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Share Name | Share Symbol | Market | Type |
---|---|---|---|
Cvr Refining, LP Common Units Representing Limited Partner Interests | NYSE:CVRR | NYSE | Ordinary Share |
Price Change | % Change | Share Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
---|---|---|---|---|---|---|---|---|
0.00 | 0.00% | 10.49 | 0.00 | 01:00:00 |
(Mark One)
|
|
þ
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
For the fiscal year ended December 31, 2016
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OR
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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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37-1702463
(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 units representing limited partner interests
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The New York Stock Exchange
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Large accelerated filer
o
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Accelerated filer
þ
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Non-accelerated filer
o
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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 14, 2017
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Common units representing limited partner interests
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147,600,000 units
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Page
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•
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common units representing limited partner interests, a portion of which we sold in the Initial Public Offering and which are listed on the NYSE; and
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•
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a general partner interest, which is not entitled to any distributions, and which is held by our general partner.
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•
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restrictions on operations or the need to install enhanced or additional controls;
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•
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the need to obtain and comply with permits, licenses and authorizations;
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•
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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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•
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specifications for the products marketed by us, primarily gasoline and diesel fuel.
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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 2020
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Total
Estimated
Costs
Through 2020
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||||||||
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(in millions)
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||||||||||||||
Coffeyville Refinery
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$
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0.2
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$
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—
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$
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1.0
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$
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1.2
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Phillipsburg Terminal
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0.5
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—
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0.7
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1.2
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||||
Wynnewood Refinery
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0.2
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—
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1.1
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1.3
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||||
Total Estimated Costs
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$
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0.9
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$
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—
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$
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2.8
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$
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3.7
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•
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major unplanned maintenance requirements;
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•
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catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire or natural disasters, including floods, windstorms and other similar events;
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•
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labor supply shortages or labor contract disputes that result in a work stoppage or slowdown;
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•
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cessation or suspension of a plant or specific operations dictated by environmental authorities; and
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•
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an event or incident involving a large clean-up, decontamination, or the imposition of laws and ordinances regulating the cost and schedule of demolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition.
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•
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limiting our ability to obtain additional financing to fund our working capital needs, capital expenditures, debt service requirements, acquisitions or other purposes;
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•
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requiring us to utilize a significant portion of our cash flows to service our indebtedness, thereby reducing available cash and our ability to make distributions on our common units;
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•
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limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt;
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•
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limiting our ability to compete with other companies who are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions;
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•
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restricting us from making strategic acquisitions, introducing new technologies or exploiting business opportunities;
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restricting the way in which we conduct our business because of financial and operating covenants in the agreements governing our and our subsidiaries' existing and future indebtedness, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to us;
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•
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exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in our or our subsidiaries' debt instruments that could have a material adverse effect on our business, financial condition and operating results;
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•
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increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and
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•
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limiting our ability to react to changing market conditions in our industry and in our customers' industries.
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•
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incur additional indebtedness or issue certain preferred units;
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pay distributions in respect of our units or make other restricted payments;
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make certain payments on debt that is subordinated or secured on a junior basis;
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make certain investments;
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sell certain assets;
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create liens on certain assets;
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consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
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enter into certain transactions with our affiliates; and
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designate our subsidiaries as unrestricted subsidiaries.
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Although we believe we have sufficient liquidity under the Amended and Restated ABL Credit Facility and the intercompany credit facility to operate both the Coffeyville and Wynnewood refineries, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all.
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•
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Market volatility could exert downward pressure on the price of our common units, which may make it more difficult for us to raise additional capital and thereby limit our ability to grow, which could in turn cause the price of our common units to drop.
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•
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Market conditions could result in our significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons could result in decreased sales and earnings for us.
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•
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the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;
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•
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accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refinery or our suppliers or customers;
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•
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the counterparties to our 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 our facilities, or those of our 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, our vendors, suppliers, contractors or sub-contractors.
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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 our 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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Neither our partnership agreement nor any other agreement requires the owners of our general partner, including CVR Energy, to pursue a business strategy that favors us. The affiliates of our general partner, including CVR Energy, have fiduciary duties to make decisions in their own best interests and in the best interest of holders of CVR Energy's common stock, including IEP, which may be contrary to our interests. In addition, our general partner is allowed to take into account the interests of parties other than us or our unitholders, such as its owners or CVR Energy, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
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•
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Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. There is no limitation on the amounts our general partner can cause us to pay it or its affiliates.
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Our general partner controls the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner decides whether to retain separate counsel or others to perform services for us.
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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
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Our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or our common unitholders. Decisions made by our general partner in its individual capacity are made by CVR Refining Holdings as the sole member of our general partner, and not by the board of directors of our general partner. Examples include the exercise of the general partner's call right, its voting rights with respect to any common units it may own, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement.
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•
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Our partnership agreement provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it did not make such decisions in bad faith, meaning it believed that the decisions were adverse to our interest.
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Our partnership agreement provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to 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 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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Our partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or
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approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates.
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business strategy and policies;
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mergers or other business combinations;
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the acquisition or disposition of assets;
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•
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future issuances of common units or other securities;
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•
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incurrence of debt or obtaining other sources of financing; and
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•
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the Partnership's distribution policy and the payment of distributions on the Partnership's common units.
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•
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the proportionate ownership interest of unitholders immediately prior to the issuance will decrease;
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•
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the amount of cash distributions on each unit will decrease;
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•
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the ratio of our taxable income to distributions may increase;
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•
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the relative voting strength of each previously outstanding unit will be diminished; and
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•
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the market price of the common units may decline.
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•
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the requirement that a majority of the board of directors of our general partner consist of independent directors;
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•
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the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and
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•
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the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.
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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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380
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Own
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Oil refinery and office buildings
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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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2016
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High
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Low
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||||
First Quarter
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$
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20.25
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$
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10.17
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Second Quarter
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13.25
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7.33
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Third Quarter
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11.25
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5.50
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Fourth Quarter
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11.00
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6.45
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2015
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High
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Low
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||||
First Quarter
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$
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21.18
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$
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13.37
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Second Quarter
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22.59
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18.02
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Third Quarter
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21.23
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17.30
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Fourth Quarter
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22.74
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18.26
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December 31, 2014
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March 31, 2015
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June 30, 2015
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September 30, 2015
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Total Cash
Distributions
Paid in 2015
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||||||||||
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(in millions, except per unit data)
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||||||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates
|
$
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38.2
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$
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78.5
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$
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101.2
|
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$
|
104.4
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$
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322.3
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Amounts paid to non-affiliates
|
16.4
|
|
|
33.7
|
|
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43.4
|
|
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44.7
|
|
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138.2
|
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|||||
Total amount paid
|
$
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54.6
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|
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$
|
112.2
|
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|
$
|
144.6
|
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$
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149.1
|
|
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$
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460.5
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Per common unit
|
$
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0.37
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|
$
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0.76
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$
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0.98
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$
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1.01
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|
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$
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3.12
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|
Common units outstanding
|
147.6
|
|
|
147.6
|
|
|
147.6
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147.6
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|
|
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Jan '13
|
|
Mar '13
|
|
Jun '13
|
|
Sep '13
|
|
Dec '13
|
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Mar '14
|
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Jun '14
|
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Sep '14
|
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Dec '14
|
|||||||||
CVR Refining, LP
|
100.00
|
|
|
138.48
|
|
|
125.71
|
|
|
109.41
|
|
|
100.61
|
|
|
105.69
|
|
|
117.62
|
|
|
113.83
|
|
|
84.00
|
|
Russell 2000 Index
|
100.00
|
|
|
106.87
|
|
|
109.78
|
|
|
120.60
|
|
|
130.69
|
|
|
131.75
|
|
|
133.99
|
|
|
123.73
|
|
|
135.30
|
|
Peer Group
|
100.00
|
|
|
120.45
|
|
|
98.15
|
|
|
88.06
|
|
|
125.78
|
|
|
117.54
|
|
|
115.11
|
|
|
121.97
|
|
|
121.16
|
|
|
Mar '15
|
|
Jun '15
|
|
Sep '15
|
|
Dec '15
|
|
Mar '16
|
|
Jun '16
|
|
Sep '16
|
|
Dec '16
|
||||||||
CVR Refining, LP
|
105.85
|
|
|
96.82
|
|
|
106.24
|
|
|
110.12
|
|
|
70.27
|
|
|
45.08
|
|
|
51.02
|
|
|
60.50
|
|
Russell 2000 Index
|
140.70
|
|
|
140.84
|
|
|
123.62
|
|
|
127.58
|
|
|
125.12
|
|
|
129.38
|
|
|
140.58
|
|
|
152.42
|
|
Peer Group
|
155.24
|
|
|
151.09
|
|
|
152.70
|
|
|
148.45
|
|
|
117.11
|
|
|
92.37
|
|
|
104.10
|
|
|
134.23
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions, except per unit data)
|
||||||||||||||||||
Statements of Operations Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net sales
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
|
$
|
8,829.7
|
|
|
$
|
8,683.5
|
|
|
$
|
8,281.7
|
|
Cost of materials and other
|
3,759.2
|
|
|
4,143.6
|
|
|
8,013.4
|
|
|
7,526.7
|
|
|
6,667.5
|
|
|||||
Direct operating expenses(1)
|
393.4
|
|
|
478.5
|
|
|
416
|
|
|
361.7
|
|
|
426.5
|
|
|||||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Depreciation and amortization
|
126.3
|
|
|
128.0
|
|
|
120.9
|
|
|
113.9
|
|
|
107.1
|
|
|||||
Cost of sales
|
4,278.9
|
|
|
4,722.8
|
|
|
8,550.3
|
|
|
8,002.3
|
|
|
7,201.1
|
|
|||||
Selling, general and administrative expenses(1)
|
71.9
|
|
|
75.2
|
|
|
70.6
|
|
|
77.8
|
|
|
86.2
|
|
|||||
Depreciation and amortization
|
2.7
|
|
|
2.2
|
|
|
1.6
|
|
|
0.4
|
|
|
0.5
|
|
|||||
Operating income
|
77.8
|
|
|
361.7
|
|
|
207.2
|
|
|
603.0
|
|
|
993.9
|
|
|||||
Interest expense and other financing costs
|
(43.4
|
)
|
|
(42.6
|
)
|
|
(34.2
|
)
|
|
(44.1
|
)
|
|
(76.2
|
)
|
|||||
Interest income
|
0.1
|
|
|
0.4
|
|
|
0.3
|
|
|
0.4
|
|
|
—
|
|
|||||
Gain (loss) on derivatives, net
|
(19.4
|
)
|
|
(28.6
|
)
|
|
185.6
|
|
|
57.1
|
|
|
(285.6
|
)
|
|||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
(26.1
|
)
|
|
(37.5
|
)
|
|||||
Other income (expense), net
|
0.2
|
|
|
0.3
|
|
|
(0.2
|
)
|
|
0.1
|
|
|
0.7
|
|
|||||
Income before income tax expense
|
15.3
|
|
|
291.2
|
|
|
358.7
|
|
|
590.4
|
|
|
595.3
|
|
|||||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Net income
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
$
|
358.7
|
|
|
$
|
590.4
|
|
|
$
|
595.3
|
|
Available cash for distribution(2)
|
$
|
0.3
|
|
|
$
|
402.0
|
|
|
$
|
421.5
|
|
|
$
|
546.0
|
|
|
|
||
Net income subsequent to initial public offering (January 23, 2013 through December 31, 2013)
|
|
|
|
|
|
|
|
$
|
512.6
|
|
|
|
|||||||
Net income per common unit – basic and diluted(3)
|
$
|
0.10
|
|
|
$
|
1.97
|
|
|
$
|
2.43
|
|
|
$
|
3.47
|
|
|
|
||
|
|
|
|
|
|
|
|
|
|
||||||||||
Weighted average common units outstanding:
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic and Diluted
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Balance Sheet Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash and cash equivalents
|
$
|
314.1
|
|
|
$
|
187.3
|
|
|
$
|
370.2
|
|
|
$
|
279.8
|
|
|
$
|
153.1
|
|
Working capital(4)
|
313.7
|
|
|
297.5
|
|
|
503.6
|
|
|
656.0
|
|
|
380.9
|
|
|||||
Total assets(4)
|
2,331.9
|
|
|
2,189.0
|
|
|
2,410.7
|
|
|
2,525.3
|
|
|
2,246.2
|
|
|||||
Total debt, including current portion(4)
|
541.5
|
|
|
573.8
|
|
|
574.3
|
|
|
574.7
|
|
|
760.9
|
|
|||||
Total partners' capital/divisional equity
|
1,296.7
|
|
|
1,281.4
|
|
|
1,450.1
|
|
|
1,522.1
|
|
|
980.8
|
|
|||||
Cash Flow Data
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash flow provided by (used in):
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
$
|
267.8
|
|
|
$
|
473.7
|
|
|
$
|
715.8
|
|
|
$
|
601.0
|
|
|
$
|
917.3
|
|
Investing activities
|
(107.9
|
)
|
|
(194.7
|
)
|
|
(191.2
|
)
|
|
(204.4
|
)
|
|
(119.8
|
)
|
|||||
Financing activities(5)
|
(33.1
|
)
|
|
(461.9
|
)
|
|
(434.2
|
)
|
|
(269.9
|
)
|
|
(647.1
|
)
|
|||||
Net cash flow
|
$
|
126.8
|
|
|
$
|
(182.9
|
)
|
|
$
|
90.4
|
|
|
$
|
126.7
|
|
|
$
|
150.4
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures for property, plant and equipment
|
$
|
102.3
|
|
|
$
|
194.7
|
|
|
$
|
191.3
|
|
|
$
|
204.5
|
|
|
$
|
120.2
|
|
|
(1)
|
Amounts are shown exclusive of depreciation and amortization.
|
(2)
|
Available cash for distribution is generally equal to Adjusted EBITDA reduced for cash needed for (i) debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Available cash for distribution is not a recognized term under GAAP. Available cash should not be considered in isolation or as an alternative to net income or operating income, as a measure of operating performance. In addition, available cash for distribution is not presented as, and should not be considered an alternative to cash flows from operations or as a measure of liquidity. Available cash as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure. For the year ended December 31, 2013, available cash for distribution is calculated for the period beginning at the closing of our Initial Public Offering (January 23, 2013 through December 31, 2013).
|
(3)
|
We have omitted net income per unit for the year ended December 31, 2012 because we operated under a different capital structure prior to the closing of the Initial Public Offering, and, as a result, the per unit data would not be meaningful to investors. Per unit data for the year ended December 31, 2013 is calculated since the closing of the Initial Public Offering on January 23, 2013.
|
(4)
|
Prior period amounts have been retrospectively adjusted for Accounting Standard Update No. 2015-03, which requires that costs incurred to issue debt be presented in the balance sheet as a direct reduction from the carrying value of the debt.
|
(5)
|
Prior to December 31, 2012, Coffeyville Resources, LLC ("CRLLC") provided cash as necessary to support our operations and retained excess cash generated by our operations. Historical cash received, or paid by, CRLLC on our behalf has been recorded as net contributions from, or net distributions to, parent, respectively, as a component of divisional equity in our historical combined financial statements, and as a financing activity in our Combined Statements of Cash Flows. Net distributions to parent included in cash flows from financing activities were
$651.6 million
for the year ended December 31, 2012.
|
•
|
statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;
|
•
|
statements relating to future financial or operational performance, future distributions, future capital sources and capital expenditures; and
|
•
|
any other statements preceded by, followed by or that include the words "anticipates," "believes," "expects," \"plans," "intends," "estimates," "projects," "could," "should," "may," or similar expressions.
|
•
|
our ability to make cash distributions on the common units;
|
•
|
the price volatility of crude oil, other feedstocks and refined products, and variable nature of our distributions;
|
•
|
the ability of our general partner to modify or revoke our distribution policy at any time;
|
•
|
our ability to forecast our future financial condition or results of operations and our future revenues and expenses;
|
•
|
the effects of transactions involving forward and derivative instruments;
|
•
|
our ability in the future to obtain an adequate crude oil supply pursuant to supply agreements or at all;
|
•
|
our continued access to crude oil and other feedstock and refined products pipelines;
|
•
|
the level of competition from other petroleum refiners;
|
•
|
changes in our credit profile;
|
•
|
potential operating consequences from accidents, fire, severe weather, floods, or other natural disasters, or other operating hazards resulting in unscheduled downtime;
|
•
|
our continued ability to secure RINs, as well as environmental and other governmental permits necessary for the operation of our business;
|
•
|
costs of compliance with existing, or compliance with new, environmental laws and regulations, as well as the potential liabilities arising from, and capital expenditures required to, remediate current or future contamination;
|
•
|
the seasonal nature of our business;
|
•
|
our dependence on significant customers;
|
•
|
our potential inability to obtain or renew permits;
|
•
|
our ability to continue safe, reliable operations without unplanned maintenance events prior to and when approaching the end-of-cycle turnaround operations;
|
•
|
new regulations concerning the transportation of hazardous chemicals, risks of terrorism, and the security of chemical manufacturing facilities;
|
•
|
the risk of security breaches;
|
•
|
our lack of asset diversification;
|
•
|
the potential loss of our transportation cost advantage over our competitors;
|
•
|
our ability to comply with employee safety laws and regulations;
|
•
|
potential disruptions in the global or U.S. capital and credit markets;
|
•
|
the success of our acquisition and expansion strategies;
|
•
|
our reliance on CVR Energy's senior management team;
|
•
|
the risk of a substantial increase in costs or work stoppages associated with negotiating collective bargaining agreements with the unionized portion of our workforce;
|
•
|
the potential shortage of skilled labor or loss of key personnel;
|
•
|
successfully defending against third-party claims of intellectual property infringement;
|
•
|
our indebtedness;
|
•
|
our potential inability to generate sufficient cash to service all of our indebtedness;
|
•
|
the limitations contained in our debt agreements that limit our flexibility in operating our business;
|
•
|
the dependence on our subsidiaries for cash to meet our debt obligations;
|
•
|
our limited operating history as a stand-alone entity;
|
•
|
potential increases in costs and distraction of management resulting from the requirements of being a publicly traded partnership;
|
•
|
exemptions we will rely on in connection with the NYSE corporate governance requirements;
|
•
|
risks relating to our relationships with CVR Energy;
|
•
|
risks relating to the control of our general partner by CVR Energy;
|
•
|
the conflicts of interest faced by our senior management team, which operates both us and CVR Energy, and our general partner;
|
•
|
limitations on duties owed by our general partner that are included in the partnership agreement;
|
•
|
changes in our treatment as a partnership for U.S. income or state tax purposes; and
|
•
|
instability and volatility in the capital and credit markets.
|
|
|
Year Ended December 31,
|
|||||||
|
|
2016
|
|
2015
|
|
2014
|
|||
|
|
(in millions)
|
|||||||
Share-based compensation(1)
|
|
4.9
|
|
|
9.3
|
|
|
8.0
|
|
(Gain) loss on derivatives, net
|
|
19.4
|
|
|
28.6
|
|
|
(185.6
|
)
|
Major scheduled turnaround expenses(2)
|
|
31.5
|
|
|
102.2
|
|
|
6.8
|
|
Flood insurance recovery(3)
|
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
(1)
|
Represents impact of share-based compensation awards.
|
(2)
|
Represents expense associated with major scheduled turnaround activities performed at our Coffeyville refinery (
$31.5 million
in 2016,
$102.2 million
in 2015 and
$5.5 million
in 2014) and our Wynnewood refinery (
1.3 million
in 2014).
|
(3)
|
Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery on June/July 2007. Refer to Part II, Item 8,
Note 11 ("Commitments and Contingencies")
, of this Report for further details.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Consolidated Statements of Operations Data
|
|
|
|
|
|
||||||
Net sales
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
|
$
|
8,829.7
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of materials and other
|
3,759.2
|
|
|
4,143.6
|
|
|
8,013.4
|
|
|||
Direct operating expenses(1)(2)
|
361.9
|
|
|
376.3
|
|
|
409.2
|
|
|||
Major scheduled turnaround expenses
|
31.5
|
|
|
102.2
|
|
|
6.8
|
|
|||
Depreciation and amortization
|
126.3
|
|
|
128.0
|
|
|
120.9
|
|
|||
Cost of sales
|
4,278.9
|
|
|
4,750.1
|
|
|
8,550.3
|
|
|||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|||
Selling, general and administrative expenses(1)
|
71.9
|
|
|
75.2
|
|
|
70.6
|
|
|||
Depreciation and amortization
|
2.7
|
|
|
2.2
|
|
|
1.6
|
|
|||
Operating income
|
77.8
|
|
|
361.7
|
|
|
207.2
|
|
|||
Interest expense and other financing costs
|
(43.4
|
)
|
|
(42.6
|
)
|
|
(34.2
|
)
|
|||
Interest income
|
0.1
|
|
|
0.4
|
|
|
0.3
|
|
|||
Gain (loss) on derivatives, net
|
(19.4
|
)
|
|
(28.6
|
)
|
|
185.6
|
|
|||
Other income (expense), net
|
0.2
|
|
|
0.3
|
|
|
(0.2
|
)
|
|||
Income before income tax expense
|
15.3
|
|
|
291.2
|
|
|
358.7
|
|
|||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
$
|
358.7
|
|
Gross profit(3)
|
$
|
152.4
|
|
|
$
|
439.1
|
|
|
$
|
279.4
|
|
Refining margin(4)
|
$
|
672.1
|
|
|
$
|
1,018.3
|
|
|
$
|
816.3
|
|
Adjusted EBITDA(5)
|
$
|
222.8
|
|
|
$
|
602.0
|
|
|
$
|
621.6
|
|
Available cash for distribution(6)
|
$
|
0.3
|
|
|
$
|
402.0
|
|
|
$
|
421.5
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(dollars per barrel)
|
||||||||||
Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Gross profit(3)
|
$
|
2.10
|
|
|
$
|
6.23
|
|
|
$
|
3.90
|
|
Refining margin(4)
|
$
|
9.27
|
|
|
$
|
14.45
|
|
|
$
|
11.38
|
|
Direct operating expenses and major scheduled turnaround expenses(1)(2)
|
$
|
5.43
|
|
|
$
|
6.79
|
|
|
$
|
5.80
|
|
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(7)
|
$
|
5.08
|
|
|
$
|
6.40
|
|
|
$
|
5.44
|
|
Barrels sold (barrels per day)(7)
|
211,643
|
|
|
204,708
|
|
|
209,669
|
|
|
Year Ended December 31,
|
||||||||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
||||||
Refining Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Sweet
|
177,256
|
|
|
84.8
|
|
176,097
|
|
|
86.0
|
|
179,059
|
|
|
86.2
|
|||
Medium
|
2,525
|
|
|
1.2
|
|
2,460
|
|
|
1.2
|
|
2,022
|
|
|
1.0
|
|||
Heavy sour
|
18,261
|
|
|
8.7
|
|
14,520
|
|
|
7.1
|
|
15,464
|
|
|
7.4
|
|||
Total crude oil throughput
|
198,042
|
|
|
94.7
|
|
193,077
|
|
|
94.3
|
|
196,545
|
|
|
94.6
|
|||
All other feedstocks and blendstocks
|
11,077
|
|
|
5.3
|
|
11,672
|
|
|
5.7
|
|
11,284
|
|
|
5.4
|
|||
Total throughput
|
209,119
|
|
|
100.0
|
|
204,749
|
|
|
100.0
|
|
207,829
|
|
|
100.0
|
|||
Production:
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gasoline
|
108,762
|
|
|
51.9
|
|
99,961
|
|
|
48.5
|
|
102,275
|
|
|
48.9
|
|||
Distillate
|
85,092
|
|
|
40.6
|
|
85,953
|
|
|
41.7
|
|
87,639
|
|
|
41.9
|
|||
Other (excluding internally produced fuel)
|
15,751
|
|
|
7.5
|
|
20,074
|
|
|
9.8
|
|
19,149
|
|
|
9.2
|
|||
Total refining production (excluding internally produced fuel)
|
209,605
|
|
|
100.0
|
|
205,988
|
|
|
100.0
|
|
209,063
|
|
|
100.0
|
|||
Product price (dollars per gallon):
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Gasoline
|
$
|
1.34
|
|
|
|
|
$
|
1.61
|
|
|
|
|
$
|
2.53
|
|
|
|
Distillate
|
1.36
|
|
|
|
|
1.62
|
|
|
|
|
2.81
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
Market Indicators (dollars per barrel)
|
|
|
|
|
|
||||||
West Texas Intermediate (WTI) NYMEX
|
$
|
43.47
|
|
|
$
|
48.76
|
|
|
$
|
92.91
|
|
Crude Oil Differentials:
|
|
|
|
|
|
||||||
WTI less WTS (light/medium sour)
|
0.85
|
|
|
(0.28
|
)
|
|
5.95
|
|
|||
WTI less WCS (heavy sour)
|
13.95
|
|
|
13.20
|
|
|
18.48
|
|
|||
NYMEX Crack Spreads:
|
|
|
|
|
|
||||||
Gasoline
|
15.42
|
|
|
19.89
|
|
|
17.29
|
|
|||
Heating Oil
|
13.89
|
|
|
20.93
|
|
|
23.59
|
|
|||
NYMEX 2-1-1 Crack Spread
|
14.66
|
|
|
20.41
|
|
|
20.44
|
|
|||
PADD II Group 3 Product Basis:
|
|
|
|
|
|
||||||
Gasoline
|
(3.62
|
)
|
|
(2.12
|
)
|
|
(4.45
|
)
|
|||
Ultra Low Sulfur Diesel
|
(0.92
|
)
|
|
(2.02
|
)
|
|
0.75
|
|
|||
PADD II Group 3 Product Crack Spread:
|
|
|
|
|
|
||||||
Gasoline
|
11.82
|
|
|
17.76
|
|
|
12.84
|
|
|||
Ultra Low Sulfur Diesel
|
12.96
|
|
|
18.91
|
|
|
24.34
|
|
|||
PADD II Group 3 2-1-1
|
12.39
|
|
|
18.34
|
|
|
18.59
|
|
|
(1)
|
Our direct operating expenses and selling, general and administrative expenses for the years ended
December 31, 2016
,
2015
and
2014
are shown exclusive of depreciation and amortization (Refer to Part II, Item 8,
Note 2 ("Summary of Significant Accounting Policies")
of this report for further details.)
|
(2)
|
Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.
|
(3)
|
Gross profit, a GAAP measure, is calculated as the difference between net sales and cost of materials and other, direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, flood insurance recovery and depreciation and amortization. Each of the components used in this calculation are taken directly from our Consolidated Statements of Operations. In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.
|
(4)
|
Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of materials and other. Refining margin is a non-GAAP measure that management believes is important to investors in evaluating the performance of our refineries as a general indication of the amount above our cost of materials and other at which we are able to sell refined products. Each of the components used in this calculation (net sales and cost of materials and other) are taken directly from our Consolidated Statements of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our 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 our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.
|
|
Year Ended
December 31, |
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net Sales
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
|
$
|
8,829.7
|
|
Cost of materials and other
|
3,759.2
|
|
|
4,143.6
|
|
|
8,013.4
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
361.9
|
|
|
376.3
|
|
|
409.2
|
|
|||
Major scheduled turnaround expenses
|
31.5
|
|
|
102.2
|
|
|
6.8
|
|
|||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|||
Depreciation and amortization
|
126.3
|
|
|
128.0
|
|
|
120.9
|
|
|||
Gross Profit
|
152.4
|
|
|
439.1
|
|
|
279.4
|
|
|||
Add:
|
|
|
|
|
|
||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
361.9
|
|
|
376.3
|
|
|
409.2
|
|
|||
Major scheduled turnaround expenses
|
31.5
|
|
|
102.2
|
|
|
6.8
|
|
|||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|||
Depreciation and amortization
|
126.3
|
|
|
128.0
|
|
|
120.9
|
|
|||
Refining Margin
|
$
|
672.1
|
|
|
$
|
1,018.3
|
|
|
$
|
816.3
|
|
|
Year Ended
December 31, |
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Total crude oil throughput barrels per day
|
198,042
|
|
|
193,077
|
|
|
196,545
|
|
Days in the period
|
366
|
|
|
365
|
|
|
365
|
|
Total crude oil throughput barrels
|
72,483,372
|
|
|
70,473,105
|
|
|
71,738,925
|
|
|
Year Ended
December 31, |
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining Margin
|
$
|
672.1
|
|
|
$
|
1,018.3
|
|
|
$
|
816.3
|
|
Divided by: crude oil throughput barrels
|
72.5
|
|
|
70.5
|
|
|
71.7
|
|
|||
Refining Margin per crude oil throughput barrel
|
$
|
9.27
|
|
|
$
|
14.45
|
|
|
$
|
11.38
|
|
(5)
|
EBITDA and Adjusted EBITDA.
EBITDA represents net income (loss) before (i) interest expense and other financing costs, net of interest income, (ii) income tax expense and (iii) depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted for (i) FIFO impact (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and Adjustment EBITDA), (v) (gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) flood insurance recovery.
|
|
Three Months Ended
December 31, |
|
Year Ended December 31,
|
||||||||||||
|
2016
|
|
2016
|
|
2015
|
|
2014
|
||||||||
|
(in millions)
|
||||||||||||||
|
(unaudited)
|
||||||||||||||
Net income (loss)
|
$
|
(10.7
|
)
|
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
$
|
358.7
|
|
Add:
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs, net of interest income
|
11.6
|
|
|
43.3
|
|
|
42.2
|
|
|
33.9
|
|
||||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Depreciation and amortization
|
33.4
|
|
|
129.0
|
|
|
130.2
|
|
|
122.5
|
|
||||
EBITDA
|
34.3
|
|
|
187.6
|
|
|
463.6
|
|
|
515.1
|
|
||||
Add:
|
|
|
|
|
|
|
|
||||||||
FIFO impact (favorable) unfavorable(a)
|
(22.4
|
)
|
|
(52.1
|
)
|
|
60.3
|
|
|
160.8
|
|
||||
Share-based compensation, non-cash
|
—
|
|
|
—
|
|
|
0.6
|
|
|
2.3
|
|
||||
Loss on extinguishment of debt
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Major scheduled turnaround expenses(b)
|
—
|
|
|
31.5
|
|
|
102.2
|
|
|
6.8
|
|
||||
(Gain) loss on derivatives, net
|
14.6
|
|
|
19.4
|
|
|
28.6
|
|
|
(185.6
|
)
|
||||
Current period settlements on derivative contracts(c)
|
1.2
|
|
|
36.4
|
|
|
(26.0
|
)
|
|
122.2
|
|
||||
Flood insurance recovery(d)
|
—
|
|
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
||||
Adjusted EBITDA
|
$
|
27.7
|
|
|
$
|
222.8
|
|
|
$
|
602.0
|
|
|
$
|
621.6
|
|
|
(a)
|
FIFO is our basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period.
|
(b)
|
Represents expense associated with major scheduled turnaround activities performed at the Coffeyville refinery (
$31.5 million
in 2016,
$102.2 million
in 2015 and
$5.5 million
in 2014) and the Wynnewood refinery (
$1.3 million
in 2014).
|
(c)
|
Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.
|
(d)
|
Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery on June/July 2007. Refer to Part II, Item 8,
Note 11 ("Commitments and Contingencies")
of this Report for further details.
|
(6)
|
Available cash for distribution is generally equal to Adjusted EBITDA reduced for cash needed for (i) debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Available cash for distribution is not a recognized term under GAAP. Available cash for distribution should not be considered in isolation or as an alternative to net income (loss) or operating income (loss), as a measure of operating performance. In addition, available cash for distribution is not presented as, and should not be considered an alternative to cash flows from operations or as a measure of liquidity. Available cash for distribution as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure. Below is a table reconciling the available cash for distribution for the three months and year ended
December 31, 2016
:
|
|
|
Three Months Ended
December 31, 2016 |
|
Year Ended December 31, 2016
|
||||
|
|
(in millions, except per unit data)
|
||||||
Reconciliation of Adjusted EBITDA to Available cash for distribution
|
|
|
|
|
||||
Adjusted EBITDA
|
|
$
|
27.7
|
|
|
$
|
222.8
|
|
Adjustments:
|
|
|
|
|
||||
Less:
|
|
|
|
|
||||
Cash needs for debt service
|
|
(10.0
|
)
|
|
(40.0
|
)
|
||
Reserves for environmental and maintenance capital expenditures
|
|
(17.7
|
)
|
|
(114.1
|
)
|
||
Reserves for major scheduled turnaround expenses
|
|
—
|
|
|
(48.7
|
)
|
||
Reserves for future operating needs
|
|
—
|
|
|
(19.7
|
)
|
||
Available cash for distribution
|
|
$
|
—
|
|
|
$
|
0.3
|
|
Available cash for distribution, per unit
|
|
$
|
—
|
|
|
$
|
—
|
|
Distribution declared, per unit
|
|
$
|
—
|
|
|
$
|
—
|
|
Common units outstanding (in thousands)
|
|
147,600
|
|
|
147,600
|
|
(7)
|
Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Coffeyville Refinery Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
2,948.9
|
|
|
$
|
3,220.6
|
|
|
$
|
5,755.5
|
|
Cost of materials and other
|
2,513.9
|
|
|
2,626.1
|
|
|
5,254.9
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
196.4
|
|
|
209.1
|
|
|
223.6
|
|
|||
Major scheduled turnaround expenses
|
31.5
|
|
|
102.2
|
|
|
5.5
|
|
|||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|||
Depreciation and amortization
|
69.7
|
|
|
72.1
|
|
|
73.6
|
|
|||
Gross profit
|
$
|
137.4
|
|
|
$
|
238.4
|
|
|
$
|
197.9
|
|
Plus:
|
|
|
|
|
|
||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below)
|
227.9
|
|
|
311.3
|
|
|
229.1
|
|
|||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|||
Depreciation and amortization
|
69.7
|
|
|
72.1
|
|
|
73.6
|
|
|||
Refining margin(1)
|
$
|
435.0
|
|
|
$
|
594.5
|
|
|
$
|
500.6
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(dollars per barrel)
|
||||||||||
Coffeyville Refinery Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Gross profit
|
$
|
3.03
|
|
|
$
|
5.77
|
|
|
$
|
4.53
|
|
Refining margin(1)
|
$
|
9.57
|
|
|
$
|
14.37
|
|
|
$
|
11.46
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
$
|
5.02
|
|
|
$
|
7.53
|
|
|
$
|
5.24
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold
|
$
|
4.54
|
|
|
$
|
6.92
|
|
|
$
|
4.73
|
|
Barrels sold (barrels per day)
|
137,047
|
|
|
123,279
|
|
|
132,791
|
|
|
Year Ended December 31,
|
|||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
|||
Coffeyville Refinery Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Sweet
|
104,679
|
|
|
78.9
|
|
96,727
|
|
|
79.5
|
|
103,018
|
|
|
80.0
|
Medium
|
1,229
|
|
|
0.9
|
|
2,058
|
|
|
1.7
|
|
1,222
|
|
|
1.0
|
Heavy sour
|
18,261
|
|
|
13.8
|
|
14,520
|
|
|
11.9
|
|
15,464
|
|
|
12.0
|
Total crude oil throughput
|
124,169
|
|
|
93.6
|
|
113,305
|
|
|
93.1
|
|
119,704
|
|
|
93.0
|
All other feedstocks and blendstocks
|
8,453
|
|
|
6.4
|
|
8,400
|
|
|
6.9
|
|
9,047
|
|
|
7.0
|
Total throughput
|
132,622
|
|
|
100.0
|
|
121,705
|
|
|
100.0
|
|
128,751
|
|
|
100.0
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Gasoline
|
69,303
|
|
|
51.4
|
|
57,815
|
|
|
46.5
|
|
64,002
|
|
|
48.6
|
Distillate
|
55,790
|
|
|
41.4
|
|
53,136
|
|
|
42.7
|
|
56,381
|
|
|
42.8
|
Other (excluding internally produced fuel)
|
9,756
|
|
|
7.2
|
|
13,503
|
|
|
10.8
|
|
11,314
|
|
|
8.6
|
Total refining production (excluding internally produced fuel)
|
134,849
|
|
|
100.0
|
|
124,454
|
|
|
100.0
|
|
131,697
|
|
|
100.0
|
|
(1)
|
The calculation of refining margin per crude oil throughput barrel for the years ended
December 31, 2016
,
2015
and
2014
is as follows:
|
|
Year Ended
December 31, |
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Total crude oil throughput barrels per day
|
124,169
|
|
|
113,305
|
|
|
119,704
|
|
Days in the period
|
366
|
|
|
365
|
|
|
365
|
|
Total crude oil throughput barrels
|
45,445,854
|
|
|
41,356,325
|
|
|
43,691,960
|
|
|
Year Ended
December 31, |
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining Margin
|
$
|
435.0
|
|
|
$
|
594.5
|
|
|
$
|
500.6
|
|
Divided by: crude oil throughput barrels
|
45.4
|
|
|
41.4
|
|
|
43.7
|
|
|||
Refining Margin per crude oil throughput barrel
|
$
|
9.57
|
|
|
$
|
14.37
|
|
|
$
|
11.46
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Wynnewood Refinery Financial Results
|
|
|
|
|
|
||||||
Net sales
|
$
|
1,478.0
|
|
|
$
|
1,936.9
|
|
|
$
|
3,069.8
|
|
Cost of materials and other
|
1,245.4
|
|
|
1,516.3
|
|
|
2,758.1
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
165.5
|
|
|
166.2
|
|
|
185.5
|
|
|||
Major scheduled turnaround expenses
|
—
|
|
|
—
|
|
|
1.3
|
|
|||
Depreciation and amortization
|
50.7
|
|
|
50.2
|
|
|
41.8
|
|
|||
Gross profit
|
$
|
16.4
|
|
|
$
|
204.2
|
|
|
$
|
83.1
|
|
Plus:
|
|
|
|
|
|
||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below)
|
165.5
|
|
|
166.2
|
|
|
186.8
|
|
|||
Depreciation and amortization
|
50.7
|
|
|
50.2
|
|
|
41.8
|
|
|||
Refining margin(1)
|
$
|
232.6
|
|
|
$
|
420.6
|
|
|
$
|
311.7
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(dollars per barrel)
|
||||||||||
Wynnewood Refinery Key Operating Statistics
|
|
|
|
|
|
||||||
Per crude oil throughput barrel:
|
|
|
|
|
|
||||||
Gross profit
|
$
|
0.61
|
|
|
$
|
7.01
|
|
|
$
|
2.96
|
|
Refining margin(1)
|
$
|
8.60
|
|
|
$
|
14.44
|
|
|
$
|
11.11
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)
|
$
|
6.12
|
|
|
$
|
5.71
|
|
|
$
|
6.66
|
|
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold
|
$
|
6.06
|
|
|
$
|
5.59
|
|
|
$
|
6.66
|
|
Barrels sold (barrels per day)
|
74,596
|
|
|
81,429
|
|
|
76,878
|
|
|
Year Ended December 31,
|
|||||||||||||
|
2016
|
|
2015
|
|
2014
|
|||||||||
|
|
|
%
|
|
|
|
%
|
|
|
|
%
|
|||
Wynnewood Refinery Throughput and Production Data (bpd)
|
|
|
|
|
|
|
|
|
|
|
|
|||
Throughput:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Sweet
|
72,577
|
|
|
94.9
|
|
79,370
|
|
|
95.6
|
|
76,041
|
|
|
96.2
|
Medium
|
1,296
|
|
|
1.7
|
|
402
|
|
|
0.5
|
|
800
|
|
|
1.0
|
Heavy sour
|
—
|
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
|
—
|
Total crude oil throughput
|
73,873
|
|
|
96.6
|
|
79,772
|
|
|
96.1
|
|
76,841
|
|
|
97.2
|
All other feedstocks and blendstocks
|
2,624
|
|
|
3.4
|
|
3,272
|
|
|
3.9
|
|
2,237
|
|
|
2.8
|
Total throughput
|
76,497
|
|
|
100.0
|
|
83,044
|
|
|
100.0
|
|
79,078
|
|
|
100.0
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|||
Gasoline
|
39,459
|
|
|
52.8
|
|
42,146
|
|
|
51.7
|
|
38,273
|
|
|
49.5
|
Distillate
|
29,302
|
|
|
39.2
|
|
32,817
|
|
|
40.2
|
|
31,258
|
|
|
40.4
|
Other (excluding internally produced fuel)
|
5,995
|
|
|
8.0
|
|
6,571
|
|
|
8.1
|
|
7,835
|
|
|
10.1
|
Total refining production (excluding internally produced fuel)
|
74,756
|
|
|
100.0
|
|
81,534
|
|
|
100.0
|
|
77,366
|
|
|
100.0
|
|
1.
|
The calculation of refining margin per crude oil throughput barrel for the years ended
December 31, 2016
,
2015
and
2014
is as follows:
|
|
Year Ended
December 31, |
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Total crude oil throughput barrels per day
|
73,873
|
|
|
79,772
|
|
|
76,841
|
|
Days in the period
|
366
|
|
|
365
|
|
|
365
|
|
Total crude oil throughput barrels
|
27,037,518
|
|
|
29,116,780
|
|
|
28,046,965
|
|
|
Year Ended
December 31, |
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except for $ per barrel data)
|
||||||||||
Refining Margin
|
$
|
232.6
|
|
|
$
|
420.6
|
|
|
$
|
311.7
|
|
Divided by: crude oil throughput barrels
|
27.0
|
|
|
29.1
|
|
|
28.0
|
|
|||
Refining Margin per crude oil throughput barrel
|
$
|
8.60
|
|
|
$
|
14.44
|
|
|
$
|
11.11
|
|
|
Year Ended December 31, 2016
|
|
Year Ended December 31, 2015
|
|
Total Variance
|
|
|
|
|
|||||||||||||||||||||||||||
|
Volume(1)
|
|
$ per barrel
|
|
Sales $(2)
|
|
Volume(1)
|
|
$ per barrel
|
|
Sales $(2)
|
|
Volume(1)
|
|
Sales $(2)
|
|
Price
Variance |
|
Volume
Variance |
|||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|||||||||||||||||||
Gasoline
|
42.6
|
|
|
$
|
56.16
|
|
|
$
|
2,390.8
|
|
|
40.1
|
|
|
$
|
67.52
|
|
|
$
|
2,708.4
|
|
|
2.5
|
|
|
$
|
(317.6
|
)
|
|
$
|
(483.2
|
)
|
|
$
|
165.6
|
|
Distillate
|
32.4
|
|
|
$
|
56.99
|
|
|
$
|
1,844.3
|
|
|
33.1
|
|
|
$
|
68.01
|
|
|
$
|
2,248.2
|
|
|
(0.7
|
)
|
|
$
|
(403.9
|
)
|
|
$
|
(356.8
|
)
|
|
$
|
(47.1
|
)
|
|
(1)
|
Barrels in millions
|
(2)
|
Sales dollars in millions
|
|
Year Ended December 31, 2015
|
|
Year Ended December 31, 2014
|
|
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
|
40.1
|
|
|
$
|
67.52
|
|
|
$
|
2,708.4
|
|
|
40.3
|
|
|
$
|
106.21
|
|
|
$
|
4,282.2
|
|
|
(0.2
|
)
|
|
$
|
(1,573.8
|
)
|
|
$
|
(1,552.1
|
)
|
|
$
|
(21.7
|
)
|
Distillate
|
33.1
|
|
|
$
|
68.01
|
|
|
$
|
2,248.2
|
|
|
34.9
|
|
|
$
|
118.09
|
|
|
$
|
4,122.3
|
|
|
(1.8
|
)
|
|
$
|
(1,874.1
|
)
|
|
$
|
(1,656.4
|
)
|
|
$
|
(217.7
|
)
|
|
(1)
|
Barrels in millions
|
(2)
|
Sales dollars in millions
|
|
Year Ended December 31,
|
||||||
|
2016 Actual
|
|
2017 Estimate
|
||||
|
(in millions)
|
||||||
|
(unaudited)
|
||||||
Coffeyville refinery:
|
|
|
|
||||
Maintenance
|
$
|
39.1
|
|
|
$
|
58.0
|
|
Growth
|
37.2
|
|
|
15.0
|
|
||
Coffeyville refinery total capital excluding major scheduled turnaround expenses
|
76.3
|
|
|
73.0
|
|
||
Wynnewood refinery
|
|
|
|
||||
Maintenance
|
20.6
|
|
|
63.0
|
|
||
Growth
|
0.5
|
|
|
5.0
|
|
||
Wynnewood refinery total capital excluding major scheduled turnaround expenses
|
21.1
|
|
|
68.0
|
|
||
Other Petroleum
:
|
|
|
|
||||
Maintenance
|
3.9
|
|
|
16.0
|
|
||
Growth
|
1.0
|
|
|
—
|
|
||
Other petroleum total capital excluding major scheduled turnaround expenses
|
4.9
|
|
|
16.0
|
|
||
Total capital spending excluding major scheduled turnaround expenses
|
$
|
102.3
|
|
|
$
|
157.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
||||||
Operating activities
|
$
|
267.8
|
|
|
$
|
473.7
|
|
|
$
|
715.8
|
|
Investing activities
|
(107.9
|
)
|
|
(194.7
|
)
|
|
(191.2
|
)
|
|||
Financing activities
|
(33.1
|
)
|
|
(461.9
|
)
|
|
(434.2
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
$
|
126.8
|
|
|
$
|
(182.9
|
)
|
|
$
|
90.4
|
|
|
Payments Due by Period
|
||||||||||||||||||||||||||
|
Total
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Thereafter
|
||||||||||||||
|
(in millions)
|
||||||||||||||||||||||||||
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Long-term debt(1)
|
$
|
500.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
500.0
|
|
Operating leases(2)
|
1.5
|
|
|
0.6
|
|
|
0.4
|
|
|
0.2
|
|
|
0.1
|
|
|
—
|
|
|
0.2
|
|
|||||||
Capital lease obligations(3)
|
46.9
|
|
|
1.8
|
|
|
2.1
|
|
|
2.3
|
|
|
2.6
|
|
|
2.9
|
|
|
35.2
|
|
|||||||
Unconditional purchase obligations(4)
|
1,209.8
|
|
|
128.0
|
|
|
120.1
|
|
|
119.7
|
|
|
107.2
|
|
|
97.2
|
|
|
637.6
|
|
|||||||
Environmental liabilities(5)
|
4.9
|
|
|
1.5
|
|
|
1.6
|
|
|
1.3
|
|
|
0.1
|
|
|
0.1
|
|
|
0.3
|
|
|||||||
Interest payments(6)
|
226.0
|
|
|
37.1
|
|
|
36.9
|
|
|
36.7
|
|
|
36.4
|
|
|
36.2
|
|
|
42.7
|
|
|||||||
Total
|
$
|
1,989.1
|
|
|
$
|
169.0
|
|
|
$
|
161.1
|
|
|
$
|
160.2
|
|
|
$
|
146.4
|
|
|
$
|
136.4
|
|
|
$
|
1,216.0
|
|
Other Commercial Commitments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Standby letters of credit(7)
|
$
|
28.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
(1)
|
Consists of the 2022 Notes as of
December 31, 2016
.
|
(2)
|
We lease various facilities and equipment, including real property, under operating leases for various periods.
|
(3)
|
The amount includes commitments under capital lease arrangements for two leases associated with pipelines and storage and terminal equipment at the Wynnewood refinery.
|
(4)
|
The amount includes (a) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments related to our biofuels blending obligation and (c) approximately
$733.7 million
payable ratably over
14 years
pursuant to petroleum transportation service agreements between our subsidiary, CRRM and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together, “TransCanada”). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of
December 31, 2016
, where applicable. Under the agreements, CRRM receives transportation of at least
25,000
barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of
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 and Wynnewood, Oklahoma. We also are required to make payments with respect to other environmental liabilities, which are not contractual obligations but which would be necessary for our continued operations. See "Business — Environmental Matters."
|
(6)
|
Interest payments are based on stated interest rates for our long-term debt outstanding and interest payments for the capital lease obligation as of
December 31, 2016
.
|
(7)
|
Standby letters of credit issued against the Amended and Restated ABL Credit Facility include
$0.2 million
of letters of credit issued in connection with environmental liabilities,
$26.5 million
in letters of credit to secure transportation services for crude oil and a
$1.6 million
letter of credit issued to guarantee a portion of our insurance policy.
|
•
|
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.
|
Audited Financial Statements:
|
Page
Number
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions, except unit data)
|
||||||
ASSETS
|
|||||||
Current assets:
|
|
|
|
||||
Cash and cash equivalents
|
$
|
314.1
|
|
|
$
|
187.3
|
|
Accounts receivable, net of allowance for doubtful accounts of $0.5 and $0.3, including $0.1 and $0.3 due from affiliates at December 31, 2016 and 2015, respectively
|
138.1
|
|
|
88.9
|
|
||
Inventories
|
291.1
|
|
|
252.5
|
|
||
Prepaid expenses and other current assets, including $1.2 and $2.0 due from affiliates at December 31, 2016 and 2015, respectively
|
60.3
|
|
|
100.3
|
|
||
Total current assets
|
803.6
|
|
|
629.0
|
|
||
Property, plant, and equipment, net of accumulated depreciation
|
1,515.0
|
|
|
1,549.5
|
|
||
Other long-term assets
|
13.3
|
|
|
10.5
|
|
||
Total assets
|
$
|
2,331.9
|
|
|
$
|
2,189.0
|
|
LIABILITIES AND PARTNERS' CAPITAL
|
|||||||
Current liabilities:
|
|
|
|
||||
Note payable and capital lease obligations
|
$
|
1.8
|
|
|
$
|
1.6
|
|
Accounts payable, including $4.6 and $5.4 due to affiliates at December 31, 2016 and 2015, respectively
|
225.9
|
|
|
254.3
|
|
||
Personnel accruals, including $3.0 and $4.0 due to affiliates at December 31, 2016 and 2015, respectively
|
19.3
|
|
|
21.7
|
|
||
Accrued taxes other than income taxes
|
25.2
|
|
|
22.1
|
|
||
Accrued expenses and other current liabilities, including $8.9 and $9.8 due to affiliates at December 31, 2016 and 2015, respectively
|
217.7
|
|
|
31.8
|
|
||
Total current liabilities
|
489.9
|
|
|
331.5
|
|
||
Long-term liabilities:
|
|
|
|
||||
Long-term debt and capital lease obligations, net of current portion, including $31.5 due to affiliates at December 31, 2015
|
539.7
|
|
|
572.2
|
|
||
Other long-term liabilities, including $0.6 and $0.8 due to affiliates at December 31, 2016 and 2015, respectively
|
5.6
|
|
|
3.9
|
|
||
Total long-term liabilities
|
545.3
|
|
|
576.1
|
|
||
Commitments and contingencies
|
|
|
|
||||
Partners’ capital:
|
|
|
|
||||
Common unitholders, 147,600,000 units issued and outstanding at December 31, 2016 and 2015
|
1,296.7
|
|
|
1,281.4
|
|
||
General partner interest
|
—
|
|
|
—
|
|
||
Total partners' capital
|
1,296.7
|
|
|
1,281.4
|
|
||
Total liabilities and partners' capital
|
$
|
2,331.9
|
|
|
$
|
2,189.0
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except per unit data)
|
||||||||||
Net sales
|
$
|
4,431.3
|
|
|
$
|
5,161.9
|
|
|
$
|
8,829.7
|
|
Operating costs and expenses:
|
|
|
|
|
|
||||||
Cost of materials and other
|
3,759.2
|
|
|
4,143.6
|
|
|
8,013.4
|
|
|||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
393.4
|
|
|
478.5
|
|
|
416.0
|
|
|||
Depreciation and amortization
|
126.3
|
|
|
128.0
|
|
|
120.9
|
|
|||
Cost of sales
|
4,278.9
|
|
|
4,750.1
|
|
|
8,550.3
|
|
|||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|||
Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below)
|
71.9
|
|
|
75.2
|
|
|
70.6
|
|
|||
Depreciation and amortization
|
2.7
|
|
|
2.2
|
|
|
1.6
|
|
|||
Total operating costs and expenses
|
4,353.5
|
|
|
4,800.2
|
|
|
8,622.5
|
|
|||
Operating income
|
77.8
|
|
|
361.7
|
|
|
207.2
|
|
|||
Other income (expense):
|
|
|
|
|
|
||||||
Interest expense and other financing costs
|
(43.4
|
)
|
|
(42.6
|
)
|
|
(34.2
|
)
|
|||
Interest income
|
0.1
|
|
|
0.4
|
|
|
0.3
|
|
|||
Gain (loss) on derivatives, net
|
(19.4
|
)
|
|
(28.6
|
)
|
|
185.6
|
|
|||
Other income (expense), net
|
0.2
|
|
|
0.3
|
|
|
(0.2
|
)
|
|||
Total other income (expense)
|
(62.5
|
)
|
|
(70.5
|
)
|
|
151.5
|
|
|||
Income before income tax expense
|
15.3
|
|
|
291.2
|
|
|
358.7
|
|
|||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|||
Net income
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
$
|
358.7
|
|
|
|
|
|
|
|
||||||
Net income per common unit - basic and diluted
|
$
|
0.10
|
|
|
$
|
1.97
|
|
|
$
|
2.43
|
|
|
|
|
|
|
|
||||||
Weighted average common units outstanding:
|
|
|
|
|
|
||||||
Basic and diluted
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
Common Units Issued
|
|
Limited Partner Interest
|
|
Common Unitholders
|
|
General Partner Interest
|
|
Total Partners'
Capital
|
|||||||||
|
(in millions, except unit data)
|
|||||||||||||||||
Balance at December 31, 2013
|
147,600,000
|
|
|
—
|
|
|
1,522.1
|
|
|
—
|
|
|
1,522.1
|
|
||||
June issuance of additional common units to the public, net of offering costs
|
7,089,100
|
|
|
—
|
|
|
178.5
|
|
|
—
|
|
|
178.5
|
|
||||
June redemption of common units from CVR Refining Holdings, LLC
|
(7,089,100
|
)
|
|
—
|
|
|
(179.0
|
)
|
|
—
|
|
|
(179.0
|
)
|
||||
Share-based compensation - Affiliates
|
—
|
|
|
—
|
|
|
2.3
|
|
|
—
|
|
|
2.3
|
|
||||
Cash distributions to common unitholders - Affiliates
|
—
|
|
|
—
|
|
|
(313.4
|
)
|
|
—
|
|
|
(313.4
|
)
|
||||
Cash distributions to common unitholders - Non-affiliates
|
—
|
|
|
—
|
|
|
(119.1
|
)
|
|
—
|
|
|
(119.1
|
)
|
||||
Net income
|
—
|
|
|
—
|
|
|
358.7
|
|
|
—
|
|
|
358.7
|
|
||||
Balance at December 31, 2014
|
147,600,000
|
|
|
—
|
|
|
1,450.1
|
|
|
—
|
|
|
1,450.1
|
|
||||
Share-based compensation - Affiliates
|
—
|
|
|
—
|
|
|
0.6
|
|
|
—
|
|
|
0.6
|
|
||||
Cash distributions to common unitholders - Affiliates
|
—
|
|
|
—
|
|
|
(322.3
|
)
|
|
—
|
|
|
(322.3
|
)
|
||||
Cash distributions to common unitholders - Non-affiliates
|
—
|
|
|
—
|
|
|
(138.2
|
)
|
|
—
|
|
|
(138.2
|
)
|
||||
Net income
|
—
|
|
|
—
|
|
|
291.2
|
|
|
—
|
|
|
291.2
|
|
||||
Balance at December 31, 2015
|
147,600,000
|
|
|
—
|
|
|
1,281.4
|
|
|
—
|
|
|
1,281.4
|
|
||||
Net income
|
—
|
|
|
—
|
|
|
15.3
|
|
|
—
|
|
|
15.3
|
|
||||
Balance at December 31, 2016
|
147,600,000
|
|
|
$
|
—
|
|
|
$
|
1,296.7
|
|
|
$
|
—
|
|
|
$
|
1,296.7
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Cash flows from operating activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
$
|
358.7
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation and amortization
|
129.0
|
|
|
130.2
|
|
|
122.5
|
|
|||
Allowance for doubtful accounts
|
0.2
|
|
|
—
|
|
|
(0.5
|
)
|
|||
Amortization of deferred financing costs
|
1.9
|
|
|
1.9
|
|
|
1.9
|
|
|||
Loss on disposition of assets
|
0.3
|
|
|
0.9
|
|
|
0.2
|
|
|||
Share-based compensation
|
4.9
|
|
|
9.3
|
|
|
8.0
|
|
|||
(Gain) loss on derivatives, net
|
19.4
|
|
|
28.6
|
|
|
(185.6
|
)
|
|||
Current period settlements on derivative contracts
|
36.4
|
|
|
(26.0
|
)
|
|
122.2
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Accounts receivable
|
(49.4
|
)
|
|
41.1
|
|
|
105.4
|
|
|||
Inventories
|
(38.5
|
)
|
|
41.3
|
|
|
200.3
|
|
|||
Prepaid expenses and other current assets
|
(4.8
|
)
|
|
12.9
|
|
|
3.9
|
|
|||
Other long-term assets
|
0.5
|
|
|
4.3
|
|
|
(0.6
|
)
|
|||
Accounts payable
|
(17.0
|
)
|
|
(16.3
|
)
|
|
(58.5
|
)
|
|||
Accrued expenses and other current liabilities
|
170.6
|
|
|
(45.9
|
)
|
|
36.6
|
|
|||
Other long-term liabilities
|
(1.0
|
)
|
|
0.2
|
|
|
1.3
|
|
|||
Net cash provided by operating activities
|
267.8
|
|
|
473.7
|
|
|
715.8
|
|
|||
Cash flows from investing activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(102.3
|
)
|
|
(194.7
|
)
|
|
(191.3
|
)
|
|||
Investment in affiliate
|
(5.6
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from sale of assets
|
—
|
|
|
—
|
|
|
0.1
|
|
|||
Net cash used in investing activities
|
(107.9
|
)
|
|
(194.7
|
)
|
|
(191.2
|
)
|
|||
Cash flows from financing activities:
|
|
|
|
|
|
||||||
Payment of capital lease obligations
|
(1.6
|
)
|
|
(1.4
|
)
|
|
(1.2
|
)
|
|||
Revolving debt repayment - affiliates
|
(31.5
|
)
|
|
—
|
|
|
—
|
|
|||
Proceeds from June 2014 issuance of common units, net of offering costs
|
—
|
|
|
—
|
|
|
178.5
|
|
|||
Redemption of common units from CVR Refining Holdings, LLC - June 2014
|
—
|
|
|
—
|
|
|
(179.0
|
)
|
|||
Distributions to common unitholders - affiliates
|
—
|
|
|
(322.3
|
)
|
|
(313.4
|
)
|
|||
Distributions to common unitholders - non-affiliates
|
—
|
|
|
(138.2
|
)
|
|
(119.1
|
)
|
|||
Net cash used in financing activities
|
(33.1
|
)
|
|
(461.9
|
)
|
|
(434.2
|
)
|
|||
Net increase (decrease) in cash and cash equivalents
|
126.8
|
|
|
(182.9
|
)
|
|
90.4
|
|
|||
Cash and cash equivalents, beginning of period
|
187.3
|
|
|
370.2
|
|
|
279.8
|
|
|||
Cash and cash equivalents, end of period
|
$
|
314.1
|
|
|
$
|
187.3
|
|
|
$
|
370.2
|
|
Supplemental disclosures:
|
|
|
|
|
|
||||||
Cash paid for interest net of capitalized interest of $5.0, $3.7 and $9.4 for the years ended December 31, 2016, 2015 and 2014, respectively
|
$
|
41.5
|
|
|
$
|
40.6
|
|
|
$
|
32.4
|
|
Non-cash investing and financing activities:
|
|
|
|
|
|
||||||
Construction in progress additions included in accounts payable
|
$
|
9.2
|
|
|
$
|
20.6
|
|
|
$
|
19.9
|
|
Change in accounts payable related to construction in progress additions
|
$
|
(11.4
|
)
|
|
$
|
0.7
|
|
|
$
|
(10.5
|
)
|
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
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Coffeyville refinery(1)
|
$
|
31.5
|
|
|
$
|
102.2
|
|
|
5.5
|
|
|
Wynnewood refinery(2)
|
—
|
|
|
—
|
|
|
1.3
|
|
|||
Total major scheduled turnaround expenses
|
$
|
31.5
|
|
|
$
|
102.2
|
|
|
$
|
6.8
|
|
|
(1)
|
The Coffeyville refinery completed the first phase of its most recent major scheduled turnaround in November 2015. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016. During the outage at the Coffeyville refinery as discussed in
Note 6 ("Insurance Claims")
, the Partnership accelerated certain planned turnaround activities scheduled for 2015 and incurred turnaround expenses for the year ended December 31, 2014.
|
(2)
|
During the fluid catalytic cracking unit ("FCCU") outage at the Wynnewood refinery, the Partnership accelerated certain planned turnaround activities previously scheduled for 2016 and incurred turnaround expenses for the year ended December 31, 2014. The next turnaround for the Wynnewood refinery will be performed as a two phase turnaround. The first phase is scheduled to begin in the second half of 2017, with the second phase to begin in the second half of 2018. Additionally, certain planned turnaround activities will be accelerated in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out.
|
|
Phantom Units
|
|
Weighted-
Average
Grant-Date
Fair Value
|
|
Aggregate
Intrinsic
Value
|
|||||
|
|
|
|
|
(in millions)
|
|||||
Non-vested at January 1, 2014
|
187,177
|
|
|
$
|
21.55
|
|
|
$
|
4.2
|
|
Granted
|
281,948
|
|
|
17.74
|
|
|
|
|||
Vested
|
(61,002
|
)
|
|
21.55
|
|
|
|
|||
Forfeited
|
(4,176
|
)
|
|
21.55
|
|
|
|
|||
Non-vested at December 31, 2014
|
403,947
|
|
|
$
|
18.89
|
|
|
$
|
6.8
|
|
Granted
|
302,319
|
|
|
20.40
|
|
|
|
|||
Vested
|
(136,531
|
)
|
|
19.26
|
|
|
|
|||
Forfeited
|
(58,144
|
)
|
|
18.87
|
|
|
|
|||
Non-vested at December 31, 2015
|
511,591
|
|
|
$
|
19.68
|
|
|
$
|
9.7
|
|
Non-vested at Granted
|
644,148
|
|
|
$
|
9.43
|
|
|
|
||
Vested
|
(218,351
|
)
|
|
19.78
|
|
|
|
|||
Forfeited
|
(32,533
|
)
|
|
19.13
|
|
|
|
|||
Non-vested at December 31, 2016
|
904,855
|
|
|
$
|
12.38
|
|
|
$
|
9.4
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Finished goods
|
$
|
135.8
|
|
|
$
|
104.7
|
|
Raw materials and precious metals
|
89.7
|
|
|
72.6
|
|
||
In-process inventories
|
23.9
|
|
|
35.7
|
|
||
Parts and supplies
|
41.7
|
|
|
39.5
|
|
||
Total Inventories
|
$
|
291.1
|
|
|
$
|
252.5
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
Land and improvements
|
$
|
29.1
|
|
|
$
|
28.7
|
|
Buildings
|
47.3
|
|
|
47.8
|
|
||
Machinery and equipment
|
2,306.0
|
|
|
2,142.2
|
|
||
Automotive equipment
|
24.2
|
|
|
23.9
|
|
||
Furniture and fixtures
|
9.0
|
|
|
8.2
|
|
||
Leasehold improvements
|
0.8
|
|
|
0.8
|
|
||
Construction in progress
|
41.0
|
|
|
116.8
|
|
||
|
2,457.4
|
|
|
2,368.4
|
|
||
Accumulated depreciation
|
942.4
|
|
|
818.9
|
|
||
Total property, plant and equipment, net
|
$
|
1,515.0
|
|
|
$
|
1,549.5
|
|
|
December 31,
|
||||||
|
2016
|
|
2015
|
||||
|
(in millions)
|
||||||
6.5% Second Lien Senior Notes, due 2022
|
$
|
500.0
|
|
|
$
|
500.0
|
|
Intercompany credit facility
|
—
|
|
|
31.5
|
|
||
Capital lease obligations
|
46.9
|
|
|
48.5
|
|
||
Total debt
|
546.9
|
|
|
580.0
|
|
||
Unamortized debt issuance costs
|
(5.4
|
)
|
|
(6.2
|
)
|
||
Current portion of capital lease obligations
|
(1.8
|
)
|
|
(1.6
|
)
|
||
Long-term debt, net of current portion
|
$
|
539.7
|
|
|
$
|
572.2
|
|
Year Ending December 31,
|
Capital Lease
|
||
|
(in millions)
|
||
2017
|
$
|
6.4
|
|
2018
|
6.5
|
|
|
2019
|
6.5
|
|
|
2020
|
6.5
|
|
|
2021
|
6.5
|
|
|
2022 and thereafter
|
50.8
|
|
|
Total future payments
|
83.2
|
|
|
Less: amount representing interest
|
36.3
|
|
|
Present value of future minimum payments
|
46.9
|
|
|
Less: current portion
|
1.8
|
|
|
Long-term portion
|
$
|
45.1
|
|
•
|
common units; and
|
•
|
a general partner interest, which is not entitled to any distributions, and which is held by the general partner.
|
|
December 31, 2014
|
|
March 31, 2015
|
|
June 30, 2015
|
|
September 30, 2015
|
|
Total Cash
Distributions
Paid in 2015
|
||||||||||
|
(in millions, except per unit data)
|
||||||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates
|
$
|
38.2
|
|
|
$
|
78.5
|
|
|
$
|
101.2
|
|
|
$
|
104.4
|
|
|
$
|
322.3
|
|
Amounts paid to non-affiliates
|
16.4
|
|
|
33.7
|
|
|
43.4
|
|
|
44.7
|
|
|
138.2
|
|
|||||
Total amount paid
|
$
|
54.6
|
|
|
$
|
112.2
|
|
|
$
|
144.6
|
|
|
$
|
149.1
|
|
|
$
|
460.5
|
|
Per common unit
|
$
|
0.37
|
|
|
$
|
0.76
|
|
|
$
|
0.98
|
|
|
$
|
1.01
|
|
|
$
|
3.12
|
|
Common units outstanding
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions, except per unit data)
|
||||||||||
Net income
|
$
|
15.3
|
|
|
$
|
291.2
|
|
|
$
|
358.7
|
|
Net income per common unit, basic and diluted
|
$
|
0.10
|
|
|
$
|
1.97
|
|
|
$
|
2.43
|
|
Weighted-average common units outstanding, basic and diluted
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
Year Ending December 31,
|
Operating
Leases
|
|
Unconditional
Purchase
Obligations
(1)
|
||||
|
(in millions)
|
||||||
2017
|
$
|
0.6
|
|
|
$
|
128.0
|
|
2018
|
0.4
|
|
|
120.1
|
|
||
2019
|
0.2
|
|
|
119.7
|
|
||
2020
|
0.1
|
|
|
107.2
|
|
||
2021
|
—
|
|
|
97.2
|
|
||
Thereafter
|
0.2
|
|
|
637.6
|
|
||
|
$
|
1.5
|
|
|
$
|
1,209.8
|
|
|
(1)
|
This amount includes approximately
$733.7 million
payable ratably over
14 years
pursuant to petroleum transportation service agreements between CRRM and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together "TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of
December 31, 2016
, where applicable. Under the agreements, CRRM receives transportation of at least
25,000
barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of
20 years
on TransCanada's Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.
|
Year Ending December 31,
|
Amount
|
||
|
(in millions)
|
||
2017
|
$
|
1.5
|
|
2018
|
1.6
|
|
|
2019
|
1.3
|
|
|
2020
|
0.1
|
|
|
2021
|
0.1
|
|
|
Thereafter
|
0.3
|
|
|
Undiscounted total
|
4.9
|
|
|
Less amounts representing interest at 1.47%
|
0.1
|
|
|
Accrued environmental liabilities at December 31, 2016
|
$
|
4.8
|
|
•
|
Level 1 — Quoted prices in active markets for identical assets or liabilities
|
•
|
Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)
|
•
|
Level 3 — Significant unobservable inputs (including CVR Refining's own assumptions in determining the fair value)
|
|
December 31, 2016
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Location and Description
|
|
|
|
|
|
|
|
||||||||
Other current assets (derivative agreements)
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total Assets
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Other current liabilities (derivative agreements)
|
—
|
|
|
(11.1
|
)
|
|
—
|
|
|
(11.1
|
)
|
||||
Other current liabilities (biofuel blending obligation & benzene obligation)
|
—
|
|
|
(187.0
|
)
|
|
—
|
|
|
(187.0
|
)
|
||||
Total Liabilities
|
$
|
—
|
|
|
$
|
(198.1
|
)
|
|
$
|
—
|
|
|
$
|
(198.1
|
)
|
|
December 31, 2015
|
||||||||||||||
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
|
(in millions)
|
||||||||||||||
Location and Description
|
|
|
|
|
|
|
|
||||||||
Other current assets (derivative agreements)
|
$
|
—
|
|
|
$
|
44.7
|
|
|
$
|
—
|
|
|
$
|
44.7
|
|
Total Assets
|
$
|
—
|
|
|
$
|
44.7
|
|
|
$
|
—
|
|
|
$
|
44.7
|
|
Other current liabilities (derivative agreements)
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
(0.1
|
)
|
||||
Other current liabilities (biofuel blending obligation)
|
—
|
|
|
(2.7
|
)
|
|
—
|
|
|
(2.7
|
)
|
||||
Total Liabilities
|
$
|
—
|
|
|
$
|
(2.8
|
)
|
|
$
|
—
|
|
|
$
|
(2.8
|
)
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Current period settlements on derivative contracts
|
$
|
36.4
|
|
|
$
|
(26.0
|
)
|
|
$
|
122.2
|
|
Gain (loss) on derivatives, net
|
(19.4
|
)
|
|
(28.6
|
)
|
|
185.6
|
|
|
As of December 31, 2016
|
||||||||||||||||||
Description
|
Gross
Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
Total
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
As of December 31, 2015
|
||||||||||||||||||
Description
|
Gross Current Assets
|
|
Gross
Amounts
Offset
|
|
Net
Current Assets
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
44.8
|
|
|
$
|
(0.1
|
)
|
|
$
|
44.7
|
|
|
$
|
—
|
|
|
$
|
44.7
|
|
Total
|
$
|
44.8
|
|
|
$
|
(0.1
|
)
|
|
$
|
44.7
|
|
|
$
|
—
|
|
|
$
|
44.7
|
|
|
As of December 31, 2015
|
||||||||||||||||||
Description
|
Gross Current Liabilities
|
|
Gross
Amounts
Offset
|
|
Net
Current Liabilities
Presented
|
|
Cash
Collateral
Not Offset
|
|
Net
Amount
|
||||||||||
|
(in millions)
|
||||||||||||||||||
Commodity Swaps
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
Total
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
•
|
services from CVR Energy's employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement will serve the Partnership on a shared, part-time basis only, unless the Partnership and CVR Energy agree otherwise;
|
•
|
administrative and professional services, including legal, accounting, SEC and securities exchange reporting, human resources, information technology, communications, insurance, tax, credit, finance, government and regulatory affairs;
|
•
|
recommendations on capital raising activities to the board of directors of the Partnership's general partner, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions;
|
•
|
managing or overseeing litigation and administrative or regulatory proceedings, establishing appropriate insurance policies for the Partnership and providing safety and environmental advice;
|
•
|
recommending the payment of distributions; and
|
•
|
managing or providing advice for other projects, including acquisitions, as may be agreed by CVR Energy and the Partnership's general partner from time to time.
|
|
Year Ended December 31,
|
||||||||||
|
2016
|
|
2015
|
|
2014
|
||||||
|
(in millions)
|
||||||||||
Direct operating expenses (exclusive of depreciation and amortization)
|
$
|
13.0
|
|
|
$
|
18.1
|
|
|
$
|
21.3
|
|
Selling, general and administrative expenses (exclusive of depreciation and amortization)
|
49.2
|
|
|
53.2
|
|
|
50.8
|
|
|||
Total
|
$
|
62.2
|
|
|
$
|
71.3
|
|
|
$
|
72.1
|
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Customer A
|
15
|
%
|
|
14
|
%
|
|
13
|
%
|
|
Year Ended December 31,
|
|||||||
|
2016
|
|
2015
|
|
2014
|
|||
Supplier A
|
61
|
%
|
|
61
|
%
|
|
67
|
%
|
|
Year Ended December 31, 2016
|
||||||||||||||
|
Quarter
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in millions, except per unit data)
|
||||||||||||||
Net sales
|
$
|
834.0
|
|
|
$
|
1,164.4
|
|
|
$
|
1,163.5
|
|
|
$
|
1,269.4
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of materials and other
|
722.3
|
|
|
941.9
|
|
|
987.5
|
|
|
1,107.5
|
|
||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
117.7
|
|
|
84.0
|
|
|
97.0
|
|
|
94.7
|
|
||||
Depreciation and amortization
|
30.9
|
|
|
30.9
|
|
|
31.9
|
|
|
32.6
|
|
||||
Cost of sales
|
870.9
|
|
|
1,056.8
|
|
|
1,116.4
|
|
|
1,234.8
|
|
||||
Flood insurance recovery
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Selling, general and administrative (exclusive of depreciation and amortization as reflected below)
|
18.5
|
|
|
16.8
|
|
|
18.1
|
|
|
18.5
|
|
||||
Depreciation and amortization
|
0.6
|
|
|
0.7
|
|
|
0.6
|
|
|
0.8
|
|
||||
Total operating costs and expenses
|
890.0
|
|
|
1,074.3
|
|
|
1,135.1
|
|
|
1,254.1
|
|
||||
Operating income (loss)
|
(56.0
|
)
|
|
90.1
|
|
|
28.4
|
|
|
15.3
|
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs
|
(10.8
|
)
|
|
(10.1
|
)
|
|
(10.8
|
)
|
|
(11.7
|
)
|
||||
Interest income
|
—
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
||||
Gain (loss) on derivatives, net
|
(1.2
|
)
|
|
(1.9
|
)
|
|
(1.7
|
)
|
|
(14.6
|
)
|
||||
Other income, net
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
||||
Total other expense
|
(12.0
|
)
|
|
(12.0
|
)
|
|
(12.5
|
)
|
|
(26.0
|
)
|
||||
Income (loss) before income tax expense
|
(68.0
|
)
|
|
78.1
|
|
|
15.9
|
|
|
(10.7
|
)
|
||||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
(68.0
|
)
|
|
$
|
78.1
|
|
|
$
|
15.9
|
|
|
$
|
(10.7
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss) per common unit - basic and diluted
|
$
|
(0.46
|
)
|
|
$
|
0.53
|
|
|
$
|
0.11
|
|
|
$
|
(0.07
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common units outstanding:
|
|
|
|
|
|
|
|
||||||||
Basic and diluted
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
Year Ended December 31, 2015
|
||||||||||||||
|
Quarter
|
||||||||||||||
|
First
|
|
Second
|
|
Third
|
|
Fourth
|
||||||||
|
(in millions, except per unit data)
|
||||||||||||||
Net sales
|
$
|
1,304.4
|
|
|
$
|
1,547.5
|
|
|
$
|
1,361.6
|
|
|
$
|
948.3
|
|
Operating costs and expenses:
|
|
|
|
|
|
|
|
||||||||
Cost of materials and other
|
1,056.1
|
|
|
1,180.9
|
|
|
1,063.7
|
|
|
842.8
|
|
||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below)
|
87.0
|
|
|
90.3
|
|
|
112.6
|
|
|
188.7
|
|
||||
Depreciation and amortization
|
33.5
|
|
|
33.6
|
|
|
29.4
|
|
|
31.5
|
|
||||
Cost of sales
|
1,176.6
|
|
|
1,304.8
|
|
|
1,205.7
|
|
|
1,063.0
|
|
||||
Flood insurance recovery
|
—
|
|
|
(27.3
|
)
|
|
—
|
|
|
—
|
|
||||
Selling, general and administrative (exclusive of depreciation and amortization as reflected below)
|
18.1
|
|
|
18.6
|
|
|
18.2
|
|
|
20.2
|
|
||||
Depreciation and amortization
|
0.5
|
|
|
0.6
|
|
|
0.5
|
|
|
0.6
|
|
||||
Total operating costs and expenses
|
1,195.2
|
|
|
1,296.7
|
|
|
1,224.4
|
|
|
1,083.8
|
|
||||
Operating income (loss)
|
109.2
|
|
|
250.8
|
|
|
137.2
|
|
|
(135.5
|
)
|
||||
Other income (expense):
|
|
|
|
|
|
|
|
||||||||
Interest expense and other financing costs
|
(11.3
|
)
|
|
(10.4
|
)
|
|
(10.4
|
)
|
|
(10.5
|
)
|
||||
Interest income
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
|
0.1
|
|
||||
Gain on derivatives, net
|
(51.4
|
)
|
|
(12.6
|
)
|
|
11.8
|
|
|
23.6
|
|
||||
Other expense, net
|
0.1
|
|
|
(0.1
|
)
|
|
0.2
|
|
|
0.1
|
|
||||
Total other income
|
(62.5
|
)
|
|
(23.0
|
)
|
|
1.7
|
|
|
13.3
|
|
||||
Income (loss) before income tax expense
|
46.7
|
|
|
227.8
|
|
|
138.9
|
|
|
(122.2
|
)
|
||||
Income tax expense
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||
Net income (loss)
|
$
|
46.7
|
|
|
$
|
227.8
|
|
|
$
|
138.9
|
|
|
$
|
(122.2
|
)
|
|
|
|
|
|
|
|
|
||||||||
Net income (loss) per common unit - basic and diluted
|
$
|
0.32
|
|
|
$
|
1.54
|
|
|
$
|
0.94
|
|
|
$
|
(0.83
|
)
|
|
|
|
|
|
|
|
|
||||||||
Weighted-average common units outstanding:
|
|
|
|
|
|
|
|
||||||||
Basic and diluted
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
|
147.6
|
|
Name
|
|
Age
|
|
Position With Our General Partner
|
|
John J. Lipinski
|
|
65
|
|
|
Chief Executive Officer and President, Director
|
Susan M. Ball
|
|
53
|
|
|
Chief Financial Officer and Treasurer
|
Robert W. Haugen
|
|
58
|
|
|
Executive Vice President, Refining Operations
|
Martin J. Power
|
|
61
|
|
|
Chief Commercial Officer
|
David L. Landreth
|
|
60
|
|
|
Senior Vice President, Economics and Planning
|
John R. Walter
|
|
40
|
|
|
Senior Vice President, General Counsel and Secretary
|
Carl C. Icahn
|
|
80
|
|
|
Director
|
SungHwan Cho
|
|
42
|
|
|
Director
|
Jonathan Frates
|
|
34
|
|
|
Director
|
Andrew Langham
|
|
43
|
|
|
Director
|
Louis J. Pastor
|
|
32
|
|
|
Director
|
Kenneth Shea
|
|
58
|
|
|
Director
|
Jon R. Whitney
|
|
72
|
|
|
Director
|
Glenn R. Zander
|
|
70
|
|
|
Director
|
•
|
CVR Energy makes available to our general partner the services of CVR Energy executive officers and employees who serve as our general partner's executive officers; and
|
•
|
We, our general partner and our subsidiaries, as the case may be, are obligated to reimburse CVR Energy for any allocated portion of the costs that CVR Energy incurs in providing compensation and benefits to such CVR Energy employees. We also pay our allocated portion of performance units and incentive units issued by CVR Energy to those personnel providing services to the Partnership via the services agreement.
|
•
|
To align the executive officers' interest with that of the unitholders and stakeholders, which provides long-term economic benefits to the unitholders;
|
•
|
To provide competitive financial incentives in the form of salary, bonuses and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and
|
•
|
To maintain a compensation program whereby the executive officers, through exceptional performance and equity-based incentives, have the opportunity to realize economic rewards commensurate with appropriate gains of other unitholders and stakeholders.
|
2016 Performance Measure
|
|
2016 Performance Goals
Threshold/Target/Maximum
|
|
2016 Actual Results
|
|
Portion of Target Bonus Allocable to Measure
|
Consolidated adjusted EBITDA — Petroleum business
|
|
Threshold: $300.0 million
Target: $482.0 million
Maximum: $665.0 million
|
|
$222.8 million
|
|
30% of bonus for Messrs. Haugen, Power and Landreth
|
Petroleum reliability measures (as adjusted)
|
|
Threshold: 177,000 bpd
Target: 189,000 bpd
Maximum: 201,000 bpd
|
|
202,893 bpd
|
|
35% of bonus for Mr. Haugen; 30% of bonus for Mr. Power; 40% of bonus for Mr. Landreth
|
Crude transportation production measure
|
|
Threshold: 62,000 bpd
Target: 67,000 bpd Maximum: 72,000 bpd |
|
71,261 bpd
|
|
10% of bonus for Messrs. Haugen and Landreth; 20% of bonus for Mr. Power
|
Turnaround expense - Coffeyville
|
|
Threshold: $40.0 million
Target: $37.0 million
Maximum: $34.0 million
|
|
$31.5 million
|
|
5% of bonus for Mr. Haugen
|
Coffeyville Refinery Environmental Health & Safety Measures
|
|
Threshold: 5% of refining payout levels
Target: 10% of refining payout levels Maximum: 15% of refining payout levels |
|
11.5%
|
|
10% of bonus for Messrs. Haugen, Power and Landreth
|
Wynnewood Refinery Environmental Health & Safety Measures
|
|
Threshold: 2.5% of refining payout levels
Target: 5% of refining payout levels Maximum: 7.5% of refining payout levels |
|
5.9%
|
|
5% of bonus for Messrs. Haugen and Power
|
Wynnewood Refinery Environmental Health & Safety Measures
|
|
Threshold: 5% of refining payout levels
Target: 10% of refining payout levels Maximum: 15% of refining payout levels |
|
11.8%
|
|
10% of bonus for Mr. Landreth
|
Crude Transportation Environmental Health & Safety Measures
|
|
Threshold: 2.5% of refining payout levels
Target: 5% of refining payout levels Maximum: 7.5% of refining payout levels |
|
7.0%
|
|
5% of bonus for Mr. Haugen and Mr. Power
|
•
|
To align the executive officers' interest with that of the stockholders and stakeholders, which provides long-term economic benefits to the stockholders;
|
•
|
To provide competitive financial incentives in the form of salary, bonuses and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and
|
•
|
To maintain a compensation program whereby the executive officers, through exceptional performance and equity-based incentives, have the opportunity to realize economic rewards commensurate with appropriate gains of other equity holders and stakeholders.
|
2016 Performance Measure
|
|
2016 Performance Goals
Threshold/Target/Maximum |
|
2016 Actual Results
|
|
Portion of Target Bonus Allocable to Measure
|
Consolidated adjusted EBITDA for CVR Energy
|
|
Threshold: $339.0 million
Target: $535.0 million
Maximum: $733.0 million
|
|
$279.5 million
|
|
30% of bonus for Mr. Lipinski and Ms. Ball
|
Synergies from East Dubuque Acquisition
|
|
Threshold: less than $7.0 million
Target: $7.0 million
Maximum: $10.0 million
|
|
$7.9 million
|
|
5% of bonus for Mr. Lipinski and Ms. Ball
|
Petroleum Reliability Measures (as adjusted)
|
|
Threshold: 177,000 bpd
Target: 189,000 bpd
Maximum: 201,000 bpd
|
|
202,893 bpd
|
|
30% of bonus for Mr. Lipinski and Ms. Ball
|
Crude Transportation Production Measures
|
|
Threshold: 62,000 gathered bpd
Target: 67,000 gathered bpd Maximum: 72,000 gathered bpd |
|
71,261 bpd
|
|
5% of bonus for Mr. Lipinski and Ms. Ball
|
Fertilizer Reliability Measures
|
|
Threshold: 1,006,000 tons
Target: 1,059,000 tons Maximum: 1,090,000 tons |
|
1,091,365 tons
|
|
10% of bonus for Mr. Lipinski and Ms. Ball
|
Coffeyville Refinery Environmental Health & Safety Measures
|
|
Threshold: 5% of refining payout levels
Target: 10% of refining payout levels Maximum: 15% of refining payout levels |
|
11.5%
|
|
10% of bonus for Mr. Lipinski and Ms. Ball
|
Wynnewood Refinery Environmental Health & Safety Measures
|
|
Threshold: 2.5% of refining payout levels
Target: 5% of refining payout levels Maximum: 7.5% of refining payout levels |
|
5.9%
|
|
5% of bonus for Mr. Lipinski and Ms. Ball
|
Fertilizer Environmental Health & Safety Measures
|
|
Threshold: 2.5% of nitrogen payout levels
Target: 5% of nitrogen payout levels Maximum: 7.5% of nitrogen payout levels |
|
5.7%
|
|
5% of bonus for Mr. Lipinski and Ms. Ball
|
|
|||||||||||||||||
Name and Principal Position
|
|
Year
|
|
Salary ($)
|
|
Stock Awards ($)(1)
|
|
Non-Equity
Incentive Plan
Compensation
($)(2)
|
|
All Other
Compensation
($)(3)
|
|
Total ($)
|
|||||
John J. Lipinski,
|
|
2016
|
|
1,000,000
|
|
|
—
|
|
|
5,898,750
|
|
|
36,949
|
|
|
6,935,699
|
|
Chief Executive Officer and
|
|
2015
|
|
1,000,000
|
|
|
—
|
|
|
7,187,500
|
|
|
32,214
|
|
|
8,219,714
|
|
President
|
|
2014
|
|
1,000,000
|
|
|
—
|
|
|
2,894,000
|
|
|
30,604
|
|
|
3,924,604
|
|
Susan M. Ball,
|
|
2016
|
|
425,000
|
|
|
945,009
|
|
|
489,345
|
|
|
19,082
|
|
|
1,878,436
|
|
Chief Financial Officer and
|
|
2015
|
|
415,000
|
|
|
945,003
|
|
|
673,338
|
|
|
18,703
|
|
|
2,052,044
|
|
Treasurer
|
|
2014
|
|
390,000
|
|
|
930,002
|
|
|
451,464
|
|
|
18,230
|
|
|
1,789,696
|
|
Robert W. Haugen,
|
|
2016
|
|
365,000
|
|
|
645,008
|
|
|
432,087
|
|
|
24,109
|
|
|
1,466,204
|
|
Executive Vice President,
|
|
2015
|
|
350,000
|
|
|
645,005
|
|
|
611,100
|
|
|
22,877
|
|
|
1,628,982
|
|
Refining Operations
|
|
2014
|
|
325,000
|
|
|
615,010
|
|
|
445,926
|
|
|
21,985
|
|
|
1,407,921
|
|
Martin J. Power,
|
|
2016
|
|
330,000
|
|
|
650,005
|
|
|
371,531
|
|
|
18,078
|
|
|
1,369,614
|
|
Chief Commercial Officer
|
|
2015
|
|
325,000
|
|
|
650,012
|
|
|
510,705
|
|
|
18,078
|
|
|
1,503,795
|
|
|
|
2014
|
|
27,603
|
|
|
2,038,671
|
|
|
—
|
|
|
—
|
|
|
2,066,274
|
|
David L. Landreth
|
|
2016
|
|
272,500
|
|
|
460,008
|
|
|
225,834
|
|
|
23,636
|
|
|
981,978
|
|
Senior Vice President,
|
|
2015
|
|
265,000
|
|
|
460,002
|
|
|
308,990
|
|
|
21,202
|
|
|
1,055,194
|
|
Economics and Planning
|
|
2014
|
|
245,000
|
|
|
450,010
|
|
|
224,106
|
|
|
20,440
|
|
|
939,556
|
|
(1)
|
For 2015 and 2016, the above table reflects the aggregate grant date fair value for incentive units granted to Ms. Ball and Messrs. Haugen and Power by CVR Energy in December 2015 and 2016, and for phantom units granted to Mr. Landreth by CVR Refining in December 2015 and 2016, in each case, computed in accordance with FASB ASC 718, with the assumptions relied upon in such valuation set forth in Note 3 ("Share-Based Compensation") to our audited consolidated financial statements. We pay for our allocated portion of the performance and incentive units pursuant to the services agreement. For 2014, the above table reflects the aggregate grant date fair value for incentive units granted to Ms. Ball and Messrs. Haugen and Power by CVR Energy in December 2014, notional units granted to Mr. Power effective as of December 2014 by CVR Refining, and phantom units granted to Mr. Landreth by CVR Refining in December 2014, in each case, computed in accordance with FASB ASC 718, with the assumptions relied upon in such valuation set forth in Note 3 ("Share-Based Compensation") to our audited consolidated financial statements. We pay for our allocated portion of the performance and incentive units pursuant to the services agreement.
|
(2)
|
Amounts in this column for 2016, 2015 and 2014 reflect amounts earned pursuant to the CVR Energy PIP in respect of performance during those years, paid in 2017, 2016, and 2015 respectively. For Mr. Lipinski, the amounts for 2015 and 2016 also reflect the aggregate grant date fair value for certain performance units granted in December 2015 and December 2016, of $3,500,000 for each year, that are valued based on a performance factor that is tied to certain operational performance metrics.
|
(3)
|
Amounts in this column for 2016 include the following: (a) a company contribution under the CVR Energy 401(k) plan of $15,900 for each named executive officer; (b) $14,191 for Mr. Lipinski, $2,004 for Ms. Ball, $6,082 for Mr. Haugen and $4,708 for Mr. Landreth in premiums paid by CVR Energy on behalf of the executive officer with respect to its executive life insurance program; and (c) $6,858 for Mr. Lipinski, $1,178 for Ms. Ball, $2,127 for Mr. Haugen, $2,178 for Mr. Power and $3,027 for Mr. Landreth in taxable value (inclusive of associated premiums) provided by CVR Energy on behalf of the executive officer with respect to its basic life insurance program.
|
Name
|
|
Salary ($)
|
|
Stock Awards ($)
|
|
Non-Equity Incentive Compensation ($)
|
|
Other ($)
|
||||
John J. Lipinski
|
|
500,000
|
|
|
—
|
|
|
2,949,375
|
|
|
18,475
|
|
Susan M. Ball
|
|
208,250
|
|
|
463,054
|
|
|
239,779
|
|
|
9,350
|
|
Robert W. Haugen
|
|
346,750
|
|
|
612,758
|
|
|
410,483
|
|
|
22,903
|
|
Martin J. Power
|
|
313,500
|
|
|
617,505
|
|
|
352,954
|
|
|
17,174
|
|
|
|
|
|
Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)
|
|
|
|
|
||||||||||
Name
|
|
Grant Date
|
|
Threshold ($)
|
|
Target ($)
|
|
Maximum ($)
|
|
All Other Stock Awards; Number of Shares of Stock or Units (#)
|
|
Grant Date Fair Value of Stock Awards ($)(2)
|
||||||
John J. Lipinski
|
|
—
|
|
|
1,250,000
|
|
|
2,500,000
|
|
|
3,750,000
|
|
|
—
|
|
|
—
|
|
|
|
12/31/2016
|
|
|
2,450,000
|
|
|
3,500,000
|
|
|
3,850,000
|
|
|
—
|
|
|
—
|
|
Susan M. Ball
|
|
—
|
|
|
255,000
|
|
|
510,000
|
|
|
765,000
|
|
|
—
|
|
|
—
|
|
|
|
12/31/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
100,426
|
|
|
945,009
|
|
Robert W. Haugen
|
|
—
|
|
|
219,000
|
|
|
438,000
|
|
|
657,000
|
|
|
—
|
|
|
—
|
|
|
|
12/31/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
68,545
|
|
|
645,008
|
|
Martin J. Power
|
|
—
|
|
|
189,750
|
|
|
379,500
|
|
|
569,250
|
|
|
—
|
|
|
—
|
|
|
|
12/31/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69,076
|
|
|
650,005
|
|
David L. Landreth
|
|
—
|
|
|
115,813
|
|
|
231,625
|
|
|
347,438
|
|
|
—
|
|
|
—
|
|
|
|
12/31/2016
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
48,885
|
|
|
460,008
|
|
(1)
|
Amounts in these columns reflect amounts that could have been earned by the named executive officers under the CVR Energy PIP in respect of 2016 performance at the threshold, target and maximum levels with respect to each performance measure. The performance measures and related goals for 2016 set by the compensation committee of our general partner and the compensation committee of CVR Energy, as applicable, are described in the Compensation Discussion and Analysis. For Mr. Lipinski, amounts also reflect amounts that could be earned under certain performance units issued in December 2016 at threshold, target, and maximum based on performance factors that are tied to operational performance metrics.
|
(2)
|
Reflects the grant date fair value of certain incentive unit awards to Ms. Ball and Messrs. Haugen and Power by CVR Energy during 2016, and phantom unit awards to Mr. Landreth under the CVR Refining LTIP during 2016, in each case, computed in accordance with FASB ASC Topic 718.
|
|
|
Option Awards
|
|
Stock Awards
|
|
|
|||||||
Name
|
|
Number of Securities Underlying Options (#) Unexercisable
|
|
Option Exercise Price ($)
|
|
Number of Shares or Units of Stock
That Have Not Vested (#)
|
|
Market Value of Shares or Units of
Stock That Have Not Vested ($)(1)
|
|||||
Susan M. Ball
|
|
—
|
|
|
—
|
|
|
17,474
|
|
(2
|
)
|
236,248
|
|
|
|
—
|
|
|
—
|
|
|
30,822
|
|
(3
|
)
|
320,549
|
|
|
|
—
|
|
|
—
|
|
|
100,426
|
|
(4
|
)
|
1,044,430
|
|
Robert W. Haugen
|
|
—
|
|
|
—
|
|
|
11,556
|
|
(2
|
)
|
156,237
|
|
|
|
—
|
|
|
—
|
|
|
21,037
|
|
(3
|
)
|
218,785
|
|
|
|
—
|
|
|
—
|
|
|
68,545
|
|
(4
|
)
|
712,868
|
|
Martin J. Power
|
|
227,927
|
|
|
23.39
|
|
|
|
(5
|
)
|
116,135
|
|
|
|
|
—
|
|
|
—
|
|
|
13,232
|
|
(2
|
)
|
178,897
|
|
|
|
—
|
|
|
—
|
|
|
21,200
|
|
(3
|
)
|
220,480
|
|
|
|
—
|
|
|
—
|
|
|
69,076
|
|
(4
|
)
|
718,390
|
|
David L. Landreth
|
|
—
|
|
|
—
|
|
|
8,455
|
|
(6
|
)
|
114,312
|
|
|
|
—
|
|
|
—
|
|
|
15,003
|
|
(7
|
)
|
156,031
|
|
|
|
—
|
|
|
—
|
|
|
48,885
|
|
(8
|
)
|
508,404
|
|
(1)
|
This column represents the number of unvested units outstanding on such date, multiplied by the closing price of the units on December 31, 2016, which: (i) for purposes of the incentive units described in footnote (2) and the phantom units described in footnote (6) below, was $13.52 (the closing price of $10.40 plus $3.12 in accrued distributions); (ii) for purposes of the incentive units described in footnote (3) and the phantom units described in footnote (7) below was $10.40; and (iii) for purposes of the incentive units described in footnote (4) and the phantom units described in footnote (8) below was $10.40. For purposes of the incentive units described in footnote (5) below, this column represents the fair value of the outstanding units estimated using the Black-Scholes option-pricing model.
|
(2)
|
The incentive units reflected were issued on December 26, 2014 and are scheduled to vest on December 26, 2017, provided the executive continues to serve as an employee of CVR Energy or one of its subsidiaries on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below. The Partnership will share in its prorated share of the costs associated with these awards based on the percentage of time that the executive dedicates to our business during the vesting term.
|
(3)
|
The incentive units reflected were issued on December 18, 2015 and are scheduled to vest in one-half annual increments on December 18, 2017 and 2018, provided the executive continues to serve as an employee of CVR Energy or one of its subsidiaries on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below. The Partnership will share in its prorated share of the costs associated with these awards based on the percentage of time that the executive dedicates to our business during the vesting term.
|
(4)
|
The incentive units reflected were issued on December 31, 2016 and are scheduled to vest in one-third annual increments on December 16 of 2017 through 2019, provided the executive continues to serve as an employee of CVR Energy or one of its subsidiaries on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below. The Partnership will share in its prorated share of the costs associated with these awards based on the percentage of time that the executive dedicates to our business during the vesting term.
|
(5)
|
The notional units reflected were issued effective as of December 1, 2014 in the form of stock appreciation rights and are scheduled to vest on December 1, 2017, provided the executive continues to serve as an employee of CVR Refining or one of its affiliates on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below.
|
(6)
|
The phantom units reflected were issued on December 26, 2014 and are scheduled to vest on December 26, 2017, provided the executive continues to serve as an employee of CVR Refining or one of its subsidiaries or parents on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below.
|
(7)
|
The phantom units reflected were issued on December 18, 2015 and are scheduled to vest in one-half annual increments on December 18, 2017 and 2018, provided the executive continues to serve as an employee of CVR Refining or one of its subsidiaries or parents on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below.
|
(8)
|
The phantom units reflected were issued on December 31, 2016 and are scheduled to vest in one-third annual increments on December 16 of 2017 through 2019, provided the executive continues to serve as an employee of CVR Refining or one of its subsidiaries or parents on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below.
|
|
|
Equity Awards
|
|||||
Named Executive Officer
|
|
Number of Shares or Units
Acquired on Vesting (#)
|
|
Value Realized
on Vesting ($)
|
|
||
Susan M. Ball
|
|
13,216
|
|
|
202,337
|
|
(1)
|
|
|
17,475
|
|
|
222,981
|
|
(2)
|
|
|
15,411
|
|
|
146,405
|
|
(3)
|
Robert W. Haugen
|
|
8,076
|
|
|
123,644
|
|
(1)
|
|
|
11,556
|
|
|
147,455
|
|
(2)
|
|
|
10,519
|
|
|
99,931
|
|
(3)
|
Martin J. Power
|
|
13,232
|
|
|
168,840
|
|
(2)
|
|
|
10,601
|
|
|
100,710
|
|
(3)
|
David L. Landreth
|
|
6,241
|
|
|
95,550
|
|
(4)
|
|
|
8,456
|
|
|
107,899
|
|
(5)
|
|
|
7,502
|
|
|
71,269
|
|
(6)
|
(1)
|
For incentive units that became vested during fiscal year 2016, the amount reflected includes a per unit value equal to (i) the average closing price of CVR Refining's common units in accordance with the agreement, plus (ii) accrued distributions of $6.05 per unit.
|
(2)
|
For incentive units that became vested during fiscal year 2016, the amount reflected includes a per unit value equal to (i) the average closing price of CVR Refining's common units in accordance with the agreement, plus (ii) accrued distributions of $3.12 per unit.
|
(3)
|
For incentive units that became vested during fiscal year 2016, the amount reflected includes a per unit value equal to the average closing price of CVR Refining's common units in accordance with the agreement.
|
(4)
|
For phantom units that became vested during fiscal year 2016, the amount reflected includes a per unit value equal to (i) the average closing price of CVR Refining's common units in accordance with the agreement, plus (ii) accrued distributions of $6.05 per unit.
|
(5)
|
For phantom units that became vested during fiscal year 2016, the amount reflected includes a per unit value equal to (i) the average closing price of CVR Refining's common units in accordance with the agreement, plus (ii) accrued distributions of $3.12 per unit.
|
(6)
|
For phantom units that became vested during fiscal year 2016, the amount reflected includes a per unit value equal to the average closing price of CVR Refining's common units in accordance with the agreement.
|
(1)
|
Severance payments and benefits in the event of termination without cause or resignation for good reason not in connection with a change in control.
|
(2)
|
Severance payments and benefits in the event of termination without cause or resignation for good reason in connection with a change in control.
|
(3)
|
Beginning in 2014, CVR Energy switched to a self-insured medical plan, and premiums for the named executive officers are paid by the employee only.
|
|
Death ($)
|
|
Disability ($)
|
|
Retirement ($)
|
|
Termination without
Cause or
with Good Reason ($)
|
|||||||
|
|
|
|
|
|
|
(1)
|
|
(2)
|
|||||
Susan M. Ball
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,167,307
|
|
Robert W. Haugen
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,116,463
|
|
(1)
|
Termination without cause or resignation for good reason not in connection with a change in control.
|
(2)
|
Termination without cause or resignation for good reason in connection with a change in control.
|
Name
|
|
Fees Earned or Paid in
Cash / Total Compensation (1)($)
|
Glenn R. Zander
|
|
85,000
|
Kenneth Shea
|
|
77,000
|
Jon R. Whitney
|
|
82,000
|
(1)
|
Amounts reflected in this column include annual retainer fees and additional fees for service as committee members, including the chair positions during
2016
.
|
•
|
our general partner;
|
•
|
each of our general partner's directors;
|
•
|
each of our named executive officers;
|
•
|
each unitholder known by us to beneficially hold five percent or more of our outstanding units; and
|
•
|
all of our general partner's executive officers and directors as a group.
|
|
Common Units
Beneficially Owned
|
||||
Name of Beneficial Owner
|
Number
|
|
Percent(1)
|
||
CVR Refining GP, LLC(2)
|
—
|
|
|
—
|
|
CVR Energy, Inc.(3)
|
97,315,764
|
|
|
65.9
|
%
|
John J. Lipinski(4)
|
200,000
|
|
|
*
|
|
Susan M. Ball
|
8,000
|
|
|
*
|
|
Robert W. Haugen
|
—
|
|
|
—
|
|
Martin J. Power
|
—
|
|
|
—
|
|
David L. Landreth
|
11,000
|
|
|
*
|
|
Carl C. Icahn(5)
|
103,065,764
|
|
|
69.8
|
%
|
SungHwan Cho
|
—
|
|
|
—
|
|
Jonathan Frates
|
—
|
|
|
—
|
|
Andrew Langham
|
2,000
|
|
|
*
|
|
Louis J. Pastor
|
—
|
|
|
—
|
|
Kenneth Shea
|
—
|
|
|
—
|
|
Jon R. Whitney
|
6,000
|
|
|
*
|
|
Glenn R. Zander
|
5,000
|
|
|
*
|
|
All directors and executive officers of our general partner as a group (14 persons)(6)
|
103,298,764
|
|
|
69.9
|
%
|
*
|
Less than 1%
|
(1)
|
Based on 147,600,000 common units outstanding as of
February 14, 2017
.
|
(2)
|
CVR Refining GP, LLC, a wholly owned subsidiary of CVR Refining Holdings, is our general partner and manages and operates our business and has a non-economic general partner interest.
|
(3)
|
97,303,764 of these common units are owned of record by CVR Refining Holdings, LLC and 12,000 of these common units are owned of record by CVR Refining Holdings Sub, LLC, each of which is an indirect wholly-owned subsidiary of CVR Energy. CVR Energy, Inc. is a publicly traded company. The directors of CVR Energy are Carl C. Icahn, Bob G. Alexander, SungHwan Cho, Jonathan Frates, Andrew Langham, John J. Lipinski, Stephen Mongillo and James M. Strock.
|
(4)
|
Mr. Lipinski owns 80,000 common units directly. In addition, Mr. Lipinski may be deemed to be the beneficial owner of an additional 120,000 common units, which are owned by the 2011 Lipinski Exempt Family Trust, which are held in trust for the benefit of Mr. Lipinski's family. Mr. Lipinski's spouse is the trustee of the trust.
|
(5)
|
The following disclosures are based on a Schedule 13D/A filed with the Commission on July 24, 2014 and amended August 2, 2016 by CVR Refining Holdings, CRLLC, CRRM, Coffeyville Refining & Marketing Holdings, Inc. ("CRRM Holdings"), CVR Energy, IEP Energy LLC ("IEP Energy"), IEP Energy Holding LLC ("Energy Holding"), American Entertainment Properties Corp. ("AEP"), Icahn Building LLC ("Building"), Icahn Enterprises Holdings L.P. ("Icahn Enterprises Holdings"), Icahn Enterprises G.P. Inc. ("Icahn Enterprises GP"), Beckton Corp. ("Beckton"), and Carl C. Icahn (collectively, the "Icahn Reporting Persons").
|
(6)
|
The number of common units owned by all of the directors and executive officers of our general partner, as a group, reflects the sum of (i) the 200,000 common units owned directly or indirectly by Mr. Lipinski, the 8,000 common units owned by Ms. Ball, the 11,000 common units owned by Mr. Landreth and the 1,000 common units owned by Mr. Walter, (ii) the 103,065,764 common units owned directly or indirectly by Mr. Icahn, (iii) the 2,000 common units owned by Mr. Langham, (iv) the 6,000 common units owned by Mr. Whitney, and (v) the 5,000 common units owned by Mr. Zander.
|
|
|
Shares
Beneficially Owned
|
||||
Name of Beneficial Owner
|
|
Number
|
|
Percent(1)
|
||
John J. Lipinski
|
|
—
|
|
|
—
|
|
Susan M. Ball
|
|
—
|
|
|
—
|
|
Robert W. Haugen
|
|
1
|
|
|
*
|
|
Martin J. Power
|
|
—
|
|
|
—
|
|
David L. Landreth
|
|
—
|
|
|
—
|
|
Carl C. Icahn(2)
|
|
71,198,718
|
|
|
82
|
%
|
SungHwan Cho
|
|
—
|
|
|
—
|
|
Jonathan Frates
|
|
|
|
|
||
Andrew Langham
|
|
—
|
|
|
—
|
|
Louis J. Pastor
|
|
—
|
|
|
—
|
|
Kenneth Shea
|
|
—
|
|
|
—
|
|
Jon R. Whitney
|
|
—
|
|
|
—
|
|
Glenn R. Zander
|
|
—
|
|
|
—
|
|
All directors and executive officers of our general partner as a group (14 persons)
|
|
71,198,719
|
|
|
82
|
%
|
*
|
Less than 1%
|
(1)
|
Percentage calculated based upon 86,831,050 shares of common stock outstanding as of
February 14, 2017
.
|
(2)
|
Shares of common stock reflected as beneficially owned by Mr. Icahn are owned of record by IEP Energy LLC, a subsidiary of Icahn Enterprises L.P. Mr. Icahn may be deemed to indirectly beneficially own such shares for purposes of Section 13(d) of the Exchange Act. Mr. Icahn disclaims beneficial ownership of such shares for all other purposes.
|
Plan Category
|
|
Number of
Securities to be
Issued Upon
Exercise of
Outstanding Options
Warrants and Rights(a)
|
|
Weighted-Average
Exercise Price of
Outstanding Options
Warrants and Rights(b)
|
|
Number of
Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in (a)) (c)
|
|
|||
Equity compensation plans approved by security holders:
|
|
|
|
|
|
|
|
|||
CVR Refining, LP Long-Term Incentive Plan
|
|
—
|
|
|
—
|
|
|
11,070,000
|
|
(1)
|
Equity compensation plans not approved by security holders:
|
|
|
|
|
|
|
|
|||
None
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
—
|
|
|
—
|
|
|
11,070,000
|
|
|
(1)
|
Represents units that remain available for future issuance pursuant to the CVR Refining LTIP in connection with awards of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights. As of
December 31, 2016
, no awards had been granted under the CVR Refining LTIP to any of our named executive officers that would reduce the units available for issuance.
|
•
|
services from CVR Energy's employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement will serve us on a shared, part-time basis only, unless we and CVR Energy agree otherwise;
|
•
|
administrative and professional services, including legal, accounting, SEC and securities exchange reporting, human resources, information technology, insurance, tax, credit, finance, government and regulatory affairs;
|
•
|
recommendations on capital raising activities to the board of directors of our general partner, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions;
|
•
|
managing or overseeing litigation and administrative or regulatory proceedings, establishing appropriate insurance policies for us and providing us with safety and environmental advice;
|
•
|
recommending the payment of distributions; and
|
•
|
managing or providing advice for other projects, including acquisitions, as may be agreed by CVR Energy and our general partner from time to time.
|
|
Fiscal
|
|
Fiscal
|
||||
|
Year 2016
|
|
Year 2015
|
||||
Audit fees(1)
|
$
|
1,289,100
|
|
|
$
|
1,169,200
|
|
Audit-related fees(2)
|
15,000
|
|
|
15,000
|
|
||
Tax fees
|
—
|
|
|
—
|
|
||
All other fees
|
—
|
|
|
—
|
|
||
Total
|
$
|
1,304,100
|
|
|
$
|
1,184,200
|
|
(1)
|
Represents the aggregate fees for professional services rendered for the audit of the Partnership's financial statements for fiscal years ended
December 31, 2016
and
2015
, the audit of the effectiveness of the Partnership's internal control over financial reporting as of
December 31, 2016
and
2015
and consultations on financial accounting and reporting matters arising during the course of the audit for fiscal years
2016
and
2015
. Also includes the review of the consolidated financial statements included in the Partnership's quarterly reports on Form 10-Q.
|
(2)
|
Represents fees for agreed-upon procedures performed for statutory reporting.
|
|
CVR Refining, LP
|
|
|
By:
|
CVR Refining GP, LLC, its general partner
|
|
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 17, 2017
|
John J. Lipinski
|
|
|
|
|
|
/s/ SUSAN M. BALL
|
Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)
|
February 17, 2017
|
Susan M. Ball
|
|
|
|
|
|
|
Director
|
February 17, 2017
|
Carl C. Icahn
|
|
|
|
|
|
/s/ SUNGHWAN CHO
|
Director
|
February 17, 2017
|
SungHwan Cho
|
|
|
|
|
|
/s/ JONATHAN FRATES
|
Director
|
February 17, 2017
|
Jonathan Frates
|
|
|
|
|
|
|
Director
|
February 17, 2017
|
Andrew Langham
|
|
|
|
|
|
/s/ LOUIS J. PASTOR
|
Director
|
February 17, 2017
|
Louis J. Pastor
|
|
|
|
|
|
/s/ KENNETH SHEA
|
Director
|
February 17, 2017
|
Kenneth Shea
|
|
|
|
|
|
/s/ JON R. WHITNEY
|
Director
|
February 17, 2017
|
Jon R. Whitney
|
|
|
|
|
|
/s/ GLENN R. ZANDER
|
Director
|
February 17, 2017
|
Glenn R. Zander
|
|
|
10.8**
|
Amended and Restated ABL Pledge and Security Agreement, dated as of December 20, 2012, among CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, and Wells Fargo Bank, National Association, as collateral agent (incorporated by reference to Exhibit 1.2 to CVR Energy, Inc.'s Form 8-K filed on December 27, 2012 (Commission File No. 001-33492)).
|
|
|
10.9**
|
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 CVR Energy Inc.'s Registration Statement on Form S-1/A, File No. 333-137588, filed on February 12, 2007 (Commission File No. 001-33492)).
|
|
|
10.10**
|
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 CVR Energy, Inc.'s Form 8-K filed on February 28, 2011 (Commission File No. 001-33492)).
|
|
|
10.11**
|
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 CVR Energy Inc.'s Form 10-K for the year ended December 31, 2011, filed on February 29, 2012 (Commission File No. 001-33492)).
|
|
|
10.12**
|
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 CVR Energy Inc.'s Form 8-K filed on April 12, 2010 (Commission File No. 001-33492)).
|
|
|
10.13**
|
Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and between CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.4 to the Partnership's Form 8-K filed on January 29, 2013).
|
|
|
10.13.1**
|
First Amendment to Credit Agreement, dated as of October 29, 2014, by and between CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on October 30, 2014).
|
|
|
10.14**
|
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 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007 (Commission File No. 001-33492)).
|
|
|
10.15**
|
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 Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011 (Commission File No. 001-33492)).
|
|
|
10.16**
|
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 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007).
|
|
|
10.16.1**
|
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 of the Form 10-K filed by CVR Energy, Inc. on March 28, 2008 (Commission File No. 001-33492)).
|
|
|
31.2*
|
Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer and Treasurer.
|
|
|
32.1†
|
Section 1350 Certification of Chief Executive Officer and President and Chief Financial Officer and Treasurer.
|
|
|
101*
|
The following financial information for CVR Refining LP's Annual Report on Form 10-K for the year ended December 31, 2016, formatted in XBRL ("Extensible Business Reporting Language") includes: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Changes in Partners' Capital, (iv) Consolidated Statements of Cash Flows, (v) the Notes to Consolidated Financial Statements, tagged in detail.
|
*
|
|
Filed herewith.
|
|
|
|
**
|
|
Previously filed.
|
|
|
|
†
|
|
Furnished herewith.
|
|
|
|
+
|
|
Denotes management contract or compensatory plan or arrangement.
|
1 Year Cvr Refining, LP Common Units Representing Limited Partner Interests Chart |
1 Month Cvr Refining, LP Common Units Representing Limited Partner Interests Chart |
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