell process control computer (TDC 3000) or any replacement computer. All transmitter signals and computer calculations are available to the Refinery through the existing communications bus for verification. Calibration of the transmitter shall be done at least annually and may be done more frequently at Refinery Company's request.
|
1.
|
Purpose.
|
2.
|
Definitions.
|
3.
|
Administration.
|
4.
|
Stock Subject to the Plan; Grant Limitations.
|
5.
|
Stock Options.
|
6.
|
Stock Appreciation Rights.
|
7.
|
Dividend Equivalent Rights.
|
8.
|
Restricted Stock; Restricted Stock Units.
|
9.
|
Performance Awards.
|
10.
|
Share Awards.
|
11.
|
Effect of a Termination of Employment.
|
12.
|
Adjustment Upon Changes in Capitalization.
|
13.
|
Effect of Certain Transactions.
|
14.
|
Interpretation.
|
15.
|
Termination and Amendment of the Plan or Modification of Options and Awards.
|
16.
|
Non-Exclusivity of the Plan.
|
17.
|
Limitation of Liability.
|
18.
|
Regulations and Other Approvals; Governing Law.
|
19.
|
Miscellaneous.
|
i.
|
50% of the Performance Units attributable to Award 1 shall be subject to a performance objective relating to crude throughput (the “
Throughput Objective
”), with a target level of attaining crude throughput of an average of 168,500 barrels per day during the Award 1 Performance Cycle.
|
ii.
|
50% of the Performance Units attributable to Award 1 shall be subject to a performance objective relating to gathered crude (the “
Gathered Crude Objective
” and, together with the Throughput Objective, the “
Performance Objectives
”), with a target level of attaining an average of 52,000 gathered crude barrels per day during the Award 1 Performance Cycle.
|
i.
|
50% of the Performance Units attributable to Award 2 shall be subject to a Throughput Objective, with a target level of attaining crude throughput of an average of 176,500 barrels per day during the Award 2 Performance Cycle.
|
ii.
|
50% of the Performance Units attributable to Award 2 shall be subject to a Gathered Crude Objective, with a target level of attaining an average of 53,000 gathered crude barrels per day during the Award 2 Performance Cycle.
|
Level of Attainment of
Applicable Performance Objective
|
Performance
Factor
|
|
Equal to or Greater Than
|
But Less Than
|
|
0.0%
|
75%
|
0.0%
|
75.0%
|
80%
|
70.0%
|
80.0%
|
85%
|
80.0%
|
85.0%
|
90%
|
90.0%
|
90.0%
|
110%
|
100.0%
|
110.0%
|
N/A
|
110.0%
|
CVR ENERGY, INC.
|
GRANTEE
|
/s/ Stanley A. Riemann
|
/s/ John J. Lipinski
|
By: Stanley A. Riemann
|
Name: John J. Lipinski
|
Title: Chief Operating Officer
|
|
CVR ENERGY, INC.
|
GRANTEE
|
/s/ Stanley A. Riemann
|
/s/ John J. Lipinski
|
By: Stanley A. Riemann
|
Name: John J. Lipinski
|
Title: Chief Operating Officer
|
|
Date: February 26, 2014
|
By:
|
/s/ JOHN J. LIPINSKI
|
|
|
John J. Lipinski
Chief Executive Officer
|
Date: February 26, 2014
|
By:
|
/s/ SUSAN M. BALL
|
|
|
Susan M. Ball
Chief Financial Officer
|
Date: February 26, 2014
|
By:
|
/s/ JOHN J. LIPINSKI
|
|
|
John J. Lipinski
Chief Executive Officer
|
|
By:
|
/s/ SUSAN M. BALL
|
|
|
Susan M. Ball
Chief Financial Officer
|