UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________________________
Form 10-K
(Mark One) | |
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2017 | |
OR | OR |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to | |
Commission file number: 001-35781
_____________________________________________________________
CVR Refining, LP
(Exact name of registrant as specified in its charter)
Delaware (State or Other Jurisdiction of Incorporation or Organization) | 37-1702463 (I.R.S. Employer Identification No.) |
2277 Plaza Drive, Suite 500 Sugar Land, Texas (Address of Principal Executive Offices) | 77479 (Zip Code) |
Registrant's Telephone Number, including Area Code:
(281) 207-3200
_____________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered |
Common units representing limited partner interests | The New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 or Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o |
(Do not check if a smaller reporting company) | ||
Smaller reporting company o | Emerging growth company o | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 2017 (the last business day of the registrant’s second fiscal quarter) was $420,861,742. Common units of the registrant held by each executive officer and director and by each entity or person that, to the registrant’s knowledge, owned 10% or more of the registrant’s outstanding common units as of June 30, 2017 have been excluded from this number in that these persons may be deemed affiliates of the registrant. This determination of possible affiliate status is not necessarily a conclusive determination for other purposes.
Indicate the number of units outstanding of each of the registrant's classes of common units, as of the latest practicable date.
Class | Outstanding at February 20, 2018 |
Common units representing limited partner interests | 147,600,000 units |
TABLE OF CONTENTS
Page | ||
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GLOSSARY OF SELECTED TERMS
The following are definitions of certain terms used in this Annual Report on Form 10-K for the year ended December 31, 2017 (this "Report").
2022 Notes — $500.0 million aggregate principal amount of 6.5% Senior Notes due 2022, which were issued by Refining LLC and Coffeyville Finance on October 23, 2012 and fully and unconditionally guaranteed by the Partnership and each of Refining LLC's domestic subsidiaries other than Coffeyville Finance.
2-1-1 crack spread — The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.
Amended and Restated ABL Credit Facility — Our senior secured asset based revolving credit facility with a group of lenders and Wells Fargo, as administrative agent and collateral agent.
barrel — Common unit of measure in the oil industry which equates to 42 gallons.
blendstocks — Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.
bpd — Abbreviation for barrels per day.
bpcd — Abbreviation for barrels per calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by the total number of days in the year (365 or 366 days), thus reflecting all operational and logistical limitations.
bulk sales — Volume sales through third-party pipelines, in contrast to tanker truck quantity rack sales.
capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a barrel per calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as crude oil and other feedstock costs, product values and downstream unit constraints.
catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
Coffeyville Finance — Coffeyville Finance Inc., a wholly owned subsidiary of Refining LLC and an indirect wholly-owned subsidiary of the Partnership.
crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.
CRLLC — Coffeyville Resources, LLC, a wholly-owned subsidiary of CVR Energy.
CRPLLC — Coffeyville Resources Pipeline, LLC.
CRRM — Coffeyville Resource Refining & Marketing, LLC, a wholly-owned subsidiary of Refining LLC and indirect wholly-owned subsidiary of the Partnership.
CVR Energy — CVR Energy, Inc., a publicly traded company listed on the NYSE under the ticker symbol "CVI," which indirectly owns our general partner and a majority of our common units.
CVR Partners — CVR Partners, LP, a publicly traded limited partnership listed on the NYSE under the ticker symbol "UAN," which produces and markets nitrogen fertilizers in the form of urea ammonium nitrate ("UAN") and ammonia.
CVR Refining — CVR Refining, LP and its subsidiaries.
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CVR Refining GP or general partner — CVR Refining GP, LLC, an indirect wholly-owned subsidiary of CVR Energy.
distillates — Primarily diesel fuel, kerosene and jet fuel.
ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
FCCU — Fluid Catalytic Cracking Unit.
feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel during the refining process.
Group 3 — A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include our Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and CHS Inc.'s refinery in McPherson, KS.
heavy crude oil — A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.
independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil throughputs in its refinery operations from third parties.
intercompany credit facility — A $150.0 million senior unsecured revolving credit facility between CRLLC and Refining LLC.
LIBOR — London Interbank Offered Rate.
light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.
Midway — Midway Pipeline LLC
MSCF — One thousand standard cubic feet, a customary gas measurement unit.
natural gas liquids — Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels and products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.
PADD II — Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.
Partnership — CVR Refining and its subsidiaries.
petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.
rack sales — Sales which are made at terminals into third-party tanker trucks or railcars.
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
Refining LLC — CVR Refining, LLC, a wholly-owned subsidiary of the Partnership.
RFS — Renewable Fuel Standard of the EPA.
RINs — Renewable fuel credits, known as renewable identification numbers.
sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
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spot market — A market in which commodities are bought and sold for cash and delivered immediately.
sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
throughput — The volume processed through a unit or a refinery or transported on a pipeline.
turnaround — A periodically required standard procedure to inspect, refurbish, repair and maintain our refineries. This process involves the shutdown and inspection of major processing units and occurs every four to five years.
Velocity — Velocity Central Oklahoma Pipeline LLC.
Vitol — Vitol Inc.
Vitol Agreement — The Amended and Restated Crude Oil Supply Agreement between Vitol and CRRM.
VPP — Velocity Pipeline Partners, LLC.
WCS — Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity") of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.
WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.
WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.
yield — The percentage of refined products that is produced from crude oil and other feedstocks.
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PART I
Item 1. Business
Overview
CVR Refining, LP and, unless the context otherwise requires, its subsidiaries ("CVR Refining," the "Partnership," "we," "us," or "our") is an independent downstream energy limited partnership with refining and related logistics assets that operates in the mid-continent region. Our common units are listed on the New York Stock Exchange ("NYSE") under the symbol "CVRR."
We are a petroleum refiner and own two of only seven refineries in Group 3 of the PADD II region of the United States. We own and operate a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas with a rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing 20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). The combined crude capacity represents approximately 23% of the region's refining capacity. In addition, we also control and operate supporting logistics assets including (i) approximately 570 miles of active owned, leased and joint venture pipelines, (ii) approximately 130 crude oil transports, (iii) a network of strategically located crude oil gathering tank farms, (iv) approximately 6.4 million barrels of owned and leased crude oil storage, and (v) over 4.6 million barrels of combined refined products and feedstocks storage capacity. The strategic location of our refineries, combined with our supporting logistics assets, provide us with a significant crude oil cost advantage relative to our competitors. Furthermore, our Coffeyville refinery located in southeast Kansas and the Wynnewood refinery located 65 miles south of Oklahoma City, Oklahoma, are approximately 100 miles and 130 miles, respectively, from the crude oil hub at Cushing, Oklahoma ("Cushing"), and have access to inland domestic and Canadian crude oils that are priced based on the price of WTI. During the year ended December 31, 2017, the crude oil consumed at the refineries was price advantaged to WTI.
During the fourth quarter of 2017, we entered into a joint venture, Midway Pipeline LLC ("Midway"), with a subsidiary of Plains All American Pipeline, L.P. ("Plains"), which acquired the approximately 100-mile, 16-inch pipeline that connects our Coffeyville refinery to the Cushing oil hub, and we separately acquired from Plains the approximately 100-mile, 8- and 10-inch pipeline system connecting our Wynnewood refinery to Cushing. Refer to Part II, Item 8, Note 6 ("Equity Method Investments") of this Report for a discussion of the joint venture transaction.
Our refineries' complexity allows us to optimize the yields (the percentage of refined product that is produced from crude oil and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery's ability to process lower quality crude oil and feedstocks in an economic manner. Our two refineries' capacity weighted average complexity is 13.0. As a result of key investments in our refining assets and the addition of process units to comply with gasoline quality regulations, both of the refinery's complexities have increased. Our Coffeyville refinery's complexity score is 13.3, and our Wynnewood refinery's complexity score is 12.6. Our high complexity provides us the flexibility to increase our refining margin over comparable refiners with lower complexities. We have achieved significant increases in our refinery crude throughput rates over historical levels. As a result of the increasing complexities, we are capable of processing a variety of crudes, including WTS, WTI, sweet and sour Canadian, and locally gathered crudes.
For the year ended December 31, 2017, our Coffeyville refinery's product yield included gasoline (50%), diesel fuel (primarily ultra-low sulfur diesel ("ULSD")) (42%), and pet coke and other refined products such as natural gas liquids ("NGLs") (propane and butane), slurry, sulfur and gas oil (8%). Our Wynnewood refinery's product yield included gasoline (51%), diesel fuel (primarily ULSD) (38%), asphalt (5%), jet fuel (4%) and other products (2%) (slurry, sulfur and gas oil, and specialty products such as propylene and solvents).
Our crude oil gathering system capacity is over 80,000 bpd currently. The gathering system allows us to gather crude oil that is purchased from independent crude oil producers in Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, which serves our two refineries. During 2017, we gathered approximately 86,000 bpd of price-advantaged crudes from our gathering area. The system has field offices in Bartlesville and Pauls Valley, Oklahoma, Plainville and Winfield, Kansas and Denver, Colorado. Gathered crude oil provides an attractive and competitive base supply of crude oil for the Coffeyville and Wynnewood refineries. In aggregate, these crudes have been sourced at a discount to WTI because of our proximity to the sources of crude oil, existing logistics infrastructure and quality differences. We also have 35,000 bpd of contracted capacity on the Keystone and Spearhead pipelines that allow us to supply price-advantaged Canadian crude to our refineries. We also have contracted capacity on the Pony Express and White Cliffs pipelines, which both became in-service during 2015. Both the Pony Express and White Cliffs pipelines originate in Colorado and extend to Cushing.
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In addition to our gathering system, we own (i) a 170,000 bpd pipeline system that transports crude oil from our Broome Station facility to our Coffeyville refinery, (ii) approximately 1.5 million barrels of crude oil storage capacity that supports the gathering system and our Coffeyville refinery, (iii) approximately 0.9 million barrels of crude oil storage capacity at our Wynnewood refinery and (iv) approximately 1.5 million barrels of crude oil storage capacity in Cushing. We also lease additional crude oil storage capacity of approximately 2.3 million barrels in Cushing and 0.2 million barrels in Duncan, Oklahoma. The Duncan storage supports our Wynnewood refinery while the Cushing storage supports both our Wynnewood and Coffeyville refineries.
For the fiscal years ended December 31, 2017, 2016 and 2015, we generated net sales of $5.7 billion, $4.4 billion and $5.2 billion, respectively, and operating income of $203.8 million, $77.8 million and $361.7 million, respectively.
Our History
We were formed by CVR Energy in September 2012 in order to own and operate petroleum and auxiliary businesses as a limited partnership. On January 23, 2013, we completed our initial public offering of 24,000,000 common units to the public priced at $25.00 per unit, resulting in gross proceeds to us of $600.0 million. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises L.P. ("IEP"). Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per unit, resulting in gross proceeds to us of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."
As of December 31, 2017, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings, LLC ("CVR Refining Holdings") held approximately 66% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership’s general partner, CVR Refining GP, which holds a non-economic general partner interest.
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Organizational Structure and Related Ownership
The following chart illustrates our organizational structure as of the date of this Report.
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Crude and Feedstock Supply
Our Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, our Coffeyville refinery crude oil slate consists of a blend of mid-continent domestic grades, various Canadian medium and heavy sours, and North Dakota Bakken and other similarly sourced crudes. While crude oil has constituted over 90% of our Coffeyville refinery's total throughput over the last five years, other feedstock inputs include normal butane, natural gasoline, alkylation feeds, naphtha, gas oil and vacuum tower bottoms.
Our Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutane, gasoline components, and normal butane are also typically used. Historically most of the Wynnewood refinery's crude oil has been acquired domestically, mainly from Texas and Oklahoma, but it can also access and process various light and medium Canadian grades.
Crude oil is supplied to our refineries through our wholly-owned gathering system and by owned, leased and joint venture pipelines. We have continued to increase the number of barrels of crude oil supplied through our crude oil gathering system in 2017 and it now has the capacity of supplying over 80,000 bpd of crude oil to our refineries. For the year ended December 31, 2017, the gathering system supplied approximately 44% and 49% of the Coffeyville and Wynnewood refineries' crude oil demand, respectively. Locally produced crude oils are delivered to the refineries at a discount to WTI, and although sometimes slightly heavier and more sour, offer good economics to the refineries. These crude oils are light and sweet enough to allow us to blend higher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining our target medium sour blend with an API gravity of between 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of our proprietary gathering system are delivered to Cushing by various pipelines, including the Keystone and Spearhead pipelines, and subsequently to our Broome Station facility via the Midway joint venture pipeline. Our current contracted capacity includes the Pony Express and White Cliffs pipelines, respectively. From the Broome Station facility, crude oil is delivered to our Coffeyville refinery via our own 170,000 bpd pipeline system. Crude oils are delivered to the Wynnewood refinery through third-party pipelines, the pipeline we acquired from Plains and, beginning in April 2017, through the VPP joint venture pipeline, and received into storage tanks at terminals located on or near the refinery.
For the year ended December 31, 2017, our Coffeyville refinery's crude oil supply blend was comprised of approximately 92% light sweet crude oil and 8% heavy sour crude oil. For the year ended December 31, 2017, our Wynnewood refinery's crude oil supply blend was comprised entirely of light sweet crude oil. The light sweet crude oil supply blend includes our locally gathered crude oil.
The Coffeyville refinery is connected to the mid-continent natural gas liquids commercial hub of Conway, Kansas by the inbound Enterprise Pipeline Blue Line. Natural gas liquids feedstock supplies such as butanes and natural gasoline are sourced and delivered directly into the refinery. In addition, Coffeyville's proximity to Conway provides access to the natural gas liquid and liquid petroleum gas fractionation and storage capabilities as well as the commercial markets available at Conway.
Crude Oil Supply Agreement
Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies") of this Report for information on the crude oil supply agreement.
Refining Process
Coffeyville Refinery. Our Coffeyville refinery is a 115,000 bpcd rated capacity facility with operations including fractionation, catalytic cracking, hydrotreating, reforming, coking, isomerization, alkylation, sulfur recovery and propane and butane recovery. Our Coffeyville refinery benefits from significant refining unit redundancies, which include two crude oil distillation and vacuum towers, three sulfur recovery units and four hydrotreating units. These redundancies allow us to continue to receive and process crude oil even if one tower requires unplanned maintenance without having to shut down the entire refinery in the case of a major unit turnaround. In addition, our Coffeyville refinery has a redundant supply of hydrogen pursuant to our feedstock and shared services agreement with CVR Partners. During the year ended December 31, 2017, our Coffeyville refinery processed approximately 132,000 bpd and 9,000 bpd of crude oil and feedstocks and blendstocks, respectively.
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Wynnewood Refinery. Our Wynnewood refinery is a 70,000 bpcd rated capacity facility with operations including fractionation, cracking, hydrotreating, hydrocracking, reforming, solvent deasphalting, alkylation, sulfur recovery and propane and butane recovery. Similar to our Coffeyville refinery, our Wynnewood refinery benefits from unit redundancies, including two crude oil distillation and vacuum towers and four hydrotreating units. During the year ended December 31, 2017, our Wynnewood refinery processed approximately 73,000 bpd and 3,000 bpd of crude oil and feedstocks and blendstocks, respectively. These throughput rates for 2017 reflect the first phase of the major scheduled turnaround completed in the fourth quarter of 2017.
Marketing and Distribution
We focus our Coffeyville petroleum product marketing efforts in the central mid-continent area, because of its relative proximity to the refinery and pipeline access. Coffeyville also has access to the Rocky Mountain area. Coffeyville engages in rack marketing, which is the supply of product through tanker trucks and railcars directly to customers located in close geographic proximity to the refinery and to customers at throughput terminals on the refined products distribution systems of Magellan and NuStar. Coffeyville also makes bulk sales (sales into third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. The outbound Enterprise Pipeline Red Line provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ULSD product sales from Kansas up into North Dakota.
Our Wynnewood refinery ships its finished product via pipeline, railcar, and truck. It focuses its efforts in the southern portion of the Magellan system which covers all of Oklahoma, parts of Arkansas as well as eastern Missouri, and all other Magellan terminals. The pipeline system is also able to flow in the opposite direction, providing access to Texas markets as well as some adjoining states with pipeline connections. Wynnewood also sells jet fuel to the U.S. Department of Defense via its segregated truck rack and can offer asphalts, solvents and other specialty products via both truck and rail.
Customers
Customers for our refined petroleum products primarily include retailers, railroads and farm cooperatives and other refiners/marketers in Group 3 of the PADD II region because of their relative proximity to our refineries and pipeline access. We sell bulk products to long-standing customers at spot market prices based on a Group 3 basis differential to prices quoted on the New York Mercantile Exchange ("NYMEX"), which are reported by industry market-related indices such as Platts and Oil Price Information Service.
We also have a rack marketing business supplying product through tanker trucks directly to customers located in proximity to our Coffeyville and Wynnewood refineries, as well as to customers located at throughput terminals on refined products distribution systems run by Magellan and NuStar. Rack sales are at posted prices that are influenced by competitor pricing and Group 3 spot market differentials. Additionally, our Wynnewood refinery supplies jet fuel to the U.S. Department of Defense. In addition, our Coffeyville refinery sells hydrogen and a by-product of its refining operations, such as petroleum coke, to an affiliate, CVR Partners, pursuant to separate multi-year agreements. For the year ended December 31, 2017, one customer accounted for 10% or more of our consolidated revenues. Our largest customer accounted for approximately 19% of our net sales while approximately 52% of our net sales were made to our ten largest customers. While we do have a high concentration of customers, we do not believe that the loss of any single customer would have a material adverse impact on our results of operations, financial condition and the ability to make cash distributions. Refer to Part I, Item 1A, Risk Factors, Our business depends on significant customers and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and our ability to pay distributions to our unitholders.
Competition
We compete primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting our refining operations are cost of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refinery product mix and product distribution and transportation costs. The location of our refineries provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors. We primarily compete against five refineries operated in the mid-continent region. In addition to these refineries, we compete against trading companies, as well as other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the Gulf Coast and the Texas panhandle region. Our competition also includes branded, integrated and independent oil refining companies, such as Phillips 66, HollyFrontier Corporation, CHS Inc., Valero Energy Corporation and Flint Hills Resources.
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Seasonality
Our business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel is higher during the planting and harvesting seasons. As a result, our results of operations for the first and fourth calendar quarters are generally lower compared to our results for the second and third calendar quarters. In addition, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products can impact the demand for gasoline and diesel fuel. The demand for asphalt is also seasonal and is generally higher during the months of March through October.
Environmental Matters
Our businesses are subject to extensive and frequently changing federal, state and local, environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, the storage, handling, use and transportation of petroleum products, and the characteristics and composition of gasoline and diesel fuels. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact our business and operations by imposing:
• | restrictions on operations or the need to install enhanced or additional controls; |
• | the need to obtain and comply with permits, licenses and authorizations; |
• | liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and for off-site waste disposal locations; and |
• | specifications for the products marketed by us, primarily gasoline and diesel fuel. |
Our operations require numerous permits, licenses and authorizations. Failure to comply with these permits or environmental laws and regulations could result in fines, penalties or other sanctions or a revocation of our permits. In addition, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. These laws and regulations could result in increased capital, operating and compliance costs.
The principal environmental risks associated with our businesses are outlined below, with additional details included in Part I, Item 1A, Risk Factors and Part II, Item 8, Note 12 ("Commitments and Contingencies") of this Report.
The Federal Clean Air Act
The federal Clean Air Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect our operations both directly and indirectly. Direct impacts may occur through the federal Clean Air Act's permitting requirements and/or emission control requirements relating to specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. The federal Clean Air Act indirectly affects our operations by extensively regulating the air emissions of sulfur dioxide ("SO2"), volatile organic compounds, nitrogen oxides and other substances, including those emitted by mobile sources, which are direct or indirect users of our products.
Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation of controls or changes to our operations in order to comply. If new controls or changes to operations are needed, the costs could be material. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations, could cause us to expend substantial resources to comply and/or permit our facilities to produce products that meet applicable requirements.
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The regulation of air emissions under the federal Clean Air Act requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at our petroleum operations when regulations change or we add new equipment or modify our existing equipment. Various regulations specific to our operations have been implemented, such as National Emission Standard for Hazardous Air Pollutants ("NESHAP"), New Source Performance Standards ("NSPS") and New Source Review/Prevention of Significant Deterioration ("PSD").
On September 12, 2012, the U.S. Environmental Protection Agency (the "EPA") published in the Federal Register final revisions to its NSPS for process heaters and flares at petroleum refineries. The EPA originally issued final standards in June 2008, but the portions of the rule relating to process heaters and flares were stayed pending reconsideration of certain provisions. The final standards regulate emissions of nitrogen oxide from process heaters and emissions of SO2 from flares, as well as require certain work practice and monitoring standards for flares. We do not believe that the costs of complying with the rule are material.
On December 1, 2015, the EPA published in the Federal Register the petroleum refining sector risk rule. The rule places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. We do not believe that the costs of complying with the rule are material.
Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies") of this Report for further discussion of recent environmental matters related to the Clean Air Act including the "Flood, Crude Oil Discharge and Insurance" and certain "Environmental, Health and Safety ("EHS") Matters."
The Federal Clean Water Act
The federal Clean Water Act ("CWA") and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants into the water, affect our operations. Direct impacts occur through the CWA's permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load of pollutants that may be released to a particular water body based on its use. In addition, water resources are becoming and in the future may become scarcer, and many refiners, including CRRM and Wynnewood Refining Company, LLC ("WRC"), are subject to restrictions on their ability to use water in the event of low availability conditions. Both CRRM and WRC have contracts in place to receive water during certain water shortage conditions, but these conditions could change over time if water becomes scarce.
Release Reporting
The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws. Our facilities periodically experience releases of hazardous and extremely hazardous substances. Our refineries periodically have excess emission events from flaring and other planned and unplanned start up, shutdown and malfunction events. From time to time, the EPA has conducted inspections and issued information requests to us with respect to our compliance with reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and the Emergency Planning and Community Right-to-Know Act. If we fail to timely or properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third-party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.
Fuel Regulations
Tier 2, Low Sulfur Fuels. In February 2000, the EPA promulgated the Tier 2 Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Our refineries are in compliance with the EPA's low sulfur gasoline and diesel fuel standards.
Tier 3. In April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which will require that gasoline contain no more than ten parts per million of sulfur on an annual average basis. Refineries were required to be in compliance with the more stringent emission standards as of January 1, 2017; however, compliance with the rule has been extended until January 1, 2020 for approved small volume refineries and small refiners. In June 2016, because it exceeded the EPA’s specified throughput limit for a “small volume refinery,” the Wynnewood refinery became disqualified as a “small volume refinery.” Therefore, the Wynnewood refinery’s compliance deadline was accelerated to December 21, 2018. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.
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Mobile Source Air Toxic II Emissions
In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that required the reduction of benzene in gasoline by 2011. The MSAT II projects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. Our refineries are in compliance with the EPA's MSAT II rule.
Renewable Fuel Standards
Refer to Part I, Item 1A, Risk Factors, If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected, and Part II, Item 8, Note 12 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" of this Report for further discussion of the "Renewable Fuel Standards."
Greenhouse Gas Emissions
Refer to Part I, Item 1A, Risk Factors, Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows, of this Report for further discussion of the Greenhouse Gas ("GHG") Emissions regulations.
Resource Conservation and Recovery Act ("RCRA")
Our operations are subject to the RCRA requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulated substances. Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" for further discussion of "RCRA Compliance Matters."
Waste Management. There are two closed hazardous waste units at the Coffeyville refinery and fourteen other solid waste management units in the process of being closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewood refinery. In addition, one closed interim status hazardous waste land farm located at the now-closed Phillipsburg terminal is under long-term post closure care.
Impacts of Past Manufacturing. In March 2004, CRRM and Coffeyville Resources Terminal, LLC ("CRT") entered into a Consent Decree ("2004 Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") which required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the Coffeyville refinery. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and groundwater conditions, which required investigation and interim remediation projects. In June 2017, the Coffeyville refinery submitted an amended post-closure permit application to KDHE to complete closure of former hazardous waste management units at the Coffeyville refinery and to perform corrective action at the site. The now-closed Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. The Phillipsburg terminal continues to implement interim measures to address the investigation’s findings. Further remediation, if ordered necessary by the EPA or the state, will be based on the results of the investigation. The Wynnewood refinery operates under a RCRA permit. A RCRA facility investigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, the Oklahoma Department of Environmental Quality ("ODEQ") and WRC have entered into a consent order requiring further investigations of groundwater conditions and enhancements of existing remediation systems. The Wynnewood refinery has completed the groundwater investigation and ODEQ has approved our corrective action recommendations.
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The anticipated investigation and remediation costs through 2021 were estimated, as of December 31, 2017, to be as follows:
Facility | Site Investigation Costs | Capital Costs | Total Operation & Maintenance Costs Through 2021 | Total Estimated Costs Through 2021 | |||||||||||
(in millions) | |||||||||||||||
Coffeyville Refinery | $ | 0.1 | $ | — | $ | — | $ | 0.1 | |||||||
Phillipsburg Terminal | 0.3 | — | — | 0.3 | |||||||||||
Wynnewood Refinery | — | 2.7 | 0.9 | 3.6 | |||||||||||
Total Estimated Costs | $ | 0.4 | $ | 2.7 | $ | 0.9 | $ | 4.0 | |||||||
These estimates are based on current information and could increase or decrease as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2018, we will spend approximately $7.2 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closed Phillipsburg terminal and at the Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately $2.0 million in 2017 associated with related remediation.
Financial Assurance
We are required under the 2004 Consent Decree to establish financial assurance to secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 2004 Consent Decree as modified by a 2010 agreement between CRRM, CRT, the EPA and the KDHE, this financial assurance is currently provided by a bond in the amount of $3.0 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of $0.3 million for estimated costs to close regulated hazardous waste management units at the Coffeyville refinery. Additional self-funded financial assurance of approximately $5.6 million and $2.5 million is required by our post-closure care obligations and the 2004 Consent Decree for clean-up costs at the Coffeyville refinery and Phillipsburg terminal, respectively. The $3.0 million bond amount is reduced each year based on actual expenditures for corrective actions and the letter of credit and the self-funded mechanisms are re-evaluated and adjusted on an annual basis. Current RCRA financial assurance requirements for the Wynnewood refinery total $0.2 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.
Environmental Remediation
As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. There is no assurance that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material. Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies"), "Flood, Crude Oil Discharge and Insurance" of this Report for discussion of the environmental remediation associated with the discharge of crude oil on July 1, 2007 at the Coffeyville refinery.
Environmental Insurance
We are covered by CVR Energy's site pollution legal liability insurance policy. The policy includes business interruption coverage. The policy insures any location owned, leased, rented or operated by CVR Refining, including the Coffeyville and Wynnewood refineries. The policy insures certain pollution conditions at or migrating from a covered location, certain waste transportation and disposal activities and business interruption.
In addition to the site pollution legal liability insurance policy, we benefit from umbrella and excess casualty insurance policies which include sudden and accidental pollution coverage maintained by CVR Energy. This insurance provides coverage due to named perils for claims involving pollutants where the discharge is sudden and accidental and first commences at a specific day and time during the policy period.
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The site pollution legal liability policy and the pollution coverage provided in the casualty insurance policies are subject to retentions and deductibles and contain discovery requirements, reporting requirements, exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.
Safety, Health and Security Matters
We are subject to a number of federal and state laws and regulations related to safety, including the Occupational Safety and Health Act ("OSHA") and comparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
We operate a comprehensive safety, health and security program, with participation by employees at all levels of the organization. We have developed comprehensive safety programs aimed at preventing OSHA recordable incidents. Despite our efforts to achieve excellence in our safety and health performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely audit our programs and consider improvements in our management systems.
Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies"), "Wynnewood Refinery Incident" of this Report for further discussion of OSHA matters related to the Wynnewood refinery boiler explosion.
Employees
As of December 31, 2017, we employed 959 direct employees. These employees are covered by health insurance, disability and retirement plans established by CVR Energy. We believe that our relationship with our employees is good.
As of December 31, 2017, (i) the Coffeyville refinery employed 353 of our employees, about 66% of whom are covered by a collective bargaining agreement with five unions of the Metal Trades Department of the AFL-CIO ("Metal Trade Unions"), which expires in March 2019, (ii) we had 259 employees who work in crude transportation, about 32% of whom are covered by a collective bargaining agreement with the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC ("United Steelworkers"), which expires in March 2019 and automatically renews on an annual basis unless a written notice is received sixty days in advance of the relevant expiration date, and (iii) the Wynnewood refinery employed 300 of our employees, about 59% of whom are covered by a collective bargaining agreement with the International Union of Operating Engineers, which expires in June 2021.
We also rely on the services of employees of CVR Energy and its subsidiaries pursuant to a services agreement among us, CVR Energy and our general partner. Additionally, the Partnership's general partner manages the Partnership's operations and activities as specified in the partnership agreement and had 10 employees as of December 31, 2017. For more information on these agreements, refer to Part II, Item 8, Note 15 ("Related Party Transactions") of this Report.
Available Information
Our website address is www.cvrrefining.com. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), are available free of charge through our website under "Investor Relations," as soon as reasonably practicable after the electronic filing or furnishing of these reports is made with the Securities and Exchange Commission (the "SEC"). In addition, our Corporate Governance Guidelines, Codes of Ethics and Business Conduct and Charters of the Audit Committee and Compensation Committee of the Board of Directors of our general partner are available on our website. These guidelines, policies and charters are also available in print without charge to any unitholder requesting them. We do not intend for information contained in our website to be part of this Report.
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Item 1A. Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this Report.
If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In such cases, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.
Risks Inherent in Our Business
We may not have sufficient available cash to pay any quarterly distribution on our common units.
We may not have sufficient available cash (which is defined as 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) each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The board of directors of our general partner may at any time, for any reason, change our cash distribution policy or decide not to make any distribution. The amount of cash we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is directly dependent upon the margins we generate. Please see "— The price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on our profitability and our ability to pay distributions to common unitholders" below.
The price volatility of crude oil and other feedstocks, refined products and utility services may have a material adverse effect on our earnings and our ability to pay distributions to common unitholders.
Our financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices tightens, our earnings, profitability and cash flows are negatively affected. Refining margins historically have been volatile and are likely to continue to be volatile, as a result of a variety of factors including fluctuations in prices of crude oil, other feedstocks and refined products. Continued future volatility in refining industry margins may cause a decline in our results of operations, since the margin between refined product prices and crude oil and other feedstock prices may decrease below the amount needed for us to generate net cash flow sufficient for our needs. The effect of changes in crude oil prices on our results of operations therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, or a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, could have a significant negative impact on our earnings, results of operations and ability to pay distributions to common unitholders.
Our profitability is also impacted by our ability to purchase crude oil at a discount to benchmark crude oils, such as WTI, as we do not produce any crude oil and must purchase all of the crude oil we refine. Crude oil differentials can fluctuate significantly based upon overall economic and crude oil market conditions. Adverse changes in crude oil differentials can adversely impact refining margins, earnings and cash flows. In addition, our purchases of crude oil, although based on WTI prices, have historically been at a discount to WTI because of our proximity to the sources, existing logistics infrastructure and quality differences. Any change in the sources of our crude oil, infrastructure or logistical improvements or quality differences could result in a reduction of our historical discount to WTI and may result in a reduction of our cost advantage.
Refining margins are also impacted by domestic and global refining capacity. Downturns in the economy reduce the demand for refined fuels and, in turn, generate excess capacity. In addition, the expansion and construction of refineries domestically and globally can increase refined fuel production capacity. Excess capacity can adversely impact refining margins, earnings and cash flows. The Arabian Gulf and Far East regions added refining capacity in 2015 and 2016.
We are significantly affected by developments in the markets in which we operate. For example, numerous pipeline projects in 2014 expanded the connectivity of the Cushing and Permian Basin markets to the gulf coast, resulting in a decrease in the domestic crude advantage.
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Volatile prices for natural gas and electricity also affect our manufacturing and operating costs. Natural gas and electricity prices have been, and will continue to be, affected by supply and demand for fuel and utility services in both local and regional markets.
The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow and not solely on profitability.
The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which may be affected by items that do not fully impact net income in a given quarter. We may have working capital changes as well as extraordinary capital expenditures and major maintenance expenses in the future. See "Management's Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Capital Spending." While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution with respect to such quarter. As a result, we may make cash distributions during periods when we report losses and may not make cash distributions during periods when we report net income.
The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business which is volatile and seasonal.
Historically, our business performance has been volatile and seasonal. For instance, our results of operations for the second and third quarters are generally higher than our results of operations for the first and fourth quarters, as demand for gasoline products increases due to higher highway traffic and road construction work during the summer months, and demand for diesel fuel decreases somewhat due to decreased agricultural activity in the winter. We expect that our future business performance will be more volatile and seasonal, and that our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. Because our quarterly distributions will significantly correlate to the cash we generate each quarter after payment of our fixed and variable expenses, future quarterly distributions paid to our common unitholders will vary significantly from quarter to quarter and may be zero.
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions at all.
Our general partner's current policy is to distribute an amount equal to all of the available cash we generate each quarter to common unitholders of record on a pro rata basis. However, the board of directors of our general partner may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions at all. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our common unitholders.
Our refining business faces significant risks due to physical damage hazards, environmental liability risk exposure and unplanned or emergency partial or total plant shutdowns resulting in business interruptions. We could incur potentially significant costs to the extent there are unforeseen events which cause property damage and a material decline in production which are not fully insured. The commercial insurance industry engaged in underwriting energy industry risk is specialized and there is finite capacity; therefore, the industry may limit or curtail coverage, may modify the coverage provided or may substantially increase premiums in the future.
If any of our production plants, logistics assets, key pipeline operations serving our plants, or key suppliers sustains a catastrophic loss and operations are shutdown or significantly impaired, it would have a material adverse impact on our operations, financial condition and cash flows. Operations at either or both of the refineries could be curtailed, limited or completely shut down for an extended period of time as the result of one or more unforeseen events and circumstances, which may not be within our control, including:
• | major unplanned maintenance requirements; |
• | catastrophic events caused by mechanical breakdown, electrical injury, pressure vessel rupture, explosion, contamination, fire or natural disasters, including floods, windstorms and other similar events; |
• | labor supply shortages or labor contract disputes that result in a work stoppage or slowdown; |
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• | cessation or suspension of a plant or specific operations dictated by environmental authorities; and |
• | an event or incident involving a large clean-up, decontamination, or the imposition of laws and ordinances regulating the cost and schedule of demolition or reconstruction, which can cause significant delays in restoring property to its pre-loss condition. |
We have sustained losses over the past ten-year period at our refineries, which are illustrative of the types of risks and hazards that exist. These losses or events resulted in costs assumed by us that were not fully insured due to policy retentions or applicable exclusions.
Currently, we are insured under CVR Energy's casualty, environmental, property and business interruption insurance policies. The property and business interruption policies insure real and personal property, including property located at our refineries and our related crude gathering and logistics assets. There is potential for a common occurrence to impact both the CVR Partners' nitrogen fertilizer plant in Coffeyville, Kansas and the Coffeyville refinery, in which case the insurance limits and applicable sub-limits would apply to all damages combined. These policies are subject to limits, sub-limits, retentions (financial and time-based) and deductibles. The application of these and other policy conditions could materially impact insurance recoveries and potentially cause us to assume losses which could impair earnings.
There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and there are risks associated with the commercial insurance industry reducing capacity, changing the scope of insurance coverage offered, and substantially increasing premiums resulting from highly adverse loss experience or other financial circumstances. Factors that impact insurance cost and availability include, but are not limited to: industry wide losses, natural disasters, specific losses incurred by us and low or inadequate investment returns earned by the insurance industry. If the supply of commercial insurance is curtailed due to highly adverse financial results we may not be able to continue our present limits of insurance coverage or obtain sufficient insurance capacity to adequately insure our risks for property damage or business interruption.
If we are required to obtain our crude oil supply without the benefit of a crude oil supply agreement, our exposure to the risks associated with volatile crude oil prices may increase and our liquidity may be reduced.
Since December 31, 2009, we have obtained substantially all of our crude oil supply for the Coffeyville refinery, other than the crude oil we gather, through the Vitol Agreement. The Vitol Agreement was amended and restated on August 31, 2012 to include the provision of crude oil intermediation services to our Wynnewood refinery. The agreement, which currently extends through December 31, 2018, minimizes the amount of in-transit inventory and mitigates crude oil pricing risk by ensuring pricing takes place close to the time the crude oil is refined and the yielded products are sold. If we were required to obtain our crude oil supply without the benefit of a supply intermediation agreement, our exposure to crude oil pricing risk may increase, despite any hedging activity in which we may engage, and our liquidity could be negatively impacted due to increased inventory, potential need to post letters of credit and negative impacts of market volatility. There is no assurance that we will be able to renew or extend the Vitol Agreement beyond December 31, 2018.
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Disruption of our ability to obtain an adequate supply of crude oil could reduce our liquidity and increase our costs.
In addition to the crude oil we gather locally in Kansas, Nebraska, Oklahoma, Missouri, Colorado and Texas, we also purchased additional crude oil to be refined into liquid fuels in 2017. In 2017, our Coffeyville refinery purchased approximately 75,000 to 80,000 bpd of crude oil while our Wynnewood refinery purchased approximately 35,000 to 40,000 bpd of crude oil. Our Wynnewood refinery has historically acquired most of its purchased crude oil from Texas and Oklahoma with smaller amounts purchased from other regions. In 2017, our Coffeyville refinery obtained a portion of its non-gathered crude oil, approximately 12%, from Canada. The actual amount of Canadian crude oil we purchase is dependent on market conditions and will vary from year to year. We are subject to the political, geographic, and economic risks attendant to doing business with Canada. Disruption of production for any reason could have a material impact on our ability to make distributions. In the event that one or more of our traditional suppliers becomes unavailable to us, we may be unable to obtain an adequate supply of crude oil, or we may only be able to obtain our crude oil supply at unfavorable prices. As a result, we may experience a reduction in our liquidity and our results of operations could be materially adversely affected.
If our access to the pipelines on which we rely for the supply of our crude oil and the distribution of our products is interrupted, our inventory and costs may increase and we may be unable to efficiently distribute our products.
If one of the pipelines on which either of the Coffeyville or Wynnewood refineries relies for supply of crude oil becomes inoperative, we would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase our costs and result in lower production levels and profitability. Similarly, if a major refined fuels pipeline becomes inoperative, we would be required to keep refined fuels in inventory or supply refined fuels to our customers through an alternative pipeline or by additional tanker trucks, which could increase our costs and result in a decline in profitability.
The geographic concentration of our refineries and related assets creates an exposure to the risks of the local economy in which we operate and other local adverse conditions. The location of our refineries also creates the risk of increased transportation costs should the supply/demand balance change in our region such that regional supply exceeds regional demand for refined products.
As our refineries are both located in the southern portion of Group 3 of the PADD II region, we primarily market our refined products in a relatively limited geographic area. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect our operating area could also materially adversely affect our revenues and our ability to make distributions. These factors include, among other things, changes in the economy, weather conditions, demographics and population, increased supply of refined products from competitors and reductions in the supply of crude oil.
Should the supply/demand balance shift in our region as a result of changes in the local economy, an increase in refining capacity or other reasons, resulting in supply in the region exceeding demand, we may have to deliver refined products to customers outside of the region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any.
If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected.
The EPA has promulgated the Renewable Fuel Standard ("RFS"), which requires refiners to either blend "renewable fuels," such as ethanol and biodiesel, into their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels that refineries like ours are obligated to blend into their finished petroleum products is adjusted annually by the EPA. We are not able to blend the substantial majority of our transportation fuels, so we have to purchase RINs on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. The price of RINs has been extremely volatile as the EPA's proposed renewable fuel volume mandates approached and exceeded the "blend wall." The blend wall refers to the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume ("E10 gasoline") is blended into transportation fuel.
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In December 2015, 2016, and 2017, the EPA published in the Federal Register final rules establishing the renewable fuel volume mandates for 2016, 2017, and 2018, and the biomass-based diesel volume mandates for 2017, 2018, and 2019, respectively. The volumes included in the EPA's final rules increased each year, but were lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authorities to lower the volumes, but its decision to do so for the 2014-2016 compliance years was challenged in the U.S. Court of Appeals for the District of Columbia Circuit. In July 2017, the court vacated the EPA’s decision to reduce the renewable volume obligation for 2016 under one of its waiver authorities, and remanded the rule to the EPA for further reconsideration. The EPA has not yet re-proposed the 2016 renewable volume obligations. The EPA also has articulated a policy that high RINs prices incentivize additional investments in renewable fuel blending and distribution infrastructure.
We cannot predict the future prices of RINs or waiver credits. The price of RINs has been extremely volatile over the last year. Additionally, the cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our petroleum products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period. However, the costs to obtain the necessary number of RINs and waiver credits could be material, if the price for RINs increases. Additionally, because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refineries' product pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions. If the demand for our transportation fuel decreases as a result of the use of increasing volumes of renewable fuels, increased fuel economy as a result of new EPA fuel economy standards, or other factors, the impact on our business could be material. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations and ability to pay distributions to our common unitholders could be materially adversely affected.
We face significant competition, both within and outside of our industry. Competitors who produce their own supply of crude oil or other feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us.
The refining industry is highly competitive with respect to both crude oil and other feedstock supply and refined product markets. We may be unable to compete effectively with our competitors within and outside of our industry, which could result in reduced profitability. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We are not engaged in the petroleum exploration and production business and therefore we do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. We do not have long-term arrangements (those exceeding more than a twelve-month period) for much of our output. Many of our competitors obtain significant portions of their crude oil and other feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.
A number of our competitors also have materially greater financial and other resources than us. These competitors may have a greater ability to bear the economic risks inherent in all aspects of the refining industry. An expansion or upgrade of our competitors' facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics and may add additional competitive pressure on us.
In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual customers. There are presently significant governmental incentives and consumer pressures to increase the use of alternative fuels in the United States. The more successful these alternatives become as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the negative impact on pricing and demand for our products and our profitability.
Our indebtedness may affect our ability to operate our business, and may have a material adverse effect on our financial condition and results of operations.
We have incurred indebtedness and we may be able to incur significant additional indebtedness in the future. If new indebtedness is added to our current indebtedness, the risks described below could increase. Our level of indebtedness could have important consequences, such as:
• | 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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• | 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; |
• | 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; |
• | 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; |
• | restricting us from making strategic acquisitions or investments, introducing new technologies or exploiting business opportunities; |
• | 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; |
• | 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; |
• | increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and |
• | limiting our ability to react to changing market conditions in our industry and in our customers' industries. |
In addition to our debt service obligations, our operations require substantial investments on a continuing basis. Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors.
In addition, we are and will be subject to covenants contained in agreements governing our present and future indebtedness. These covenants include, and will likely include, restrictions on certain payments (including restrictions on distributions to our common unitholders), the granting of liens, the incurrence of additional indebtedness, dividend restrictions affecting subsidiaries, asset sales, transactions with affiliates and mergers and consolidations. Any failure to comply with these covenants could result in a default under our current credit agreements or debt instruments or future credit agreements.
Our debt agreements contain restrictions that will limit our flexibility in operating our business and our ability to make distributions to our common unitholders.
Our debt facilities and instruments contain, and any instruments governing future indebtedness of ours would likely contain, a number of covenants that impose significant operating and financial restrictions on us, including restrictions on our and our subsidiaries' ability to, among other things:
• | incur additional indebtedness or issue certain preferred units; |
• | pay distributions in respect of our units or make other restricted payments; |
• | make certain payments on debt that is subordinated or secured on a junior basis; |
• | make certain investments; |
• | sell certain assets; |
• | create liens on certain assets; |
• | consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; |
• | enter into certain transactions with our affiliates; and |
• | designate our subsidiaries as unrestricted subsidiaries. |
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Any of these restrictions could limit our ability to plan for or react to market conditions and could otherwise restrict partnership activities. Any failure to comply with these covenants could result in a default under our debt facilities and instruments. Upon a default, unless waived, the lenders under our debt facilities and instruments would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our assets, and force us into bankruptcy or liquidation, subject to any applicable intercreditor agreements. In addition, a default under our debt facilities and instruments would trigger a cross default under our other agreements and could trigger a cross default under the agreements governing our future indebtedness. Our operating results may not be sufficient to service our indebtedness or to fund our other expenditures and we may not be able to obtain financing to meet these requirements.
Instability and volatility in the capital, credit and commodity markets in the global economy could negatively impact our business, financial condition, results of operations and cash flows.
Our business, financial condition and results of operations could be negatively impacted by difficult conditions and volatility in the capital, credit and commodities markets and in the global economy. For example:
• | Although we believe 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. |
• | 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. |
• | 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. |
Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refineries at full capacity.
Changes in our credit profile may affect the way crude oil suppliers view our ability to make payments and may induce them to shorten the payment terms for our purchases or require us to post security prior to payment. Given the large dollar amounts and volume of our crude oil and other feedstock purchases, a burdensome change in payment terms may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flows.
Our commodity derivative contracts may limit our potential gains, exacerbate potential losses and involve other risks.
We may enter into commodity derivatives contracts to mitigate our crack spread risk with respect to a portion of our expected refined products production. However, our hedging arrangements may fail to fully achieve this objective for a variety of reasons, including our failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, such transactions may limit our ability to benefit from favorable changes in margins. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:
• | 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; |
• | accidents, interruptions in transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refinery or our suppliers or customers; |
• | the counterparties to our futures contracts fail to perform under the contracts; or |
• | a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement. |
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As a result, the effectiveness of our risk mitigation strategy could have a material adverse impact on our financial results and our ability to make distributions to common unitholders.
Our commodity derivative activities could result in period-to-period volatility.
We do not apply hedge accounting to our commodity derivative contracts and, as a result, unrealized gains and losses are charged to our earnings based on the increase or decrease in the market value of the unsettled position. Such gains and losses are reflected in our income statement in periods that differ from when the underlying hedged items (i.e., gross margins) are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our operational performance.
The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.
The U.S. Congress has adopted the Dodd-Frank Act, comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market, and requires the Commodities Futures Trading Commission ("CFTC") to, among other things, institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The Dodd-Frank Act and implementing rules and regulations also require certain swap participants to comply with, among other things, certain margin requirements and clearing and trade-execution requirements in connection with certain derivative activities. The rulemaking process is still ongoing, and we cannot predict the ultimate outcome of the rulemakings. New regulations in this area may result in increased costs and cash collateral requirements for derivative instruments we may use to hedge and otherwise manage our financial risks related to volatility in oil and gas commodity prices.
If we reduce our use of derivatives as a result of the Dodd-Frank Act and any new rules and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to satisfy our debt obligations or plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices. If the Dodd-Frank Act and any new regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations and therefore could have an adverse effect on our ability to satisfy our debt obligations.
Existing design, operational, and maintenance issues associated with acquisitions may not be identified immediately and may require unanticipated capital expenditures that could adversely impact our financial condition, results of operations, cash flows and ability to make distributions to common unitholders.
Our due diligence associated with acquisitions or joint ventures may result in our assuming liabilities associated with unknown conditions or deficiencies, as well as known but undisclosed conditions and deficiencies, where we may have limited, if any, recourse for cost recovery. Such conditions and deficiencies may not become evident until sometime after cost recovery provisions, if any, have expired.
We must make substantial capital expenditures on our refineries and other facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows, and our ability to make distributions to common unitholders, could be adversely affected.
Delays or cost increases related to the engineering, procurement and construction of new facilities, or improvements and repairs to our existing facilities and equipment, could have a material adverse effect on our business, financial condition, results of operations or our ability to make distributions to our common unitholders. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:
• | denial or delay in obtaining regulatory approvals and/or permits; |
• | unplanned increases in the cost of equipment, materials or labor; |
• | disruptions in transportation of equipment and materials; |
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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; |
• | shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages; |
• | market-related increases in a project's debt or equity financing costs; and/or |
• | non-performance or force majeure by, or disputes with, our vendors, suppliers, contractors or sub-contractors. |
Our refineries have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. Our refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The first phase of the Coffeyville refinery's most recent turnaround was completed in November 2015 at a total cost of approximately $102.2 million. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016 at a total cost of approximately $31.5 million. The next turnaround scheduled for the Wynnewood refinery is being performed as a two phase turnaround. The first phase of its current turnaround was completed in November 2017 at a total cost of approximately $67.4 million. The second phase of the Wynnewood turnaround is expected to occur in 2019. In addition to the two phase turnaround, we accelerated certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. We incurred approximately $13.0 million of major scheduled turnaround expenses for the hydrocracker.
Any one or more of these occurrences noted above could have a significant impact on our business. If we were unable to make up the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows and, as a result, our ability to make distributions.
Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.
Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous wastes. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns.
In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmental compliance could have a material adverse effect on our results of operations, financial condition and profitability.
Our facilities operate under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. All of these permits, licenses, approvals, limits and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval, limit or standard. Non-compliance or incomplete documentation of our compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due to the nature of our manufacturing and refining process, there may be times when we are unable to meet the standards and terms and conditions of our permits, licenses and approvals due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities and accordingly our financial performance. For a discussion of environmental laws and regulations and their impact on our business and operations, please see "Business — Environmental Matters."
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We could incur significant cost in cleaning up contamination at our refineries, terminals, and off-site locations.
Our businesses are subject to the occurrence of accidental spills, discharges or other releases of petroleum or hazardous substances into the environment. Past or future spills related to any of our current or former operations, including our refineries, pipelines, product terminals, or transportation of products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under CERCLA, and similar state statutes for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with facilities we currently own or operate (whether or not such contamination occurred prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal.
The potential penalties and cleanup costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and ability to pay distributions to our common unitholders. In addition, we may incur liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability for personal injury, property damage, natural resource damage or for cleanup costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.
Three of our facilities, including our Coffeyville refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), and the Wynnewood refinery, have environmental contamination. We have assumed Farmland's responsibilities under certain administrative orders under the RCRA related to contamination at or that originated from the Coffeyville refinery and the Phillipsburg terminal. The Coffeyville refinery has agreed to assume liability for contamination that migrated from the refinery onto the nitrogen fertilizer plant property while Farmland owned and operated the properties. At the Wynnewood refinery, known areas of contamination have been partially addressed but corrective action has not been completed (refer to "RCRA Compliance Matters" in Part II, Item 8, Note 12 ("Commitments and Contingencies") of this Report). If significant unknown liabilities are identified at or migrating from any of our facilities, that liability could have a material adverse effect on our results of operations, financial condition and cash flows and may not be covered by insurance.
We may incur future liability relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the treatment, transportation or disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation of contamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposal and the damages or costs in any such proceedings could be material.
We may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
We hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Future expansion of our operations is predicated upon securing the necessary environmental or other permits or approvals. A decision by a government agency to deny or delay issuing a new or renewed material permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows.
Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows.
The EPA regulates GHG emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our GHG emissions at our Coffeyville and Wynnewood refineries to the EPA. In May 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new GHG emissions thresholds that determine when stationary sources, such as our refineries, must obtain permits under PSD and Title V programs of the federal Clean Air Act. Under the rule, facilities already subject to the PSD and Title V programs that increase their emissions of GHGs by a significant amount are required to undergo PSD review and to evaluate and implement air pollution control technology, known as "best available control technology," to reduce GHG emissions.
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In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate NSPS to regulate GHG emissions from petroleum refineries and electric utilities by November 2012. In September 2014, the EPA indicated that the petroleum refining sector risk rule, proposed in June 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for the EPA to regulate GHG emissions from petroleum refineries at this time. The final rule, which was published in the Federal Register on December 1, 2015, places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units and other equipment at petroleum refineries. In 2015, the EPA promulgated NSPS for carbon dioxide emissions from electric utilities, although the EPA announced in April 2017 that those NSPS were under review and may be suspended, revised or rescinded. Therefore, we expect that the EPA will not be issuing NSPS to regulate GHG from petroleum refineries at this time but that it may do so in the future.
The current administration has sought to implement a new or modified policy with respect to climate change. For example, the administration announced its intention to withdraw the United States from the Paris Climate Agreement, though the earliest possible effective date of withdrawal for the United States is November 2020. If efforts to address climate change resume, at the federal legislative level, this could mean Congressional passage of legislation adopting some form of federal mandatory GHG emission reduction, such as a nationwide cap-and-trade program. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.
In addition to potential federal legislation, a number of states have adopted regional GHG initiatives to reduce carbon dioxide and other GHG emissions. In 2007, a group of Midwest states, including Kansas (where our Coffeyville refinery is located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control GHG emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations that implement the trading scheme before it becomes effective. To date, Kansas has taken no meaningful action to implement the accord, and it is unclear whether Kansas intends to do so in the future.
Alternatively, the EPA may take further steps to regulate GHG emissions, although at this time it is unclear to what extent the EPA will pursue climate change regulation. The implementation of EPA regulations and/or the passage of federal or state climate change legislation may result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any current or future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows.
In addition, climate change legislation and regulations may result in increased costs not only for our business but also users of our refined products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.
We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers, and the proper design, operation and maintenance of our equipment. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows.
We are subject to cybersecurity risks and other cyber incidents resulting in disruption.
Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. We depend on information technology systems. In addition, we collect, process, and retain sensitive and confidential customer information in the normal course of business. Despite the security measures we have in place and any additional measures we may implement in the future, our facilities and systems, and those of our third-party service providers, could be vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, human errors, acts of vandalism or other events. Any disruption of our systems or security breach or event resulting in the misappropriation, loss or other unauthorized disclosure of confidential information, whether by us directly or our third-party service providers, could damage our reputation, expose us to the risks of litigation and liability, disrupt our business or otherwise affect our results of operations.
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Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or the public and result in liability to us.
Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results, financial condition and cash flows.
Our business depends on significant customers and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and our ability to pay distributions to our common unitholders.
Both the Coffeyville and the Wynnewood refineries have a significant concentration of customers. Our five largest customers represented 39% of our net sales for the year ended December 31, 2017. Our top customer accounted for approximately 19% of our net sales for this same period. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with our customers. The loss of several of these significant customers, or a significant reduction in purchase volume by several of them, could have a material adverse effect on our results of operations, financial condition and our ability to pay distributions to our common unitholders.
Our plans to expand our gathering and logistics assets, which assist us in reducing our costs and increasing our processing margins, may expose us to significant additional risks, compliance costs and liabilities.
We plan to continue to make investments to enhance the operating flexibility of our refineries and to improve our crude oil sourcing advantage through additional investments in our gathering and logistics assets. If we are able to successfully increase the effectiveness of our supporting gathering and logistics assets, we believe we will be able to enhance our crude oil sourcing flexibility and reduce related crude oil purchasing and delivery costs. However, the acquisition of infrastructure assets to expand crude oil gathering may expose us to risks in the future that are different than or incremental to the risks we face with respect to our refineries and existing gathering and logistics assets. The storage and transportation of liquid hydrocarbons, including crude oil and refined products, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment, operational safety and related matters. Compliance with these laws and regulations could adversely affect our operating results, financial condition and cash flows. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibit our operations, or claims of damages to property or persons resulting from our operations.
Any businesses or assets that we may acquire in connection with an expansion of our crude oil gathering could expose us to the risk of releasing hazardous materials into the environment. These releases would expose us to potentially substantial expenses, including cleanup and remediation costs, fines and penalties, and third-party claims for personal injury or property damage related to past or future releases. Accordingly, if we do acquire any such businesses or assets, we could also incur additional expenses not covered by insurance which could be material.
More stringent trucking regulations may increase our costs and negatively impact our results of operations.
In connection with the trucking operations conducted by our crude gathering division, we operate as a motor carrier and therefore are subject to regulation by federal and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent fuel-economy regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder or electronic logging devices or limits on vehicle weight and size.
To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Furthermore, from time to time, various legislative proposals are introduced, such as proposals to increase federal, state or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes will be enacted or the extent to which they will apply to us and our operations.
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The acquisition and expansion strategy of our business involves significant risks.
Our management will consider pursuing acquisitions and expansion projects in order to continue to grow and increase profitability. However, we may not be able to consummate such acquisitions or expansions, due to intense competition for suitable acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions and expansions, difficulties in identifying suitable acquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms and the failure to obtain requisite regulatory or other governmental approvals. In addition, any future acquisitions and expansions may entail significant transaction costs and risks associated with entry into new markets and lines of business.
In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:
• | unforeseen difficulties in the integration of the acquired operations and disruption of the ongoing operations of our business; |
• | failure to achieve cost savings or other financial or operating objectives contributing to the accretive nature of an acquisition; |
• | strain on the operational and managerial controls and procedures of our business, and the need to modify systems or to add management resources; |
• | difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies; |
• | assumption of unknown material liabilities or regulatory non-compliance issues; |
• | amortization of acquired assets, which would reduce future reported earnings; |
• | possible adverse short-term effects on our cash flows or operating results; and |
• | diversion of management's attention from the ongoing operations of our business. |
In addition, in connection with any potential acquisition or expansion project, we will need to consider whether a business we intend to acquire or expansion project we intend to pursue could affect our tax treatment as a partnership for federal income tax purposes. If we are otherwise unable to conclude that the activities of the business being acquired or the expansion project would not affect our treatment as a partnership for federal income tax purposes, we may elect to seek a ruling from the Internal Revenue Service ("IRS"). Seeking such a ruling could be costly or, in the case of competitive acquisitions, place us in a competitive disadvantage compared to other potential acquirers who do not need to seek such a ruling. If we are unable to conclude that an activity would not affect our treatment as a partnership for federal income tax purposes, and are unable or unwilling to obtain an IRS ruling, we may choose to acquire such business or develop such expansion project in a corporate subsidiary, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of cash available for distribution to the common unitholders and could likely cause a substantial reduction in the value of our common units.
Failure to manage these acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition and ability to pay cash distributions to our common unitholders. Our joint ventures involve similar risks. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.
We are a holding company and depend upon our subsidiaries for our cash flow.
We are a holding company, and our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of distributions, tax sharing payments or otherwise. The ability of our subsidiaries to make any payments to us will depend on, among other things, their earnings, the terms of their indebtedness, tax considerations and legal restrictions.
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Our internally generated cash flows and other sources of liquidity may not be adequate for our capital needs.
Refining businesses such as ours are capital intensive, and working capital needs may vary significantly over relatively short periods of time. For instance, crude oil price volatility can significantly impact working capital on a week-to-week and month-to-month basis. If we cannot generate adequate cash flow or otherwise secure sufficient liquidity to meet our working capital needs or support our short-term and long-term capital requirements, we may be unable to meet our debt obligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business and results of operations.
A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disrupt our business and increase our costs.
As of December 31, 2017, approximately 66% of the employees at the Coffeyville refinery, 59% of the employees at the Wynnewood refinery and 32% of the employees who work in crude transportation were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with five Metal Trades Unions (which covers union represented employees who work directly at the Coffeyville refinery) expires in March 2019. The collective bargaining agreement with the United Steelworkers (which covers unionized employees who work in crude transportation) expires in March 2019, and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2021. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations, financial condition and cash flows.
Risks Inherent in Our Limited Partnership Structure and Common Units
The board of directors of our general partner has in place a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.
Our general partner's current policy is to distribute an amount equal to the available cash we generate each quarter to our common unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow. The board of directors of the general partner may modify or revoke our cash distribution policy at any time at its discretion, including in such a manner that would result in an elimination of cash distributions regardless of the amount of available cash we generate. Our partnership agreement does not require us to make any distributions.
In addition, because of our distribution policy, our growth, if any, may not be as robust as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current common unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the outstanding common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our common unitholders.
We rely on the executive officers of CVR Energy to manage certain aspects of our business and affairs pursuant to a services agreement, which CVR Energy can terminate at any time.
Our future performance depends to a significant degree upon the continued contributions of CVR Energy's senior management team. We have entered into a services agreement with our general partner and CVR Energy whereby CVR Energy has agreed to provide us with the services of its senior management team as well as accounting, legal, finance and other key back-office and mid-office personnel. CVR Energy can terminate this agreement at any time, subject to a 180-day notice period. The loss or unavailability to us of any member of CVR Energy's senior management team could negatively affect our ability to operate our business and pursue our business strategies. We do not have employment agreements with any of CVR Energy's officers and we do not maintain any key person insurance. In addition, CVR Energy may not continue to provide us the officers that are necessary for the conduct of our business or such provision may not be on terms that are acceptable. If CVR Energy elected to terminate the service agreement on 180 days' notice, we might not be able to find qualified individuals to serve as our executive officers within such 180-day period.
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In addition, pursuant to the services agreement we are responsible for a portion of the compensation expense of such executive officers according to the percentage of time such executive officers spend working for us. However, the compensation of such executive officers is set by CVR Energy, and we have no control over the amount paid to such officers. The services agreement does not contain any cap on the amounts we may be required to pay CVR Energy pursuant to this agreement.
Our general partner, an indirect wholly-owned subsidiary of CVR Energy, owes fiduciary duties to CVR Energy and its stockholders, and the interests of CVR Energy and its stockholders may differ significantly from, or conflict with, the interests of our public common unitholders.
Our general partner is responsible for managing us. Although our general partner has a duty to manage us in a manner that is not adverse to our interest, the fiduciary duties are specifically limited by the express terms of our partnership agreement, and the directors and officers of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to CVR Energy and its stockholders. The interests of CVR Energy and its stockholders may differ from, or conflict with, the interests of our public common unitholders. In resolving these conflicts, our general partner may favor its own interests, the interests of CVR Refining Holdings, its sole member, or the interests of CVR Energy and holders of CVR Energy's common stock, including its majority stockholder, Icahn Enterprises, over our interests and those of our common unitholders.
The potential conflicts of interest include, among others, the following:
• | 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 common unitholders, such as its owners or CVR Energy, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our common unitholders. |
• | 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. |
• | 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. |
• | Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. |
In addition, CVR Energy may compete with us, may in the future acquire assets which compete with our assets or may acquire assets such as refineries which we might otherwise have sought to acquire. We do not have any non-compete agreements or understandings with CVR Energy or any other agreement with CVR Energy regarding the allocation of corporate opportunities.
Our partnership agreement limits the liability and replaces the fiduciary duties of our general partner and restricts the remedies available to us and our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement limits the liability and replaces the fiduciary duties of our general partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. By purchasing common units, common unitholders consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. Our partnership agreement contains provisions that replace the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:
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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. |
• | Our partnership agreement provides that our general partner will not have any liability to us or our common 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. |
• | 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. |
• | 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: |
• | 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 |
• | approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates. |
CVR Energy has the power to appoint and remove our general partner's directors.
CVR Energy has the power to elect all of the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. Our public common unitholders do not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Furthermore, the goals and objectives of CVR Energy and IEP, as the indirect owners of our general partner, may not be consistent with those of our public common unitholders.
Common units are subject to our general partner's call right.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by public common unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, our common unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. A common unitholder may also incur a tax liability upon a sale of its common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and then exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right.
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Our common unitholders have limited voting rights and are not entitled to elect our general partner or our general partner's directors and do not have sufficient voting power to remove our general partner without CVR Energy's consent.
Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Common unitholders have no right to elect our general partner or our general partner's board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, is chosen entirely by CVR Energy as the indirect owner of the general partner and not by our common unitholders. Unlike publicly traded corporations, we do not hold annual meetings of our common unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, even if our common unitholders are dissatisfied with the performance of our general partner, they have no practical ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished.
As of the date of this Report, CVR Energy indirectly owns approximately 66% of our common units, which means holders of common units other than CVR Energy will not be able to remove the general partner, under any circumstances, unless CVR Energy sells some of the common units that it owns or we sell additional units to the public. In addition, affiliates of IEP own approximately 3.9% of our common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).
Our partnership agreement restricts common unitholders' voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to our common unitholders.
Prior to making any distribution on our outstanding common units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, our pro rata portion of management compensation and overhead charged by CVR Energy in accordance with our services agreement. The services agreement does not contain any cap on the amount we may be required to pay pursuant to this agreement. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make distributions to the holders of our common units.
Common unitholders may have liability to repay distributions.
In the event that: (i) we make distributions to our common unitholders when our nonrecourse liabilities exceed the sum of (a) the fair market value of our assets not subject to recourse liability and (b) the excess of the fair market value of our assets subject to recourse liability over such liability, or a distribution causes such a result, and (ii) a common unitholder knows at the time of the distribution of such circumstances, such common unitholder will be liable for a period of three years from the time of the impermissible distribution to repay the distribution under Section 17-607 of the Delaware Act.
Likewise, upon the winding up of the partnership, in the event that (a) we do not distribute assets in the following order: (i) to creditors in satisfaction of their liabilities; (ii) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (iii) to partners for the return of their contribution; and finally (iv) to the partners in the proportions in which the partners share in distributions and (b) a common unitholder knows at the time of such circumstances, then such common unitholder will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-807 of the Delaware Act.
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Our general partner's interest in us and the control of our general partner may be transferred to a third party without common unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our common unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owners of our general partner to transfer their equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and the officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner.
If control of our general partner were transferred to an unrelated third party, the new owner of the general partner would have no interest in CVR Energy. We rely substantially on the senior management team of CVR Energy and have entered into a number of significant agreements with CVR Energy, including a services agreement pursuant to which CVR Energy provides us with the services of its senior management team. If our general partner were no longer controlled by CVR Energy, CVR Energy could be more likely to terminate the services agreement which it may do upon 180 days' notice.
Mr. Carl C. Icahn exerts significant influence over the Partnership and his interests may conflict with the interests of the Partnership's public common unitholders.
CVR Energy indirectly owns our general partner and approximately 66% of our common units. CVR Energy has the right to appoint and replace all of the members of the board of directors of our general partner at any time.
Mr. Carl C. Icahn indirectly controls approximately 82% of the voting power of CVR Energy's capital stock and, by virtue of such stock ownership in CVR Energy, is able to elect and appoint all of the directors of CVR Energy. This gives Mr. Icahn the ability to control and exert substantial influence over CVR Energy. As a result of such control of CVR Energy, he is able to control the Partnership, including:
• | business strategy and policies; |
• | mergers or other business combinations; |
• | the acquisition or disposition of assets; |
• | future issuances of common units or other securities; |
• | incurrence of debt or obtaining other sources of financing; and |
• | the Partnership's distribution policy and the payment of distributions on the Partnership's common units. |
CVR Energy provides us with the services of its senior management team as well as accounting, legal, finance and other key back-office and mid-office personnel pursuant to a services agreement which it can terminate at any time subject to a 180-day notice period. We cannot predict whether CVR Energy will terminate the services agreement and, if so, what the economic effect of termination would be. CVR Energy also has the right under our partnership agreement to sell our general partner at any time to a third party, who would be able to replace our entire board of directors. Finally, while CVR Energy currently owns the majority of our common units, its current owners are under no obligation to maintain their ownership interest in us, which could have a material adverse effect on us.
Mr. Icahn's interests may not always be consistent with the Partnership's interests or with the interests of the Partnership's public common unitholders. Mr. Icahn and entities controlled by him may also pursue acquisitions or business opportunities in industries in which we compete, and there is no requirement that any additional business opportunities be presented to us. We also have and may in the future enter into transactions to purchase goods or services with affiliates of Mr. Icahn. To the extent that conflicts of interest may arise between the Partnership and Mr. Icahn and his affiliates, those conflicts may be resolved in a manner adverse to the Partnership or its public common unitholders.
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We may issue additional common units and other equity interests without the approval of our unitholders, which would dilute the existing ownership interests of our common unitholders.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
• | the proportionate ownership interest of common unitholders immediately prior to the issuance will decrease; |
• | the amount of cash distributions on each common unit will decrease; |
• | the ratio of our taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding common unit will be diminished; and |
• | the market price of the common units may decline. |
In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.
Units eligible for future sale may cause the price of our common units to decline.
Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. This could also impair our ability to raise additional capital through the sale of our equity interests. As of the date of this Report, there were 147,600,000 common units outstanding. Of this amount, CVR Energy indirectly owns approximately 66% of our common units and public security holders own approximately 34% of our common units.
In addition, under our partnership agreement, our general partner and its affiliates have the right to cause us to register their units under the Securities Act and applicable state securities laws. In connection with our initial public offering, we entered into a registration rights agreement with an affiliate of IEP, CVR Refining Holdings and CVR Refining Holdings Sub, LLC, pursuant to which we may be required to register the sale of the common units they hold under the Securities Act and applicable state securities laws. Alternatively, we may be required to undertake a future public or private offering of common units and use the net proceeds from such offering to redeem an equal number of common units held by an affiliate of IEP, CVR Refining Holdings or CVR Refining Holdings Sub, LLC.
As a publicly traded partnership we qualify for, and are relying on, certain exemptions from the NYSE's corporate governance requirements.
As a publicly traded partnership, we qualify for, and are relying on, certain exemptions from the NYSE's corporate governance requirements, including:
• | the requirement that a majority of the board of directors of our general partner consist of independent directors; |
• | 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 |
• | the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors. |
Our general partner's board of directors has not established and does not currently intend to establish a nominating/corporate governance committee. Additionally, we could avail ourselves of the additional exemptions available to publicly traded partnerships listed above at any time in the future. Accordingly, common unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.
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Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation. If the Internal Revenue Service ("IRS") were to treat us as a corporation for U.S. federal income tax purposes, or we become subject to entity-level taxation for state tax purposes, our cash available for distribution to our common unitholders would be substantially reduced, likely causing a substantial reduction in the value of our common units.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested from the IRS regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our common unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. We currently own assets and conduct business in several states, many of which impose a margin or franchise tax. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distributions to our common unitholders.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.
However, any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be adopted or enacted. Any similar or future legislative or administrative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
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If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in our cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such common unitholders' behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our common unitholders and former common unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current common unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such common unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such common unitholders behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Even if common unitholders do not receive any cash distributions from us, common unitholders will be required to pay taxes on their share of our taxable income, including their share of income from the cancellation of debt.
Our common unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in "cancellation of indebtedness income" being allocated to our common unitholders as taxable income without any increase in our cash available for distribution. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If a common unitholder sells common units, the common unitholder will recognize a gain or loss equal to the difference between the amount realized and that common unitholder's tax basis in those common units. Because distributions in excess of a common unitholder's allocable share of our net taxable income decrease such common unitholder's tax basis in its common units, the amount, if any, of such prior excess distributions with respect to the common units a common unitholder sells will, in effect, become taxable income to a common unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price such common unitholder receives is less than its original cost for such common units. In addition, because the amount realized includes a common unitholder's share of our nonrecourse liabilities, if a common unitholder sells its common units, a common unitholder may incur a tax liability in excess of the amount of cash received from the sale.
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A substantial portion of the amount realized from a common unitholder’s sale of our common units, whether or not representing gain, may be taxed as ordinary income to such common unitholder due to potential recapture items, including depreciation recapture. Thus, a common unitholder may recognize both ordinary income and capital loss from the sale of common units if the amount realized on a sale of such common units is less than such common unitholder’s adjusted basis in the common units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a common unitholder sells its common units, such common unitholder may recognize ordinary income from our allocations of income and gain to such common unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of common units.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. Common Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.
Non-U.S. common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our common unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our common unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a common unitholder's tax returns.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our common unitholders.
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We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our common unitholders.
A common unitholder whose common units are the subject of a securities loan (e.g., a loan to a "short seller" to cover a short sale of common units) may be considered to have disposed of those common units. If so, such common unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a common unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the common unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the common unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
Our common unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, our common unitholders may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our common unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements.
We currently own assets and/or conduct business in the states of Arkansas, Colorado, Iowa, Kansas, Missouri, Nebraska, Oklahoma, Texas and South Dakota. These states, other than Texas and South Dakota, currently impose a personal income tax on individuals. These states, other than South Dakota, also impose income taxes on corporations and other entities. Common unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, common unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is our common unitholders' responsibility to file all United States federal, foreign, state and local income tax returns.
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Item 1B. Unresolved Staff Comments
There are no material unresolved written comments that were received from the SEC staff 180 days or more before the end of our fiscal year relating to our periodic or current reports under the Exchange Act.
Item 2. Properties
The following table contains certain information regarding our principal properties:
Location | Acres | Own/Lease | Use | |||
Coffeyville, KS | 380 | Own | Oil refinery and office buildings | |||
Wynnewood, OK | 400 | Own | Oil refinery, office buildings, refined oil storage | |||
Montgomery County, KS (Coffeyville Station) | 30 | Own | Crude oil storage | |||
Montgomery County, KS (Broome Station) | 20 | Own | Crude oil storage | |||
Cowley County, KS (Hooser Station) | 70 | Own | Crude oil storage | |||
Cushing, OK | 138 | Own | Crude oil storage | |||
Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas. We also have an administrative office in Kansas City, Kansas. The offices in Sugar Land and Kansas City are leased by CVR Energy and we will pay a pro rata share of the rent on those offices. We believe that our facilities, together with CVR Energy's leased facilities, are sufficient for our operating needs.
As of December 31, 2017, we own crude oil storage capacity of approximately (i) 1.5 million barrels supporting the gathering system and Coffeyville refinery, (ii) 0.9 million barrels at the Wynnewood refinery and (iii) 1.5 million barrels in Cushing, Oklahoma. We also lease additional crude oil storage capacity of approximately 2.3 million barrels in Cushing and 0.2 million barrels in Duncan, Oklahoma. In addition to crude oil storage, we own over 4.6 million barrels of combined refined products and feedstocks storage capacity.
We are party to a cross-easement agreement with CVR Partners so that both we and CVR Partners are able to access and utilize each other's land in Coffeyville in certain circumstances in order to operate our respective businesses in a manner to provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party's property. For more information on this cross-easement agreement, see Part III, Item 13 of this Report "Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy and CVR Partners."
Item 3. Legal Proceedings
We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described under "Business — Environmental Matters." We also incorporate by reference into this Part I, Item 3 of this Report, the information regarding the lawsuits and proceedings described and referenced in Note 12 ("Commitments and Contingencies") to our Consolidated Financial Statements as set forth in Part II, Item 8 of this Report. In accordance with accounting principles generally accepted in the United States of America ("GAAP"), we record a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common units are listed on the NYSE under the symbol "CVRR" and commenced trading on January 17, 2013. The table below sets forth, for the quarter indicated, the high and low sales prices per share of our common units for our two most recent fiscal years:
2017 | High | Low | |||||
First Quarter | $ | 12.55 | $ | 9.03 | |||
Second Quarter | 10.60 | 8.28 | |||||
Third Quarter | 10.10 | 6.70 | |||||
Fourth Quarter | 16.75 | 9.65 | |||||
2016 | High | Low | |||||
First Quarter | $ | 20.25 | $ | 10.17 | |||
Second Quarter | 13.25 | 7.33 | |||||
Third Quarter | 11.25 | 5.50 | |||||
Fourth Quarter | 11.00 | 6.45 | |||||
Holders of Record
As of February 20, 2018, there were 9 holders of record of our common units. Because many of our common units are held by brokers and other institutions on behalf of holders, we are unable to estimate the total number of beneficial owners represented by these record holders.
Cash Distribution Policy
Because our policy is to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low earnings, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in our operating performance and earnings caused by fluctuations in our refining margins. Such variations may be significant. The board of directors of our general partner may change the foregoing distribution policy at any time and the partnership agreement does not require us to make distributions at all. See Part II, Item 8, Note 9 ("Partners’ Capital and Partnership Distributions") of this Report for additional information.
On February 21, 2018, the board of directors of the Partnership's general partner declared a cash distribution for the fourth quarter of 2017 to the Partnership's unitholders of $0.45 per common unit, or $66.4 million in aggregate. The cash distribution will be paid on March 12, 2018 to unitholders of record at the close of business on March 5, 2018.
Our ability to make distributions is limited by our Amended and Restated ABL Credit Facility and the indenture governing the 2022 Notes. See Part II, Item 8, Note 8 ("Long-Term Debt") of this Report for a discussion of those limitations.
Purchases of Equity Securities by the Issuer
We did not repurchase any of our common units during the fiscal quarter ended December 31, 2017.
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Item 6. Selected Financial Data
You should read the selected historical consolidated financial data presented below in conjunction with, and the selected historical consolidated and combined financial data presented below is qualified in its entirety by reference to, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes included elsewhere in this Report.
The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the years ended December 31, 2017, 2016 and 2015 and the selected consolidated financial information presented below under the caption "Balance Sheet Data" as of December 31, 2017 and 2016 has been derived from our audited consolidated financial statements included elsewhere in this Report, which financial statements have been audited by Grant Thornton LLP, our independent registered public accounting firm. The selected consolidated financial information presented below under the captions "Statements of Operations Data" and "Cash Flow Data" for the years ended December 31, 2014 and 2013, and the selected consolidated financial information presented below under the caption "Balance Sheet Data" at December 31, 2015, 2014 and 2013 is derived from our audited consolidated financial statements that are not included in this Report.
Year Ended December 31, | |||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
(in millions, except per unit data) | |||||||||||||||||||
Statements of Operations Data | |||||||||||||||||||
Net sales | $ | 5,664.2 | $ | 4,431.3 | $ | 5,161.9 | $ | 8,829.7 | $ | 8,683.5 | |||||||||
Cost of materials and other | 4,804.7 | 3,759.2 | 4,143.6 | 8,013.4 | 7,526.7 | ||||||||||||||
Direct operating expenses(1) | 443.8 | 393.4 | 478.5 | 416.0 | 361.7 | ||||||||||||||
Flood insurance recovery | — | — | (27.3 | ) | — | — | |||||||||||||
Depreciation and amortization | 129.3 | 126.3 | 128.0 | 120.9 | 113.9 | ||||||||||||||
Cost of sales | 5,377.8 | 4,278.9 | 4,722.8 | 8,550.3 | 8,002.3 | ||||||||||||||
Selling, general and administrative expenses(1) | 78.8 | 71.9 | 75.2 | 70.6 | 77.8 | ||||||||||||||
Depreciation and amortization | 3.8 | 2.7 | 2.2 | 1.6 | 0.4 | ||||||||||||||
Operating income | 203.8 | 77.8 | 361.7 | 207.2 | 603.0 | ||||||||||||||
Interest expense and other financing costs | (47.2 | ) | (43.4 | ) | (42.6 | ) | (34.2 | ) | (44.1 | ) | |||||||||
Interest income | 0.5 | 0.1 | 0.4 | 0.3 | 0.4 | ||||||||||||||
Gain (loss) on derivatives, net | (69.8 | ) | (19.4 | ) | (28.6 | ) | 185.6 | 57.1 | |||||||||||
Loss on extinguishment of debt | — | — | — | — | (26.1 | ) | |||||||||||||
Other income (expense), net | 1.5 | 0.2 | 0.3 | (0.2 | ) | 0.1 | |||||||||||||
Income before income tax expense | 88.8 | 15.3 | 291.2 | 358.7 | 590.4 | ||||||||||||||
Income tax expense | — | — | — | — | — | ||||||||||||||
Net income | $ | 88.8 | $ | 15.3 | $ | 291.2 | $ | 358.7 | $ | 590.4 | |||||||||
Available cash for distribution(2) | $ | 204.2 | $ | 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 | $ | 0.60 | $ | 0.10 | $ | 1.97 | $ | 2.43 | $ | 3.47 | |||||||||
Weighted average common units outstanding: | |||||||||||||||||||
Basic and Diluted | 147.6 | 147.6 | 147.6 | 147.6 | 147.6 | ||||||||||||||
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Year Ended December 31, | |||||||||||||||||||
2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
(in millions) | |||||||||||||||||||
Balance Sheet Data | |||||||||||||||||||
Cash and cash equivalents | $ | 173.8 | $ | 314.1 | $ | 187.3 | $ | 370.2 | $ | 279.8 | |||||||||
Working capital | 217.5 | 313.7 | 297.5 | 503.6 | 656.0 | ||||||||||||||
Total assets | 2,269.9 | 2,331.9 | 2,189.0 | 2,410.7 | 2,525.3 | ||||||||||||||
Total debt, including current portion | 540.6 | 541.5 | 573.8 | 574.3 | 574.7 | ||||||||||||||
Total partners' capital/divisional equity | 1,246.8 | 1,296.7 | 1,281.4 | 1,450.1 | 1,522.1 | ||||||||||||||
Cash Flow Data | |||||||||||||||||||
Net cash flow provided by (used in): | |||||||||||||||||||
Operating activities | $ | 177.9 | $ | 267.8 | $ | 473.7 | $ | 715.8 | $ | 601.0 | |||||||||
Investing activities | (176.1 | ) | (107.9 | ) | (194.7 | ) | (191.2 | ) | (204.4 | ) | |||||||||
Financing activities | (142.1 | ) | (33.1 | ) | (461.9 | ) | (434.2 | ) | (269.9 | ) | |||||||||
Net increase (decrease) in cash and cash equivalents | $ | (140.3 | ) | $ | 126.8 | $ | (182.9 | ) | $ | 90.4 | $ | 126.7 | |||||||
Capital expenditures for property, plant and equipment | $ | 99.7 | $ | 102.3 | $ | 194.7 | $ | 191.3 | $ | 204.5 | |||||||||
(1) | Amounts are shown exclusive of depreciation and amortization, which amounts are presented separately below direct operating expenses and selling, general and administrative expenses. |
(2) | Available cash for distribution will generally equal 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 distribution may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Actual distributions are set by 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. 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). |
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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our consolidated financial statements and related notes included elsewhere in this Report.
Forward-Looking Statements
This Report, including, without limitation, the sections captioned "Business" and this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains "forward-looking statements" as defined by the Securities and Exchange Commission ("SEC"), including statements concerning contemplated transactions and strategic plans, expectations and objectives for future operations. Forward-looking statements include, without limitation:
• | statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future; |
• | statements relating to future financial or operational performance, future 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. |
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under the section captioned "Risk Factors" and contained elsewhere in this Report. Such factors include, among others:
• | 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 hazards 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; |
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• | 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. |
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All forward-looking statements contained in this Report only speak as of the date of this Report. We undertake no obligation to publicly update or revise any forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events, except to the extent required by law.
Overview and Executive Summary
We are an independent downstream energy limited partnership with refining and related logistics assets that operates in Group 3 of the PADD II region of the United States. We were formed by CVR Energy in September 2012 in order to own and operate petroleum and auxiliary businesses as a limited partnership. Refer to Part I, Item 1, Business, of this Report for a discussion of our business.
On January 23, 2013, we completed our initial public offering of 24,000,000 common units priced at $25.00 per unit. Of the common units issued, 4,000,000 units were purchased by an affiliate of Icahn Enterprises L.P. ("IEP"). Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units priced at $25.00 per unit. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." Immediately following the closing of the Initial Public Offering and through May 19, 2013, common units held by public security holders represented approximately 19% of all outstanding limited partner interests (including common units held by an affiliate of IEP, representing approximately 3% of all outstanding limited partner interests), while CVR Refining Holdings held common units approximating 81% of all outstanding limited partner interests in addition to owning 100% of CVR Refining GP, LLC, our general partner.
As of December 31, 2017, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 66% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership’s general partner, CVR Refining GP, which holds a non-economic general partner interest.
Major Influences on Results of Operations
Our earnings and cash flows are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in first-out ("FIFO") accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.
The prices of crude oil and other feedstocks and refined products are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. Widespread expansion or upgrades of our competitors' facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for volatile seasonal exports of diesel from the United States Gulf Coast markets. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. We are also subject to the RFS, which requires us to either blend "renewable fuels" in with our transportation fuels or purchase RINs, in lieu of blending, by March 31, 2018 or otherwise be subject to penalties.
Refer to Part I, Item 1A, Risk Factors, If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected, and Part II, Item 8, Note 12 ("Commitments and Contingencies"), "Environmental, Health and Safety ("EHS") Matters" of this Report for further discussion of the RFS.
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The cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimates related to the other variable factors, we currently estimate that the total cost of RINs will be approximately $200.0 million for the year ending December 31, 2018.
In order to assess our operating performance, we compare our net sales, less cost of materials and other, or our refining margin, against an industry refining margin benchmark. The industry refining margin benchmark is calculated by assuming that two barrels of benchmark light sweet crude oil are converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.
Although the 2-1-1 crack spread is a benchmark for our refining margin, because our refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refining margin. Our Coffeyville refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. Our Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutane, gasoline components, and normal butane are also typically used. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude oil differential. Our refining margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS price differential to WTI and the WCS price differential to WTI as both these differentials indicate the relative price of heavier, more sour, crude oil slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate. Our consumed crude oil cost discount to WTI for 2017 was $0.29 per barrel compared to consumed crude oil cost discounts of $1.58 per barrel in 2016 and $1.12 per barrel in 2015.
We produce a high volume of high value products, such as gasoline and distillates. The fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refineries is because the prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra-Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra-Low Sulfur Diesel basis. If both gasoline and Ultra-Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.
We are significantly affected by developments in the markets in which we operate. For example, numerous pipeline expansions in recent years expanding the connectivity of Cushing and Permian Basin markets to the gulf coast along with lifting the crude oil export ban has resulted in a decrease in the domestic crude advantage. The refining industry is directly impacted by these events and has seen a downward movement in refining margins as a result. The stabilization of oil prices led by OPEC's decision to lower production volumes and the resurgent shale drilling in the Permian and other tight oil plays are expected to cause price spread volatility as the industry attempts to match infrastructure to supply.
Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the year ended December 31, 2017, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $12.3 million.
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Because crude oil and other feedstocks and refined products are commodities, we have no control over the changing market. Therefore, the lower target inventory we are able to maintain significantly reduces the impact of commodity price volatility on our petroleum product inventory position relative to other refiners. Our target inventory position is generally not hedged. To the extent our inventory position deviates from the target level, we consider risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Our hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on our financial results from period to period.
Safe and reliable operations at our refineries are key to our financial performance and results of operations. Unscheduled downtime at our refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of scheduled downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. Our refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The first phase of the Coffeyville refinery's most recent turnaround was completed in November 2015 at a total cost of approximately $102.2 million. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016 at a total cost of approximately $31.5 million. The next turnaround scheduled for the Wynnewood refinery is being performed as a two-phase turnaround. The first phase of its current turnaround was completed in November 2017 at a total cost of approximately $67.4 million. The second phase of the Wynnewood turnaround is expected to occur in 2019. Turnaround expenses associated with the second phase of the Wynnewood turnaround are estimated to be approximately $25.0 million. In addition to the two phase turnaround, we accelerated certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. We incurred approximately $13.0 million of major scheduled turnaround expenses for the hydrocracker.
Agreements with Affiliates
CVR Energy and its subsidiaries are party to several agreements with CVR Partners and its subsidiary that govern the business relations among CVR Partners, CVR Energy and their subsidiaries and affiliates, and the general partner of CVR Partners. In connection with our Initial Public Offering in January 2013, some of the subsidiaries party to these agreements became subsidiaries of CVR Refining.
These intercompany agreements include (i) the pet coke supply agreement under which CVR Partners purchases the pet coke we generate at our Coffeyville refinery for use in CVR Partners' manufacture of nitrogen fertilizer; (ii) a feedstock and shared services agreement, which governs the provision of feedstocks, including, but not limited to, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iii) a raw water and facilities sharing agreement, which allocates raw water resources between the Coffeyville refinery and the nitrogen fertilizer plant; (iv) a lease agreement, pursuant to which we lease office and laboratory space to CVR Partners; (v) a cross-easement agreement, which grants easements to both parties for operational facilities, pipelines, equipment, access, and water rights; (vi) a hydrogen purchase and sale agreement; and (vii) an environmental agreement which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville refinery and the nitrogen fertilizer plant. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties. Refer to Part II, Item 8, Note 15 ("Related Party Transactions") for additional information.
Joint Ventures
Refer to Part II, Item 8, Note 6 ("Equity Method Investments") of this Report for additional information.
Crude Oil Supply Agreement
Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies") of this Report for information on the crude oil supply agreement.
46
Factors Affecting Comparability
Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons presented and discussed below.
Year Ended December 31, | |||||||||
2017 | 2016 | 2015 | |||||||
(in millions) | |||||||||
Loss on derivatives, net | 69.8 | 19.4 | 28.6 | ||||||
Major scheduled turnaround expenses(1) | 80.4 | 31.5 | 102.2 | ||||||
Flood insurance recovery(2) | — | — | (27.3 | ) | |||||
_______________________________________
(1) | Represents expense associated with major scheduled turnaround activities performed at our Coffeyville and Wynnewood refineries. |
(2) | Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery in June/July 2007. Refer to Part II, Item 8, Note 12 ("Commitments and Contingencies"), of this Report for further details. |
Distributions to CVR Refining Unitholders
Refer to Part II, Item 8, Note 9 ("Partners’ Capital and Partnership Distributions") of this Report for a summary of our distribution policy and the cash distributions paid to our unitholders during years ended December 31, 2017 and 2016.
47
Results of Operations
The period to period comparisons of our results of operations have been prepared using the historical periods included in our consolidated financial statements. The following tables below provide an overview of our results of operations, relevant market indicators and key operating statistics for the years ended December 31, 2017, 2016 and 2015.
Net sales consist principally of sales of refined fuel, and are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, versus lower value finished products, such as pet coke.
Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See " — Major Influences on Results of Operations." We discuss our results of petroleum operations in the context of per barrel consumed crack spreads and the relationship between net sales and cost of materials and other. Refining margin is a measurement calculated as the difference between net sales and cost of materials and other.
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Consolidated Statements of Operations Data | |||||||||||
Net sales | $ | 5,664.2 | $ | 4,431.3 | $ | 5,161.9 | |||||
Operating costs and expenses: | |||||||||||
Cost of materials and other | 4,804.7 | 3,759.2 | 4,143.6 | ||||||||
Direct operating expenses(1)(2) | 363.4 | 361.9 | 376.3 | ||||||||
Major scheduled turnaround expenses | 80.4 | 31.5 | 102.2 | ||||||||
Depreciation and amortization | 129.3 | 126.3 | 128.0 | ||||||||
Cost of sales | 5,377.8 | 4,278.9 | 4,750.1 | ||||||||
Flood insurance recovery | — | — | (27.3 | ) | |||||||
Selling, general and administrative expenses(1) | 78.8 | 71.9 | 75.2 | ||||||||
Depreciation and amortization | 3.8 | 2.7 | 2.2 | ||||||||
Operating income | 203.8 | 77.8 | 361.7 | ||||||||
Interest expense and other financing costs | (47.2 | ) | (43.4 | ) | (42.6 | ) | |||||
Interest income | 0.5 | 0.1 | 0.4 | ||||||||
Loss on derivatives, net | (69.8 | ) | (19.4 | ) | (28.6 | ) | |||||
Other income, net | 1.5 | 0.2 | 0.3 | ||||||||
Income before income tax expense | 88.8 | 15.3 | 291.2 | ||||||||
Income tax expense | — | — | — | ||||||||
Net income | $ | 88.8 | $ | 15.3 | $ | 291.2 | |||||
Gross profit(3) | $ | 286.4 | $ | 152.4 | $ | 439.1 | |||||
Refining margin(4) | $ | 859.5 | $ | 672.1 | $ | 1,018.3 | |||||
Adjusted EBITDA(5) | $ | 372.6 | $ | 222.8 | $ | 602.0 | |||||
Available cash for distribution(6) | $ | 204.2 | $ | 0.3 | $ | 402.0 | |||||
48
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(dollars per barrel) | |||||||||||
Key Operating Statistics | |||||||||||
Per crude oil throughput barrel: | |||||||||||
Gross profit(3) | $ | 3.83 | $ | 2.10 | $ | 6.23 | |||||
Refining margin(4) | 11.50 | 9.27 | 14.45 | ||||||||
FIFO impact, (favorable) unfavorable | (0.40 | ) | (0.72 | ) | 0.86 | ||||||
Refining margin adjusted for FIFO impact(4) | 11.10 | 8.55 | 15.31 | ||||||||
Direct operating expenses and major scheduled turnaround expenses(1)(2) | 5.94 | 5.43 | 6.79 | ||||||||
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(7) | $ | 5.55 | $ | 5.08 | $ | 6.40 | |||||
Barrels sold (barrels per day)(7) | 218,912 | 211,643 | 204,708 | ||||||||
Year Ended December 31, | |||||||||||||||||
2017 | 2016 | 2015 | |||||||||||||||
% | % | % | |||||||||||||||
Refining Throughput and Production Data (bpd) | |||||||||||||||||
Throughput: | |||||||||||||||||
Sweet | 194,613 | 89.8 | 177,256 | 84.8 | 176,097 | 86.0 | |||||||||||
Medium | — | — | 2,525 | 1.2 | 2,460 | 1.2 | |||||||||||
Heavy sour | 10,135 | 4.7 | 18,261 | 8.7 | 14,520 | 7.1 | |||||||||||
Total crude oil throughput | 204,748 | 94.5 | 198,042 | 94.7 | 193,077 | 94.3 | |||||||||||
All other feedstocks and blendstocks | 12,032 | 5.5 | 11,077 | 5.3 | 11,672 | 5.7 | |||||||||||
Total throughput | 216,780 | 100.0 | 209,119 | 100.0 | 204,749 | 100.0 | |||||||||||
Production: | |||||||||||||||||
Gasoline | 110,226 | 50.7 | 108,762 | 51.9 | 99,961 | 48.5 | |||||||||||
Distillate | 90,409 | 41.6 | 85,092 | 40.6 | 85,953 | 41.7 | |||||||||||
Other (excluding internally produced fuel) | 16,818 | 7.7 | 15,751 | 7.5 | 20,074 | 9.8 | |||||||||||
Total refining production (excluding internally produced fuel) | 217,453 | 100.0 | 209,605 | 100.0 | 205,988 | 100.0 | |||||||||||
Product price (dollars per gallon): | |||||||||||||||||
Gasoline | $ | 1.59 | $ | 1.34 | $ | 1.61 | |||||||||||
Distillate | 1.66 | 1.36 | 1.62 | ||||||||||||||
49
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
Market Indicators (dollars per barrel) | |||||||||||
West Texas Intermediate (WTI) NYMEX | $ | 50.85 | $ | 43.47 | $ | 48.76 | |||||
Crude Oil Differentials: | |||||||||||
WTI less WTS (light/medium sour) | 0.97 | 0.85 | (0.28 | ) | |||||||
WTI less WCS (heavy sour) | 12.69 | 13.95 | 13.20 | ||||||||
NYMEX Crack Spreads: | |||||||||||
Gasoline | 17.46 | 15.42 | 19.89 | ||||||||
Heating Oil | 18.93 | 13.89 | 20.93 | ||||||||
NYMEX 2-1-1 Crack Spread | 18.19 | 14.66 | 20.41 | ||||||||
PADD II Group 3 Product Basis: | |||||||||||
Gasoline | (1.83 | ) | (3.62 | ) | (2.12 | ) | |||||
Ultra Low Sulfur Diesel | (0.50 | ) | (0.92 | ) | (2.02 | ) | |||||
PADD II Group 3 Product Crack Spread: | |||||||||||
Gasoline | 15.63 | 11.82 | 17.76 | ||||||||
Ultra Low Sulfur Diesel | 18.42 | 12.96 | 18.91 | ||||||||
PADD II Group 3 2-1-1 | 17.03 | 12.39 | 18.34 | ||||||||
(1) | Amounts are shown exclusive of depreciation and amortization. |
(2) | Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which do not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period. |
(3) | Gross profit, a GAAP measure, is calculated as the difference between net sales and cost of materials and other, direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses, flood insurance recovery and depreciation and amortization. Each of the components used in this calculation are taken directly from 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 our refineries' performance 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 are 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. |
50
Refining margin per crude oil throughput barrel adjusted for FIFO impact is a measurement calculated as the difference between net sales and cost of materials and other adjusted for FIFO impact. Refining margin adjusted for FIFO impact is a non-GAAP measure that we believe is important to investors in evaluating our refineries’ performance as a general indication of the amount above our cost of materials and other (taking into account the impact of our utilization of FIFO) at which we are able to sell refined products. Our calculation of refining margin adjusted for FIFO impact may differ from calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. In order to derive the refining margin per crude oil throughput barrel adjusted for FIFO impact, we utilize the total dollar figures for refining margin adjusted for FIFO impact as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin adjusted for FIFO impact and refining margin per crude oil throughput barrel adjusted for FIFO impact are important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.
The calculation of refining margin, refining margin adjusted for FIFO impact, refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel (each a non-GAAP financial measure), including a reconciliation to the most directly comparable GAAP financial measure for the years ended December 31, 2017, 2016 and 2015 is as follows:
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Net sales | $ | 5,664.2 | $ | 4,431.3 | $ | 5,161.9 | |||||
Cost of materials and other | 4,804.7 | 3,759.2 | 4,143.6 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 363.4 | 361.9 | 376.3 | ||||||||
Major scheduled turnaround expenses | 80.4 | 31.5 | 102.2 | ||||||||
Flood insurance recovery | — | — | (27.3 | ) | |||||||
Depreciation and amortization | 129.3 | 126.3 | 128.0 | ||||||||
Gross profit | 286.4 | 152.4 | 439.1 | ||||||||
Add: | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 363.4 | 361.9 | 376.3 | ||||||||
Major scheduled turnaround expenses | 80.4 | 31.5 | 102.2 | ||||||||
Flood insurance recovery | — | — | (27.3 | ) | |||||||
Depreciation and amortization | 129.3 | 126.3 | 128.0 | ||||||||
Refining margin | 859.5 | 672.1 | 1,018.3 | ||||||||
FIFO impact, (favorable) unfavorable | (29.6 | ) | (52.1 | ) | 60.3 | ||||||
Refining margin adjusted for FIFO impact | $ | 829.9 | $ | 620.0 | $ | 1,078.6 | |||||
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Total crude oil throughput barrels per day | 204,748 | 198,042 | 193,077 | |||||
Days in the period | 365 | 366 | 365 | |||||
Total crude oil throughput barrels | 74,733,020 | 72,483,372 | 70,473,105 | |||||
51
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except for $ per barrel data) | |||||||||||
Refining margin | $ | 859.5 | $ | 672.1 | $ | 1,018.3 | |||||
Divided by: crude oil throughput barrels | 74.7 | 72.5 | 70.5 | ||||||||
Refining margin per crude oil throughput barrel | $ | 11.50 | $ | 9.27 | $ | 14.45 | |||||
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except for $ per barrel data) | |||||||||||
Refining margin adjusted for FIFO impact | $ | 829.9 | $ | 620.0 | $ | 1,078.6 | |||||
Divided by: crude oil throughput barrels | 74.7 | 72.5 | 70.5 | ||||||||
Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 11.10 | $ | 8.55 | $ | 15.31 | |||||
(5) | 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 Adjusted EBITDA); (v) (gain) loss on derivatives, net; (vi) current period settlements on derivative contracts; and (vii) flood insurance recovery. |
We present Adjusted EBITDA because it is the starting point for our determination of available cash for distribution. EBITDA and Adjusted EBITDA are not recognized terms under GAAP and should not be substituted for net income (loss) or cash flow from operations. We believe that EBITDA and Adjusted EBITDA enable investors to better understand our ability to make distributions to our common unitholders, help investors evaluate our ongoing operating results and allow for greater transparency in reviewing our overall financial, operational and economic performance. EBITDA and Adjusted EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently.
52
Below is a reconciliation of net income to EBITDA and EBITDA to Adjusted EBITDA for the three months ended December 31, 2017 and the years ended December 31, 2017, 2016 and 2015:
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
2017 | 2017 | 2016 | 2015 | ||||||||||||
(in millions) | |||||||||||||||
(unaudited) | |||||||||||||||
Net income (loss) | $ | (29.0 | ) | $ | 88.8 | $ | 15.3 | $ | 291.2 | ||||||
Add: | |||||||||||||||
Interest expense and other financing costs, net of interest income | 11.9 | 46.7 | 43.3 | 42.2 | |||||||||||
Income tax expense | — | — | — | — | |||||||||||
Depreciation and amortization | 33.6 | 133.1 | 129.0 | 130.2 | |||||||||||
EBITDA | 16.5 | 268.6 | 187.6 | 463.6 | |||||||||||
Add: | |||||||||||||||
FIFO impact, (favorable) unfavorable(a) | (30.4 | ) | (29.6 | ) | (52.1 | ) | 60.3 | ||||||||
Share-based compensation, non-cash | — | — | — | 0.6 | |||||||||||
Major scheduled turnaround expenses(b) | 43.0 | 80.4 | 31.5 | 102.2 | |||||||||||
Loss on derivatives, net | 65.0 | 69.8 | 19.4 | 28.6 | |||||||||||
Current period settlements on derivative contracts(c) | (17.7 | ) | (16.6 | ) | 36.4 | (26.0 | ) | ||||||||
Flood insurance recovery(d) | — | — | — | (27.3 | ) | ||||||||||
Adjusted EBITDA | $ | 76.4 | $ | 372.6 | $ | 222.8 | $ | 602.0 | |||||||
(a) | FIFO is our basis for determining inventory value under GAAP. 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 at the Coffeyville and Wynnewood refineries. |
(c) | Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts. |
(d) | Represents an insurance recovery from CRRM's environmental insurance carriers as a result of the flood and crude oil discharge at the Coffeyville refinery in June/July 2007. Refer to Part II, Item 8, Note 12 ("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 the release of 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. |
53
A reconciliation of Adjusted EBITDA to Available cash for distribution for the three months and year ended December 31, 2017 is as follows:
Three Months Ended December 31, 2017 | Year Ended December 31, 2017 | |||||||
(in millions, except per unit data) | ||||||||
Reconciliation of Adjusted EBITDA to Available cash for distribution | ||||||||
Adjusted EBITDA | $ | 76.4 | $ | 372.6 | ||||
Adjustments: | ||||||||
Less: | ||||||||
Cash needs for debt service | (10.0 | ) | (40.0 | ) | ||||
Reserves for environmental and maintenance capital expenditures | (25.0 | ) | (103.1 | ) | ||||
Reserves for major scheduled turnaround expenses | — | (45.0 | ) | |||||
Reserves for future operating needs | — | (54.5 | ) | |||||
Add: | ||||||||
Release of previously established cash reserves | 24.2 | 74.2 | ||||||
Available cash for distribution | $ | 65.6 | $ | 204.2 | ||||
Distribution declared, per common unit | $ | 0.45 | $ | 1.39 | ||||
Common units outstanding | 147.6 | 147.6 | ||||||
(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, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Coffeyville Refinery Financial Results | |||||||||||
Net sales | $ | 3,867.8 | $ | 2,948.9 | $ | 3,220.6 | |||||
Cost of materials and other | 3,285.8 | 2,513.9 | 2,626.1 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 209.5 | 196.4 | 209.1 | ||||||||
Major scheduled turnaround expenses | — | 31.5 | 102.2 | ||||||||
Flood insurance recovery | — | — | (27.3 | ) | |||||||
Depreciation and amortization | 71.5 | 69.7 | 72.1 | ||||||||
Gross profit | 301.0 | 137.4 | 238.4 | ||||||||
Plus: | |||||||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below) | 209.5 | 227.9 | 311.3 | ||||||||
Flood insurance recovery | — | — | (27.3 | ) | |||||||
Depreciation and amortization | 71.5 | 69.7 | 72.1 | ||||||||
Refining margin | 582.0 | 435.0 | 594.5 | ||||||||
FIFO impact, (favorable) unfavorable | (20.2 | ) | (37.8 | ) | 38.0 | ||||||
Refining margin adjusted for FIFO impact | $ | 561.8 | $ | 397.2 | $ | 632.5 | |||||
54
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(dollars per barrel) | |||||||||||
Coffeyville Refinery Key Operating Statistics | |||||||||||
Per crude oil throughput barrel: | |||||||||||
Gross profit | $ | 6.27 | $ | 3.03 | $ | 5.77 | |||||
Refining margin(1) | $ | 12.12 | $ | 9.57 | $ | 14.37 | |||||
FIFO impact, (favorable) unfavorable | $ | (0.42 | ) | $ | (0.83 | ) | $ | 0.92 | |||
Refining margin adjusted for FIFO impact(1) | $ | 11.70 | $ | 8.74 | $ | 15.29 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 4.36 | $ | 5.02 | $ | 7.53 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 4.00 | $ | 4.54 | $ | 6.92 | |||||
Barrels sold (barrels per day) | 143,598 | 137,047 | 123,279 | ||||||||
Year Ended December 31, | ||||||||||||||
2017 | 2016 | 2015 | ||||||||||||
% | % | % | ||||||||||||
Coffeyville Refinery Throughput and Production Data (bpd) | ||||||||||||||
Throughput: | ||||||||||||||
Sweet | 121,434 | 86.4 | 104,679 | 78.9 | 96,727 | 79.5 | ||||||||
Medium | — | — | 1,229 | 0.9 | 2,058 | 1.7 | ||||||||
Heavy sour | 10,135 | 7.2 | 18,261 | 13.8 | 14,520 | 11.9 | ||||||||
Total crude oil throughput | 131,569 | 93.6 | 124,169 | 93.6 | 113,305 | 93.1 | ||||||||
All other feedstocks and blendstocks | 9,058 | 6.4 | 8,453 | 6.4 | 8,400 | 6.9 | ||||||||
Total throughput | 140,627 | 100.0 | 132,622 | 100.0 | 121,705 | 100.0 | ||||||||
Production: | ||||||||||||||
Gasoline | 71,915 | 50.4 | 69,303 | 51.4 | 57,815 | 46.5 | ||||||||
Distillate | 59,593 | 41.7 | 55,790 | 41.4 | 53,136 | 42.7 | ||||||||
Other (excluding internally produced fuel) | 11,335 | 7.9 | 9,756 | 7.2 | 13,503 | 10.8 | ||||||||
Total refining production (excluding internally produced fuel) | 142,843 | 100.0 | 134,849 | 100.0 | 124,454 | 100.0 | ||||||||
(1) | The calculation of refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel for the years ended December 31, 2017, 2016 and 2015 is as follows: |
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Total crude oil throughput barrels per day | 131,569 | 124,169 | 113,305 | |||||
Days in the period | 365 | 366 | 365 | |||||
Total crude oil throughput barrels | 48,022,685 | 45,445,854 | 41,356,325 | |||||
55
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except for $ per barrel data) | |||||||||||
Refining margin | $ | 582.0 | $ | 435.0 | $ | 594.5 | |||||
Divided by: crude oil throughput barrels | 48.0 | 45.4 | 41.4 | ||||||||
Refining margin per crude oil throughput barrel | $ | 12.12 | $ | 9.57 | $ | 14.37 | |||||
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except for $ per barrel data) | |||||||||||
Refining margin adjusted for FIFO impact | $ | 561.8 | $ | 397.2 | $ | 632.5 | |||||
Divided by: crude oil throughput barrels | 48.0 | 45.4 | 41.4 | ||||||||
Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 11.70 | $ | 8.74 | $ | 15.29 | |||||
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Wynnewood Refinery Financial Results | |||||||||||
Net sales | $ | 1,792.1 | $ | 1,478.0 | $ | 1,936.9 | |||||
Cost of materials and other | 1,519.7 | 1,245.4 | 1,516.3 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 153.9 | 165.5 | 166.2 | ||||||||
Major scheduled turnaround expenses | 80.4 | — | — | ||||||||
Depreciation and amortization | 51.7 | 50.7 | 50.2 | ||||||||
Gross profit (loss) | (13.6 | ) | 16.4 | 204.2 | |||||||
Plus: | |||||||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization as reflected below) | 234.3 | 165.5 | 166.2 | ||||||||
Depreciation and amortization | 51.7 | 50.7 | 50.2 | ||||||||
Refining margin | 272.4 | 232.6 | 420.6 | ||||||||
FIFO impact, (favorable) unfavorable | (9.4 | ) | (14.2 | ) | 22.3 | ||||||
Refining margin adjusted for FIFO impact | $ | 263.0 | $ | 218.4 | $ | 442.9 | |||||
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Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(dollars per barrel) | |||||||||||
Wynnewood Refinery Key Operating Statistics | |||||||||||
Per crude oil throughput barrel: | |||||||||||
Gross profit (loss) | $ | (0.51 | ) | $ | 0.61 | $ | 7.01 | ||||
Refining margin(1) | $ | 10.20 | $ | 8.60 | $ | 14.44 | |||||
FIFO impact, (favorable) unfavorable | $ | (0.35 | ) | $ | (0.53 | ) | $ | 0.77 | |||
Refining margin adjusted for FIFO impact(1) | $ | 9.85 | $ | 8.07 | $ | 15.21 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 8.77 | $ | 6.12 | $ | 5.71 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 8.52 | $ | 6.06 | $ | 5.59 | |||||
Barrels sold (barrels per day) | 75,314 | 74,596 | 81,429 | ||||||||
Year Ended December 31, | ||||||||||||||
2017 | 2016 | 2015 | ||||||||||||
% | % | % | ||||||||||||
Wynnewood Refinery Throughput and Production Data (bpd) | ||||||||||||||
Throughput: | ||||||||||||||
Sweet | 73,179 | 96.1 | 72,577 | 94.9 | 79,370 | 95.6 | ||||||||
Medium | — | — | 1,296 | 1.7 | 402 | 0.5 | ||||||||
Heavy sour | — | — | — | — | — | — | ||||||||
Total crude oil throughput | 73,179 | 96.1 | 73,873 | 96.6 | 79,772 | 96.1 | ||||||||
All other feedstocks and blendstocks | 2,974 | 3.9 | 2,624 | 3.4 | 3,272 | 3.9 | ||||||||
Total throughput | 76,153 | 100.0 | 76,497 | 100.0 | 83,044 | 100.0 | ||||||||
Production: | ||||||||||||||
Gasoline | 38,311 | 51.3 | 39,459 | 52.8 | 42,146 | 51.7 | ||||||||
Distillate | 30,816 | 41.3 | 29,302 | 39.2 | 32,817 | 40.2 | ||||||||
Other (excluding internally produced fuel) | 5,483 | 7.4 | 5,995 | 8.0 | 6,571 | 8.1 | ||||||||
Total refining production (excluding internally produced fuel) | 74,610 | 100.0 | 74,756 | 100.0 | 81,534 | 100.0 | ||||||||
(1) | The calculation of refining margin per crude oil throughput barrel and refining margin adjusted for FIFO impact per crude oil throughput barrel for the years ended December 31, 2017, 2016 and 2015 is as follows: |
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Total crude oil throughput barrels per day | 73,179 | 73,873 | 79,772 | |||||
Days in the period | 365 | 366 | 365 | |||||
Total crude oil throughput barrels | 26,710,335 | 27,037,518 | 29,116,780 | |||||
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Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except for $ per barrel data) | |||||||||||
Refining margin | $ | 272.4 | $ | 232.6 | $ | 420.6 | |||||
Divided by: crude oil throughput barrels | 26.7 | 27.0 | 29.1 | ||||||||
Refining margin per crude oil throughput barrel | $ | 10.20 | $ | 8.60 | $ | 14.44 | |||||
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except for $ per barrel data) | |||||||||||
Refining margin adjusted for FIFO impact | $ | 263.0 | $ | 218.4 | $ | 442.9 | |||||
Divided by: crude oil throughput barrels | 26.7 | 27.0 | 29.1 | ||||||||
Refining margin adjusted for FIFO impact per crude oil throughput barrel | $ | 9.85 | $ | 8.07 | $ | 15.21 | |||||
Year Ended December 31, 2017 Compared to the Year Ended December 31, 2016
Net Sales. Net sales were $5,664.2 million for the year ended December 31, 2017, compared to $4,431.3 million for the year ended December 31, 2016. The increase of $1,232.9 million was largely the result of higher sales prices for our transportation fuels and by-products. Our average sales price per gallon for the year ended December 31, 2017 for gasoline of $1.59 and distillate of $1.66 increased by approximately 18.7% and 22.1%, respectively, as compared to the year ended December 31, 2016. Overall sales volume increased approximately 4.7% for the year ended December 31, 2017 compared to the year ended December 31, 2016. Sales volumes increased in 2017 as a result of 2016 volumes being significantly impacted by the second phase of major scheduled turnaround completed at our Coffeyville refinery. Also contributing to the increase in sales was an increase in products purchased for resale for the year ended December 31, 2017 as compared to the year ended December 31, 2016.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the year ended December 31, 2017 compared to the year ended December 31, 2016:
Year Ended December 31, 2017 | Year Ended December 31, 2016 | Total Variance | ||||||||||||||||||||||||||||||||||
Volume(1) | $ per barrel | Sales $(2) | Volume(1) | $ per barrel | Sales $(2) | Volume(1) | Sales $(2) | Price Variance | Volume Variance | |||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||
Gasoline | 44.3 | $ | 66.90 | $ | 2,966.8 | 42.6 | $ | 56.16 | $ | 2,390.8 | 1.7 | $ | 576.0 | $ | 476.3 | $ | 99.7 | |||||||||||||||||||
Distillate | 34.4 | $ | 69.71 | $ | 2,399.8 | 32.4 | $ | 56.99 | $ | 1,844.3 | 2.0 | $ | 555.5 | $ | 438.0 | $ | 117.5 | |||||||||||||||||||
(1) | Barrels in millions |
(2) | Sales dollars in millions |
Cost of Materials and Other. Cost of materials and other includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, RINs and transportation and distribution costs. Cost of materials and other was $4,804.7 million for the year ended December 31, 2017, compared to $3,759.2 million for the year ended December 31, 2016. The increase of $1,045.5 million was primarily the result of an increase in the cost of consumed crude and purchased products for resale. The increase in consumed crude oil cost was due to an increase in crude oil prices. The WTI benchmark crude oil price increased approximately 17.0% for the year ended December 31, 2017 as compared to the year ended December 31, 2016. Our average cost per barrel of crude oil consumed for the year ended December 31, 2017 was $50.63 compared to $41.99 for the year ended December 31, 2016, an increase of approximately 20.6%. Our crude oil throughput volume increased by approximately 3.1% for the year ended December 31, 2017 as compared to the equivalent period in 2016 due primarily to the major scheduled turnaround completed at our Coffeyville refinery in the first quarter of 2016. Sales volumes of refined fuels increased by approximately 4.7% during the same period.
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The impact of FIFO accounting also impacted cost of materials and other during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the years ended December 31, 2017 and 2016, we had a favorable FIFO inventory impact of $29.6 million compared to a favorable FIFO inventory impact of $52.1 million, respectively.
Refining margin per barrel of crude oil throughput increased to $11.50 for the year ended December 31, 2017 from $9.27 for the year ended December 31, 2016. Refining margin adjusted for FIFO impact was $11.10 per crude oil throughput barrel for the year ended December 31, 2017, as compared to $8.55 per crude oil throughput barrel for the year ended December 31, 2016. Gross profit per barrel increased to $3.83 for the year ended December 31, 2017, as compared to gross profit per barrel of $2.10 in the equivalent period in 2016. The increase in refining margin and gross profit per barrel was primarily due to the improvement in product margins. The benchmark 2-1-1 crack spread improved to $18.19 per barrel for the year ended December 31, 2017 from $14.66 per barrel for the year ended December 31, 2016. Also contributing to increase in refining margin and gross profit per barrel was the improvement in the Group 3 gasoline basis to NYMEX gasoline to ($1.83) per barrel for the year ended December 31, 2017 as compared to ($3.62) per barrel in the comparable period in 2016.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) include costs associated with the operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $443.8 million for the year ended December 31, 2017, compared to direct operating expenses and major scheduled turnaround expenses of $393.4 million for the year ended December 31, 2016. The increase of $50.4 million was the result of higher costs for the first phase of major scheduled turnaround activities performed at our Wynnewood refinery in 2017 as compared to the second phase of major scheduled turnaround activities completed at our Coffeyville refinery in 2016 ($48.9 million) and higher utilities costs ($8.4 million). These increases were partially offset by a decrease in repair and maintenance costs ($7.1 million). Utilities costs increased primarily due to a 28.1% increase in our natural gas cost per MMBTU and a 15.3% increase in our electricity cost per KWH. Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2017 increased to $5.94 per barrel as compared to $5.43 per barrel for the year ended December 31, 2016. The increase in the direct operating expenses per barrel of crude oil throughput was primarily a function of higher overall expenses.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business, as well as certain expenses incurred on our behalf by CVR Energy and CRLLC and billed or allocated to us. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $78.8 million for the year ended December 31, 2017, as compared to $71.9 million for the year ended December 31, 2016. The increase of $6.9 million over the comparable period was primarily due to an increase in share-based compensation expense as a result of higher unit prices of CVR Refining in 2017.
Operating Income. Operating income was $203.8 million for the year ended December 31, 2017, as compared to operating income of $77.8 million for the year ended December 31, 2016. The increase of $126.0 million was the result of an increase in refining margin ($187.4 million) due to higher sales prices for our transportation fuels and by-products which was partially offset by increases in direct operating expenses ($50.4 million), depreciation and amortization ($4.1 million) and selling, general and administrative expenses ($6.9 million).
Interest Expense. Interest expense for the year ended December 31, 2017 was $47.2 million as compared to interest expense of $43.4 million for the year ended December 31, 2016. The increase of $3.8 million resulted primarily from increased LIBOR rates for the year ended December 31, 2017 as compared to the year ended December 31, 2016.
Loss on Derivatives, net. For the year ended December 31, 2017, we recorded a $69.8 million net loss on derivatives compared to a $19.4 million net loss on derivatives for the year ended December 31, 2016. This change was primarily due to an increase in open derivative positions to 14.3 million barrels as of December 31, 2017 as compared to 4.0 million barrels as of December 31, 2016 and changes in the benchmark 2-1-1 crack spread, which resulted in a $38.3 million net loss. We enter into commodity hedging instruments in order to fix the price on a portion of our future crude oil purchases and to fix the margin on a portion of future production. In addition, we had open forward purchase and sale commitments of 5.8 million barrels of Canadian crude oil priced at fixed differentials, which resulted in a $26.0 million unrealized net loss as of December 31, 2017.
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Year Ended December 31, 2016 Compared to the Year Ended December 31, 2015
Net Sales. Net sales were $4,431.3 million for the year ended December 31, 2016, compared to $5,161.9 million for the year ended December 31, 2015. The decrease of $730.6 million was largely the result of lower sales prices for our transportation fuels and by-products. Our average sales price per gallon for the year ended December 31, 2016 for gasoline of $1.34 and distillate of $1.36 decreased by approximately 16.8% and 16.0%, respectively, as compared to the year ended December 31, 2015. Overall sales volume increased approximately 2.3% for the year ended December 31, 2016 compared to the year ended December 31, 2015. Sales volumes for 2015 were more significantly impacted by decreased production as a result of the first phase of major scheduled turnaround completed at our Coffeyville refinery in the fourth quarter of 2015 than the second phase of major scheduled turnaround completed at our Coffeyville refinery in the first quarter of 2016.
The following table demonstrates the impact of changes in sales volumes and sales prices for gasoline and distillates for the year ended December 31, 2016 compared to the year ended December 31, 2015:
Year Ended December 31, 2016 | Year Ended December 31, 2015 | Total Variance | ||||||||||||||||||||||||||||||||||
Volume(1) | $ per barrel | Sales $(2) | Volume(1) | $ per barrel | Sales $(2) | Volume(1) | Sales $(2) | Price Variance | Volume Variance | |||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||
Gasoline | 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 |
Cost of Materials and Other. Cost of materials and other was $3,759.2 million for the year ended December 31, 2016, compared to $4,143.6 million for the year ended December 31, 2015. The decrease of $384.4 million was primarily the result of a decrease in the cost of consumed crude and purchased products for resale. The decrease in consumed crude oil cost was due to a decrease in crude oil prices. The WTI benchmark crude oil price decreased approximately 10.8% for the year ended December 31, 2016 as compared to the year ended December 31, 2015. Our average cost per barrel of crude oil consumed for the year ended December 31, 2016 was $41.99 compared to $47.86 for the year ended December 31, 2015, a decrease of approximately 12.3%. Our crude oil throughput volume increased by approximately 2.9% for the year ended December 31, 2016 as compared to the equivalent period in 2015 due primarily to the major scheduled turnaround completed at our Coffeyville refinery in the fourth quarter of 2015. Sales volumes of refined fuels increased by approximately 2.3% during the same period.
The impact of FIFO accounting also impacted cost of materials and other during the comparable periods. Under the FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the years ended December 31, 2016 and 2015, we had a favorable FIFO inventory impact of $52.1 million compared to an unfavorable FIFO inventory impact of $60.3 million, respectively.
Refining margin per barrel of crude oil throughput decreased to $9.27 for the year ended December 31, 2016 from $14.45 for the year ended December 31, 2015. Refining margin adjusted for FIFO impact was $8.55 per crude oil throughput barrel for the year ended December 31, 2016, as compared to $15.31 per crude oil throughput barrel for the year ended December 31, 2015. Gross profit per barrel decreased to $2.10 for the year ended December 31, 2016, as compared to gross profit per barrel of $6.23 in the equivalent period in 2015. The decrease in refining margin and gross profit per barrel was primarily due to the decline in product margins. The benchmark 2-1-1 crack spread declined to $14.66 per barrel for the year ended December 31, 2016 from $20.41 per barrel for the year ended December 31, 2015.
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Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) were $393.4 million for the year ended December 31, 2016, compared to direct operating expenses and major scheduled turnaround expenses of $478.5 million for the year ended December 31, 2015. The decrease of $85.1 million was the result of lower costs for the second phase of major scheduled turnaround activities performed at our Coffeyville refinery in 2016 as compared to the first phase completed in 2015 ($70.7 million), lower insurance expense ($4.5 million), environmental expense ($4.3 million), production chemicals ($3.1 million), repair and maintenance costs ($2.4 million), outside services ($2.3 million) and allocated shared services expenses ($2.2 million). These decreases were partially offset by an increase in labor costs ($4.0 million). Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2016 decreased to $5.43 per barrel as compared to $6.79 per barrel for the year ended December 31, 2015. The decrease in the direct operating expenses per barrel of crude oil throughput was primarily a function of lower overall expenses.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses (exclusive of depreciation and amortization) were $71.9 million for the year ended December 31, 2016, as compared to $75.2 million for the year ended December 31, 2015. The decrease of $3.3 million over the comparable period was primarily the result of lower personnel costs and IT-related costs, partially offset by higher legal costs.
Operating Income. Operating income was $77.8 million for the year ended December 31, 2016, as compared to operating income of $361.7 million for the year ended December 31, 2015. The decrease of $283.9 million was the result of a decrease in the refining margin ($346.2 million) and the 2015 flood insurance recovery ($27.3 million), partially offset by decreases in direct operating expenses ($85.1 million), depreciation and amortization (1.2 million) and selling, general and administrative expenses ($3.3 million).
Interest Expense. Interest expense for the year ended December 31, 2016 was $43.4 million as compared to interest expense of $42.6 million for the year ended December 31, 2015. The increase of $0.8 million resulted primarily from increased LIBOR rates for the year ended December 31, 2016 as compared to the year ended December 31, 2015.
Gain (Loss) on Derivatives, net. For the year ended December 31, 2016, we recorded a $19.4 million net loss on derivatives compared to a $28.6 million net loss on derivatives for the year ended December 31, 2015. The change was primarily due to changes in crack spreads during the periods. We enter into over-the-counter commodity swap contracts to fix the margin on a portion of our future gasoline and distillate production.
Liquidity and Capital Resources
Our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations and paying distributions to our unitholders, as discussed further below. We believe that our cash flows from operations and existing cash and cash equivalents, along with borrowings, as necessary, under the Amended and Restated ABL Credit Facility and the $150.0 million intercompany credit facility, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next 12 months. However, future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control. Please read "— Capital Spending" for a further discussion of the impact on liquidity.
Our general partner's current policy is to distribute an amount equal to the available cash we generate each quarter to our unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance our growth externally, the growth in our business, and our liquidity, may be negatively impacted.
Cash Balance and Other Liquidity
As of December 31, 2017, we had cash and cash equivalents of $173.8 million. Working capital at December 31, 2017 was $217.5 million, consisting of $699.8 million in current assets and $482.3 million in current liabilities. Working capital at December 31, 2016 was $313.7 million, consisting of $803.6 million in current assets and $489.9 million in current liabilities. Additionally, as of February 20, 2018, we had cash and cash equivalents of approximately $186.0 million.
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Borrowing Activities
2022 Notes. The Partnerhsip's $500.0 million aggregate principal amount of 6.5% Second Lien Senior Notes due 2022 are unsecured and fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries (other than the co-issuer, Coffeyville Finance) on a joint and several basis.
The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, to holders of record at the close of business on April 15 and October 15, as the case may be, immediately preceding each such interest payment date.
We have the right to redeem the 2022 Notes at a redemption price of (i) 103.250% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2017; (ii) 102.167% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2018; (iii) 101.083% of the principal amount thereof, if redeemed during the twelve-month period beginning on November 1, 2019; and (iv) 100% of the principal amount, if redeemed on or after November 1, 2020, in each case, plus any accrued and unpaid interest. Prior to November 1, 2017, some or all of the 2022 Notes were able to have been redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.
In the event of a "change of control," the issuers are required to offer to buy back all of the 2022 Notes at 101% of their principal amount. A change of control is generally defined as (i) the direct or indirect sale or transfer (other than by a merger) of all or substantially all of the assets of Refining LLC to any person other than qualifying owners (as defined in the indenture), (ii) liquidation or dissolution of Refining LLC, or (iii) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the member interest of Refining LLC.
See Part II, Item 8, Note 8 ("Long-Term Debt") of this Report for additional information on the 2022 Notes, including a description of the covenants contained therein. We were in compliance with the covenants as of December 31, 2017.
Amended and Restated Asset Based (ABL) Credit Facility. On November 14, 2017, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into Amendment No. 1 to the Amended and Restated ABL Credit Agreement (the “Amendment”) with a group of lenders and Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent and collateral agent. The Amendment amends certain provisions of the Amended and Restated ABL Credit Agreement, dated December 20, 2012, by and among Wells Fargo, the group of lenders party thereto and the Credit Parties (the “Existing Credit Agreement” and as amended by the Amendment, the “Amended and Restated ABL Credit Facility”), which was otherwise scheduled to mature in December 2017. The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swingline loans of $60.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The proceeds of the loans may be used for capital expenditures, working capital and general corporate purposes. The Amended and Restated Credit Facility matures in November 2022.
As of February 20, 2018, we had $359.1 million available under the Amended and Restated ABL Credit Facility. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions.
See Part II, Item 8, Note 8 ("Long-Term Debt") of this Report for additional information on the Amended and Restated ABL Credit Facility, including a description of the covenants contained therein. We were in compliance with the covenants as of December 31, 2017.
Intercompany Credit Facility. On January 23, 2013, we entered into a new $150.0 million senior unsecured revolving credit facility (the "intercompany credit facility") with CRLLC as the lender to be used to fund growth capital expenditures. On October 29, 2014, we entered into a first amendment to the intercompany credit facility with CRLLC to expand the borrowing capacity to $250.0 million. In conjunction with the Amended and Restated ABL Credit Facility extension in 2017, we reviewed the needs of the intercompany credit facility and decided to lower the borrowing capacity back to the original level of $150.0 million effective December 1, 2017. The intercompany credit facility matures in January 2019.
As of February 20, 2018, we had $150.0 million available under the intercompany credit facility.
See Part II, Item 8, Note 8 ("Long-Term Debt") of this Report for additional information on the Intercompany Credit Facility including a description of the covenants contained therein. We were in compliance with the covenants as of December 31, 2017.
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Capital Spending
We divide our capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.
The following table summarizes our total actual capital expenditures for 2017 and current estimated capital expenditures in 2018 by major category. These estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in the manner allocated below:
Year Ended December 31, | |||||||
2017 Actual | 2018 Estimate | ||||||
(in millions) | |||||||
(unaudited) | |||||||
Coffeyville refinery: | |||||||
Maintenance | $ | 36.9 | $ | 75.0 | |||
Growth | 3.0 | 10.0 | |||||
Coffeyville refinery total capital spending | 39.9 | 85.0 | |||||
Wynnewood refinery | |||||||
Maintenance | 38.1 | 65.0 | |||||
Growth | 4.0 | 25.0 | |||||
Wynnewood refinery total capital spending | 42.1 | 90.0 | |||||
Other Petroleum: | |||||||
Maintenance | 2.7 | 15.0 | |||||
Growth | 15.0 | 10.0 | |||||
Other petroleum total capital spending | 17.7 | 25.0 | |||||
Total capital spending | $ | 99.7 | $ | 200.0 | |||
On December 1, 2017, we acquired the Cushing to Ellis crude oil pipeline system from Plains All American Pipeline, L.P. ("Plains") for $15.0 million, which amount is included in other petroleum growth capital spending in the table above. The approximately 100-mile, 8- and 10-inch pipeline system links CVR Refining's Wynnewood, Oklahoma, refinery to Cushing.
Cash Flows
The following table sets forth our consolidated cash flows for the periods indicated below:
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Net cash provided by (used in): | |||||||||||
Operating activities | $ | 177.9 | $ | 267.8 | $ | 473.7 | |||||
Investing activities(1) | (176.1 | ) | (107.9 | ) | (194.7 | ) | |||||
Financing activities | (142.1 | ) | (33.1 | ) | (461.9 | ) | |||||
Net increase (decrease) in cash and cash equivalents | $ | (140.3 | ) | $ | 126.8 | $ | (182.9 | ) | |||
(1) | Investing activities for the year ended December 31, 2017 includes the acquisition of the Cushing to Ellis crude oil pipeline system totaling $15.0 million and equity method investments in the Midway joint venture of $76.0 million. |
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Cash Flows Provided by Operating Activities
For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.
Net cash flows provided by operating activities for the year ended December 31, 2017 were approximately $177.9 million. The positive cash flow from operating activities generated over this period was primarily driven by non-cash depreciation and amortization of $134.9 million, net income of $88.8 million, loss on derivatives of $69.8 million, net cash flows for trade working capital of $17.2 million and share-based compensation of $13.2 million partially offset by net cash outflows from other working capital of $127.8 million and loss on current period settlements on derivative contracts of $16.6 million. The net cash inflow from trade working capital was attributable to an increase in accounts payable of $88.7 million and partially offset by an increase in inventory of $40.1 million and accounts receivable of $31.4 million. The increase in accounts payable was primarily associated with an increase in lease crude payables due to increased activity and pricing. The increase in inventories was primarily attributable to increased pricing for gasoline, distillates and crude oil. The increase in accounts receivable was primarily due to increased pricing for both gasoline and distillates coupled with higher volumes. The net cash outflow from other working capital was primarily due to an decrease in other current liabilities of $161.5 million partially offset by an decrease in prepaid expenses and other current assets of $33.7 million. The decrease in other current liabilities was primarily attributable to a decrease in the biofuel blending obligation as a result of an increase in the volume of purchased RINs to fulfill the requirements under the RFS, partially offset by an increase in unrealized loss on open derivative positions and forward purchase commitments. The decrease in prepaid expense was primarily related to a decrease in crude barrels in-transit, a decrease in western Canadian select sales and a decrease in prepaid pipeline capacity.
Net cash flows provided by operating activities for the year ended December 31, 2016 were approximately $267.8 million. The positive cash flow from operating activities generated over this period was primarily driven by other working capital of $165.8 million, non-cash depreciation and amortization of $130.9 million, current period settlements of derivative contracts of $36.4 million, net loss on derivatives of $19.4 million and $15.3 million of net income, partially offset by cash outflows of $104.9 million for trade working capital. The cash inflow from other working capital of $165.8 million was primarily due to an increase in other current liabilities ($170.6 million) offset by an increase in prepaid expense ($4.8 million). The large increase in other current liabilities was primarily attributable to an increase in our biofuel blending obligation to fulfill the requirements under the RFS, as a result of increased RINs obligation associated with increased RINs prices during the year ended December 31, 2016. The net cash outflow for trade working capital was attributable to an increase in accounts receivable ($49.4 million) and inventory ($38.5 million) and a decrease in accounts payable ($17.0 million). The increase in accounts receivable was primarily due to increased pricing for both gasoline and distillates, as well as higher volume. The increase in inventories was also primarily attributable to increase pricing for both gasoline and distillates, as well as higher crude oil pricing. The decrease in accounts payables was primarily associated with the turnaround at our Coffeyville refinery which was completed during the first quarter of 2016.
Net cash flows provided by operating activities for the year ended December 31, 2015 were approximately $473.7 million. The positive cash flow from operating activities generated over this period was primarily driven by $291.2 million of net income and favorable impacts to trade working capital. Trade working capital for the year ended December 31, 2015 resulted in a net cash inflow of $66.1 million, which was attributable to decreases in inventory ($41.3 million) and accounts receivable ($41.1 million), partially offset by a decrease in accounts payable ($16.3 million). Each of the cash flow impacts in trade working capital was largely attributable to the crude oil pricing environment and significant decreases in sales prices for gasoline and distillates in 2015 as compared to 2014. Other working capital activities resulted in net cash outflow of $33.0 million, which was primarily related to a decrease in accrued expenses and other current liabilities ($45.9 million), partially offset by a decrease in prepaid expenses and other current assets ($12.9 million). The decrease in accrued expenses and other current liabilities was primarily attributable to a decrease in the biofuel blending obligation as a result of increased RINs purchases during the year ended December 31, 2015 to fulfill our requirements under the RFS. The decrease in prepaid expenses and other current assets was primarily attributable to the timing of payments associated with our crude oil intermediation agreement and a reduction in prepaid insurance.
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Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended December 31, 2017 was $176.1 million compared to $107.9 million for the year ended December 31, 2016. The increase in cash used in investing activities was the result of a $76.0 million contribution to the Midway joint venture and $15.0 million related to the acquisition of the Cushing to Ellis pipeline system, partially offset by a $17.6 million decrease in capital expenditures for the year ended December 31, 2017 compared to the year ended December 31, 2016. The decrease in capital expenditures primarily resulted from a $35.8 million decrease in capital expenditures at the Coffeyville refinery, a $2.8 million decrease in capital expenditures for other petroleum projects, offset by a $21.0 million increase in capital expenditures at the Wynnewood refinery.
Net cash used in investing activities for the year ended December 31, 2016 was $107.9 million compared to $194.7 million for the year ended December 31, 2015. The decrease in cash used in investing activities was the result of a $92.4 million decrease in capital expenditures for the year ended December 31, 2016 compared to the year ended December 31, 2015. The decrease primarily resulted from a $66.6 million decrease in capital expenditures at the Coffeyville refinery, a $14.9 million decrease in capital expenditures for other petroleum projects, and a $10.9 million decrease in capital expenditures at the Wynnewood refinery. The decrease in capital expenditures was partially offset by a $5.6 million investment in VPP in 2016.
Net cash used in investing activities for the year ended December 31, 2015 was $194.7 million compared to $191.2 million for the year ended December 31, 2014. The increase in cash used in investing activities was the result of a $3.4 million increase in capital expenditures for the year ended December 31, 2015 compared to the year ended December 31, 2014. The increase primarily resulted from a $62.6 million increase in capital expenditures at the Coffeyville refinery and a $6.2 million increase in capital expenditures for other petroleum projects, largely offset by a $65.4 million decrease in capital expenditures at the Wynnewood refinery.
Cash Flows Used In Financing Activities
Net cash used in financing activities for the year ended December 31, 2017 was approximately $142.1 million. The net cash used in financing activities for the year ended December 31, 2017 was primarily attributable to distributions to our common unitholders of $138.7 million (including $96.9 million to affiliates), capital lease payments of $1.8 million and deferring financing cost payments of $1.6 million related to the extension of the Amended and Restated ABL Credit Facility.
Net cash used in financing activities for the year ended December 31, 2016 was approximately $33.1 million. The net cash used in financing activities for the year ended December 31, 2016 was primarily attributable to intercompany credit facility payments of $31.5 million and capital lease payments of $1.6 million.
Net cash used in financing activities for the year ended December 31, 2015 was approximately $461.9 million. The net cash used in financing activities for the year ended December 31, 2015 was primarily attributable to distributions to our common unitholders of $460.5 million (including $322.3 million to affiliates).
As of and for the year ended December 31, 2017, there were no borrowings or repayments under the Amended and Restated ABL Credit Facility. As of December 31, 2017, the Partnership had no borrowings outstanding under the intercompany credit facility.
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Capital and Commercial Commitments
In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of December 31, 2017 relating to contractual obligations and other commercial commitments for the five-year period following December 31, 2017 and thereafter.
Payments Due by Period | |||||||||||||||||||||||||||
Total | 2018 | 2019 | 2020 | 2021 | 2022 | Thereafter | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||||||||
Contractual Obligations | |||||||||||||||||||||||||||
Long-term debt(1) | $ | 500.0 | $ | — | $ | — | $ | — | $ | — | $ | 500.0 | $ | — | |||||||||||||
Operating leases(2) | 1.4 | 0.6 | 0.4 | 0.1 | 0.1 | — | 0.2 | ||||||||||||||||||||
Capital lease obligations(3) | 45.0 | 2.1 | 2.3 | 2.6 | 2.9 | 3.1 | 32.0 | ||||||||||||||||||||
Unconditional purchase obligations(4) | 1,061.7 | 140.7 | 113.5 | 96.9 | 87.7 | 82.7 | 540.2 | ||||||||||||||||||||
Environmental liabilities(5) | 4.0 | 2.9 | 1.1 | — | — | — | — | ||||||||||||||||||||
Interest payments(6) | 188.9 | 36.9 | 36.7 | 36.4 | 36.2 | 30.5 | 12.2 | ||||||||||||||||||||
Total | $ | 1,801.0 | $ | 183.2 | $ | 154.0 | $ | 136.0 | $ | 126.9 | $ | 616.3 | $ | 584.6 | |||||||||||||
Other Commercial Commitments | |||||||||||||||||||||||||||
Standby letters of credit(7) | $ | 28.4 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
(1) | Consists of the 2022 Notes as of December 31, 2017. |
(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 $698.6 million payable ratably over 13 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, 2017, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of 20 years on TransCanada's Keystone pipeline system. 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 Item 1. "Business — Environmental Matters." |
(6) | Interest payments are based on stated interest rates for our long-term debt outstanding and interest payments for the capital lease obligation as of December 31, 2017. |
(7) | Standby letters of credit issued against the Amended and Restated ABL Credit Facility include $0.3 million of letters of credit issued in connection with environmental liabilities, $26.5 million in letters of credit to secure transportation services for crude oil and a $1.6 million letter of credit issued to guarantee a portion of our insurance policy. |
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Our ability to make payments on and to refinance our indebtedness, to fund budgeted capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. Our ability to refinance our indebtedness is also subject to the availability of the credit markets. This, to a certain extent, is subject to refining spreads and general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our Amended and Restated ABL Credit Facility or the intercompany credit facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need or seek to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all. In addition, we may from time to time seek to issue debt or equity securities in the public or private capital markets, but there can be no assurance that we will be able to do so at prices that we deem reasonable or at all.
Off-Balance Sheet Arrangements
We do not have any "off-balance sheet arrangements" as such term is defined within the rules and regulations of the SEC.
Recent Accounting Pronouncements
Refer to Part II, Item 8, Note 2 ("Summary of Significant Accounting Policies"), of this Report for a discussion of recent accounting pronouncements applicable to us.
Critical Accounting Policies
We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Report. Our critical accounting policies, which are listed below, could materially affect the amounts recorded in our consolidated financial statements.
•Estimated lives used in computing depreciation for property, plant and equipment
•Impairment of long-lived assets
•Derivative instruments and fair value of financial instruments
•Share-based compensation
•Allocation of costs
Refer to Note 2 ("Summary of Significant Accounting Policies") to Part II, Item 8 of this Report for a discussion of these accounting policies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices, RINs prices and interest rates. None of our market risk sensitive instruments are held for trading purposes.
Commodity Price Risk
Our business has exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, a positive spread between the cost of raw materials and the value of finished products must be achieved (i.e., gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.
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We use a crude oil purchasing intermediary, Vitol, to purchase the majority of our non-gathered crude oil inventory for the refineries, which allows us to take title to and price our crude oil at locations in close proximity to our refineries, as opposed to the crude oil origination point, reducing our risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to the time elapsed between raw material acquisition and the sale of finished goods. In addition, we seek to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in our annual operating plan. Accordingly, we use commodity derivative contracts to economically hedge future cash flows (i.e., gross margin or crack spreads) and product inventories. With regard to our hedging activities, we may enter into, or have entered into, derivative instruments which serve to:
• | lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows; |
• | hedge the value of inventories in excess of minimum required inventories; and |
• | manage existing derivative positions related to a change in anticipated operations and market conditions. |
Further, we intend to engage only in risk mitigating activities directly related to our businesses.
Basis Risk
The effectiveness of our derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors including time or location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure.
Examples of our basis risk exposure are as follows:
Time Basis—In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods, then weighted-average physical prices will be weighted differently than the swap price as a result of timing.
Location Basis—In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area.
Price and Basis Risk Management Activities
In the event our inventories exceed our target base level of inventories, we may enter into commodity derivative contracts to manage our price exposure to our inventory positions that are in excess of our base level. Excess inventories are typically the result of plant operations, such as a turnaround or other plant maintenance.
To reduce the basis risk between the price of products for Group 3 and that of the NYMEX associated with selling forward derivative contracts for NYMEX crack spreads, we may enter into basis swap positions to lock the price difference. If the difference between the price of products on the NYMEX and Group 3 (or some other price benchmark as specified in the swap) is different than the value contracted in the swap, then we will receive from or owe to the counterparty the difference on each unit of product contracted in the swap, thereby completing the locking of our margin. An example of our use of a basis swap is in the winter heating oil season. The risk associated with not hedging the basis when using NYMEX forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or decreases then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on Group 3 pricing.
From time to time, we also hold various NYMEX positions through a third-party clearing house. At December 31, 2017, we had no open commodity positions. At December 31, 2017, our account balance maintained at the third-party clearing house totaled approximately $1.4 million, which is reflected on the Consolidated Balance Sheets in cash and cash equivalents. NYMEX transactions conducted for the year ended December 31, 2017 resulted in loss on derivatives, net of approximately $0.5 million.
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We enter into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, we may enter into price and basis swaps in order to fix the price on a portion of our commodity purchases and product sales. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheets with changes in fair value currently recognized in the Consolidated Statements of Operations. At December 31, 2017 we had open commodity swaps instruments consisting of 7.1 million barrels of 2-1-1 crack spreads, 3.6 million barrels of distillate crack spreads and 3.6 million barrels of gasoline crack spreads. Additionally, as of December 31, 2017, we had open forward purchase and sale commitments for 5.8 million barrels of Canadian crude oil priced at fixed differentials that are not considered probable of physical settlement and are accounted for as derivatives at December 31, 2017. A change of $1.00 per barrel in the fair value of the benchmark would result in an increase or decrease in the related fair values of commodity instruments of $17.7 million. The fair value of the outstanding contracts at December 31, 2017 was a net unrealized loss of $64.3 million, comprised of short-term unrealized losses.
Compliance Program Price Risk
As a producer of transportation fuels from petroleum, we are required to blend biofuels into the product we produce or to purchase RINs in the open market in lieu of blending to meet the mandates established by the EPA. We are exposed to market risk related to volatility in the price of RINs needed to comply with the RFS. To mitigate the impact of this risk on our results of operations and cash flows, we purchased RINs when prices are deemed favorable. See Note 12 ("Commitments and Contingencies") to Part II, Item 8 of this Report and "Major Influences on Results of Operations" in Part II, Item 7 of this Report for further discussion about compliance with the RFS.
Foreign Currency Exchange
Given that our operations are based entirely in the United States, we are not significantly exposed to foreign currency exchange rate risk. A portion of our pipeline transportation costs are transacted in Canadian dollars. Commitments for future periods under this agreement reflect the exchange rate between the Canadian Dollar and the U.S. Dollar as of the end of the reporting period. Based on the short period of time between the billing and settlement of these transportation costs in Canadian dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not material.
69
Item 8. Financial Statements and Supplementary Data
CVR REFINING, LP AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements: | Page Number |
70
Report of Independent Registered Public Accounting Firm
The Board of Directors of CVR Refining GP, LLC
The Unitholders of CVR Refining, LP
The General Partner of CVR Refining, LP
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of CVR Refining, LP (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in partners' capital, and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the Partnership's internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"), and our report dated February 23, 2018 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have serviced as the Partnership's auditor since 2013.
Kansas City, Missouri
February 23, 2018
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Report of Independent Registered Public Accounting Firm
The Board of Directors of CVR Refining GP, LLC
The Unitholders of CVR Refining, LP
The General Partner of CVR Refining, LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of CVR Refining, LP (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2017, based on criteria established in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013 Internal Control - Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2017, and our report dated February 23, 2018 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report On Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definitions and limitations of internal control over financial reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that 1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and 3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Kansas City, Missouri
February 23, 2018
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||
2017 | 2016 | ||||||
(in millions, except unit data) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 173.8 | $ | 314.1 | |||
Accounts receivable, net of allowance for doubtful accounts of $1.1 and $0.5, including $0.1 and $0.1 due from affiliates at December 31, 2017 and 2016, respectively | 168.9 | 138.1 | |||||
Inventories | 331.2 | 291.1 | |||||
Prepaid expenses and other current assets, including $1.5 and $1.2 due from affiliates at December 31, 2017 and 2016, respectively | 25.9 | 60.3 | |||||
Total current assets | 699.8 | 803.6 | |||||
Property, plant and equipment, net of accumulated depreciation | 1,478.8 | 1,515.0 | |||||
Equity method investments in affiliates | 82.8 | 5.6 | |||||
Other long-term assets | 8.5 | 7.7 | |||||
Total assets | $ | 2,269.9 | $ | 2,331.9 | |||
LIABILITIES AND PARTNERS' CAPITAL | |||||||
Current liabilities: | |||||||
Note payable and capital lease obligations | $ | 2.1 | $ | 1.8 | |||
Accounts payable, including $4.9 and $4.6 due to affiliates at December 31, 2017 and 2016, respectively | 312.3 | 225.9 | |||||
Personnel accruals, including $4.1 and $3.0 due to affiliates at December 31, 2017 and 2016, respectively | 27.3 | 19.3 | |||||
Accrued taxes other than income taxes | 24.9 | 25.2 | |||||
Accrued expenses and other current liabilities, including $10.6 and $8.9 due to affiliates at December 31, 2017 and 2016, respectively | 115.7 | 217.7 | |||||
Total current liabilities | 482.3 | 489.9 | |||||
Long-term liabilities: | |||||||
Long-term debt and capital lease obligations, net of current portion | 538.5 | 539.7 | |||||
Other long-term liabilities, including $0.0 and $0.6 due to affiliates at December 31, 2017 and 2016, respectively | 2.3 | 5.6 | |||||
Total long-term liabilities | 540.8 | 545.3 | |||||
Commitments and contingencies | |||||||
Partners’ capital: | |||||||
Common unitholders, 147,600,000 units issued and outstanding at December 31, 2017 and 2016 | 1,246.8 | 1,296.7 | |||||
General partner interest | — | — | |||||
Total partners' capital | 1,246.8 | 1,296.7 | |||||
Total liabilities and partners' capital | $ | 2,269.9 | $ | 2,331.9 | |||
See accompanying notes to consolidated financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except per unit data) | |||||||||||
Net sales | $ | 5,664.2 | $ | 4,431.3 | $ | 5,161.9 | |||||
Operating costs and expenses: | |||||||||||
Cost of materials and other | 4,804.7 | 3,759.2 | 4,143.6 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 443.8 | 393.4 | 478.5 | ||||||||
Depreciation and amortization | 129.3 | 126.3 | 128.0 | ||||||||
Cost of sales | 5,377.8 | 4,278.9 | 4,750.1 | ||||||||
Flood insurance recovery | — | — | (27.3 | ) | |||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below) | 78.8 | 71.9 | 75.2 | ||||||||
Depreciation and amortization | 3.8 | 2.7 | 2.2 | ||||||||
Total operating costs and expenses | 5,460.4 | 4,353.5 | 4,800.2 | ||||||||
Operating income | 203.8 | 77.8 | 361.7 | ||||||||
Other income (expense): | |||||||||||
Interest expense and other financing costs | (47.2 | ) | (43.4 | ) | (42.6 | ) | |||||
Interest income | 0.5 | 0.1 | 0.4 | ||||||||
Loss on derivatives, net | (69.8 | ) | (19.4 | ) | (28.6 | ) | |||||
Other income, net | 1.5 | 0.2 | 0.3 | ||||||||
Total other expense | (115.0 | ) | (62.5 | ) | (70.5 | ) | |||||
Income before income tax expense | 88.8 | 15.3 | 291.2 | ||||||||
Income tax expense | — | — | — | ||||||||
Net income | $ | 88.8 | $ | 15.3 | $ | 291.2 | |||||
Net income per common unit - basic and diluted | $ | 0.60 | $ | 0.10 | $ | 1.97 | |||||
Weighted average common units outstanding: | |||||||||||
Basic and diluted | 147.6 | 147.6 | 147.6 | ||||||||
See accompanying notes to consolidated financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL
Common Units Issued | Limited Partner Interest | Common Unitholders | General Partner Interest | Total Partners' Capital | ||||||||||||||
(in millions, except unit data) | ||||||||||||||||||
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 | |||||||||||||
Cash distributions to common unitholders - Affiliates | — | — | (96.9 | ) | — | (96.9 | ) | |||||||||||
Cash distributions to common unitholders - Non-affiliates | — | — | (41.8 | ) | — | (41.8 | ) | |||||||||||
Net income | — | — | 88.8 | — | 88.8 | |||||||||||||
Balance at December 31, 2017 | 147,600,000 | $ | — | $ | 1,246.8 | $ | — | $ | 1,246.8 | |||||||||
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Cash flows from operating activities: | |||||||||||
Net income | $ | 88.8 | $ | 15.3 | $ | 291.2 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation and amortization | 133.1 | 129.0 | 130.2 | ||||||||
Allowance for doubtful accounts | 0.6 | 0.2 | — | ||||||||
Amortization of deferred financing costs | 1.8 | 1.9 | 1.9 | ||||||||
Loss on disposition of assets | 1.6 | 0.3 | 0.9 | ||||||||
Share-based compensation | 13.2 | 4.9 | 9.3 | ||||||||
Loss on derivatives, net | 69.8 | 19.4 | 28.6 | ||||||||
Current period settlements on derivative contracts | (16.6 | ) | 36.4 | (26.0 | ) | ||||||
Income from equity method investments, net of distributions | (0.7 | ) | — | — | |||||||
Changes in assets and liabilities: | |||||||||||
Accounts receivable | (31.4 | ) | (49.4 | ) | 41.1 | ||||||
Inventories | (40.1 | ) | (38.5 | ) | 41.3 | ||||||
Prepaid expenses and other current assets | 33.7 | (4.8 | ) | 12.9 | |||||||
Other long-term assets | 0.3 | 0.5 | 4.3 | ||||||||
Accounts payable | 88.7 | (17.0 | ) | (16.3 | ) | ||||||
Accrued expenses and other current liabilities | (161.5 | ) | 170.6 | (45.9 | ) | ||||||
Other long-term liabilities | (3.4 | ) | (1.0 | ) | 0.2 | ||||||
Net cash provided by operating activities | 177.9 | 267.8 | 473.7 | ||||||||
Cash flows from investing activities: | |||||||||||
Capital expenditures | (99.7 | ) | (102.3 | ) | (194.7 | ) | |||||
Proceeds from sale of assets | 0.1 | — | — | ||||||||
Investment in affiliate, net of return of investment | (76.5 | ) | (5.6 | ) | — | ||||||
Net cash used in investing activities | (176.1 | ) | (107.9 | ) | (194.7 | ) | |||||
Cash flows from financing activities: | |||||||||||
Payment of capital lease obligations | (1.8 | ) | (1.6 | ) | (1.4 | ) | |||||
Payment of deferred financing costs | (1.6 | ) | — | — | |||||||
Revolving debt repayment - affiliates | — | (31.5 | ) | — | |||||||
Distributions to common unitholders - affiliates | (96.9 | ) | — | (322.3 | ) | ||||||
Distributions to common unitholders - non-affiliates | (41.8 | ) | — | (138.2 | ) | ||||||
Net cash used in financing activities | (142.1 | ) | (33.1 | ) | (461.9 | ) | |||||
Net increase (decrease) in cash and cash equivalents | (140.3 | ) | 126.8 | (182.9 | ) | ||||||
Cash and cash equivalents, beginning of period | 314.1 | 187.3 | 370.2 | ||||||||
Cash and cash equivalents, end of period | $ | 173.8 | $ | 314.1 | $ | 187.3 | |||||
Supplemental disclosures: | |||||||||||
Cash paid for interest net of capitalized interest of $0.9, $5.0 and $3.7 for the years ended December 31, 2017, 2016 and 2015, respectively | $ | 45.1 | $ | 41.5 | $ | 40.6 | |||||
Non-cash investing and financing activities: | |||||||||||
Construction in progress additions included in accounts payable | $ | 6.9 | $ | 9.2 | $ | 20.6 | |||||
Change in accounts payable related to construction in progress additions | $ | (2.3 | ) | $ | (11.4 | ) | $ | 0.7 | |||
See accompanying notes to consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Nature of Business
CVR Refining, LP and subsidiaries ("CVR Refining" or the "Partnership") is an independent petroleum refiner and marketer of high value transportation fuels. The Partnership owns a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a complex crude oil refinery in Wynnewood, Oklahoma. As of December 31, 2017, Coffeyville Resources, LLC ("CRLLC") a wholly-owned subsidiary of CVR Energy, Inc. ("CVR Energy"), owns 100% of the Partnership's non-economic general partner interest and approximately 66% of the Partnership's outstanding limited partner interests. As of December 31, 2017, Icahn Enterprises L.P. ("IEP") and its affiliates own approximately 82% of CVR Energy's outstanding shares.
On January 23, 2013, the Partnership completed an initial public offering (the "Initial Public Offering"). The Partnership sold 24,000,000 common units at a price of $25.00 per unit. Of the common units issued, 4,000,000 units were purchased by an affiliate of IEP. Additionally, on January 30, 2013, the underwriters closed their option to purchase an additional 3,600,000 common units at a price of $25.00 per unit. The common units, which are listed on the New York Stock Exchange, began trading on January 17, 2013 under the symbol "CVRR."
As of December 31, 2017, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 3.9% of all outstanding limited partner interests), and CVR Refining Holdings, LLC ("CVR Refining Holdings") held approximately 66% of all outstanding limited partner interests. In addition, CVR Refining Holdings owns 100% of the Partnership's general partner, CVR Refining GP, LLC ("CVR Refining GP") which holds a non-economic general partner interest.
Management and Operations
The Partnership is party to a services agreement, pursuant to which the Partnership and its general partner obtain certain management and other services from CVR Energy. The Partnership's general partner manages the Partnership's activities subject to the terms and conditions specified in the Partnership's partnership agreement. The operations of the general partner, in its capacity as general partner, are managed by its board of directors. Actions by the general partner that are made in its individual capacity are made by CVR Refining Holdings, a subsidiary of CRLLC, as the sole member of the Partnership's general partner and not by the board of directors of the general partner. The members of the board of directors of the Partnership's general partner are not elected by the Partnership's unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business.
The Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter. The available cash for distribution for each quarter will be determined by the board of directors of the Partnership's general partner following the end of such quarter and will generally be distributed within 60 days of quarter end. The partnership agreement does not require that the Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Partnership can change the distribution policy at any time.
(2) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying Partnership consolidated financial statements include the accounts of CVR Refining and its wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates
The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America ("GAAP"), using management's best estimates and judgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from these estimates and judgments.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Cash and Cash Equivalents
The Partnership considers all highly liquid money market accounts and debt instruments with original maturities of three months or less to be cash equivalents. Under the Partnership's cash management system, checks issued but not presented to banks frequently result in book overdraft balances for accounting purposes and are classified within accounts payable in the Consolidated Balance Sheets. The change in book overdrafts are reported in the Consolidated Statements of Cash Flows as a component of operating cash flows for accounts payable as they do not represent bank overdrafts. The amount of these checks included in accounts payable as of December 31, 2017 and 2016 was $10.2 million and $11.1 million, respectively.
Accounts Receivable, net
CVR Refining grants credit to its customers. Credit is extended based on an evaluation of a customer's financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding longer than their contractual payment terms are considered past due. CVR Refining determines its allowance for doubtful accounts by considering a number of factors, including the length of time trade accounts are past due, the customer's ability to pay its obligations to CVR Refining, and the condition of the general economy and the industry as a whole. CVR Refining writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. Amounts collected on accounts receivable are included in net cash provided by operating activities in the Consolidated Statements of Cash Flows. At December 31, 2017 and 2016, one customer individually represented greater than 10% of the total net accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2017 and 2016 was approximately 12% and 11%, respectively, of the net accounts receivable balance.
Inventories
Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress and refined fuels and by-products. Inventories are valued at the lower of the first-in, first-out ("FIFO") cost, or net realizable value for refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or net realizable value. The cost of inventories includes inbound freight costs.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to the Partnership's refineries for which title had not transferred, non-trade accounts receivable, current portions of prepaid insurance, deferred financing costs, derivative agreements and other general current assets.
Property, Plant and Equipment
Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1.0 million in cost which is expected to take more than six months to complete. Depreciation is computed using principally the straight-line method over the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:
Asset | Range of Useful Lives, in Years | ||
Improvements to land | 15 | to | 30 |
Buildings | 20 | to | 30 |
Machinery and equipment | 5 | to | 30 |
Automotive equipment | 5 | to | 15 |
Furniture and fixtures | 3 | to | 10 |
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Leasehold improvements and assets held under capital leases are depreciated or amortized on the straight-line method over the shorter of the contractual lease term or the estimated useful life of the asset. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
Deferred Financing Costs
Deferred financing costs associated with debt issuances are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Additionally, any underwriting and original issue discount and premium related to debt issuances are amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Deferred financing costs related to the Partnership's Amended and Restated ABL Credit Facility are amortized to interest expense and other financing costs using the straight-line method through the termination date of the facility.
Planned Major Maintenance Costs
The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. The required frequency of planned major maintenance activities varies by unit for the refineries, but generally is every four to five years. Costs associated with these turnaround activities were included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations.
For the years ended December 31, 2017, 2016 and 2015, the Partnership incurred the following major scheduled turnaround expenses.
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Coffeyville refinery(1) | $ | — | $ | 31.5 | 102.2 | ||||||
Wynnewood refinery(2) | 80.4 | — | — | ||||||||
Total major scheduled turnaround expenses | $ | 80.4 | $ | 31.5 | $ | 102.2 | |||||
(1) | The Coffeyville refinery completed the first phase of its most recent major scheduled turnaround in November 2015. The second phase of the Coffeyville turnaround was completed during the first quarter of 2016. |
(2) | The Wynnewood refinery completed the first phase of its most recent major scheduled turnaround in November 2017. The second phase of the Wynnewood turnaround is expected to occur in 2019. In addition to the two phase turnaround, we accelerated certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. We incurred approximately $13.0 million of major scheduled turnaround expenses for the hydrocracker. |
Cost Classifications
Cost of materials and other includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, renewable identification numbers ("RINs") expenses and transportation and distribution costs.
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses also include allocated share-based compensation from CVR Energy and its subsidiaries as discussed in Note 3 ("Share-Based Compensation").
Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated expenses for legal, treasury, accounting, marketing, human resources, information technology and maintaining the corporate and administrative offices in Texas and Kansas. Selling, general and administrative expenses also include allocated share-based compensation from CVR Energy and its subsidiaries as discussed in Note 3 ("Share-Based Compensation").
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes
CVR Refining is treated as a partnership for U.S. federal income tax purposes. The income tax liability of the common unitholders is not reflected in the consolidated financial statements of the Partnership. Generally, each common unitholder is required to take into account its respective share of CVR Refining's income, gains, loss and deductions. The Partnership is not subject to income taxes, except for a franchise tax in the State of Texas.
Under the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 740, Income Taxes, taxes based on income like the Texas franchise tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. As of December 31, 2017 and 2016, the Partnership has no material tax balances associated with the Texas franchise tax. When applicable, penalties and interest related to uncertain tax positions are recorded as income tax expense.
Segment Reporting
The Partnership accounts for segment reporting in accordance with ASC Topic 280, Segment Reporting, which established standards for entities to report information about the operating segments and geographic areas in which they operate. CVR Refining only operates one segment and all of its operations are located in the United States.
Impairment of Long-Lived Assets
CVR Refining accounts for long-lived assets in accordance with accounting standards issued by the FASB regarding the treatment of the impairment or disposal of long-lived assets. As required by this standard, CVR Refining reviews long-lived assets (excluding intangible assets with indefinite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell.
Revenue Recognition
Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has assumed the risk of loss, and payment has been received or collection is reasonably assured. Excise and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues.
Non-monetary product exchanges and certain buy/sell crude oil transactions which are entered into in the normal course of business are included on a net cost basis in operating expenses on the Consolidated Statements of Operations.
Shipping Costs
Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of materials and other.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Derivative Instruments and Fair Value of Financial Instruments
The Partnership uses futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices and finished goods product prices to provide economic hedges of inventory positions. Although management considers these derivatives economic hedges, these derivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging, and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. See Note 14 ("Derivative Financial Instruments") for further discussion.
Other financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments. See Note 8 ("Long-Term Debt") for further discussion of the fair value of the debt instruments.
Share-Based Compensation
The Partnership has recorded share-based compensation expense related to the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP") and has been allocated share-based compensation expense from CVR Energy and CRLLC. The Partnership and CVR Energy account for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation ("ASC 718"). ASC 718 requires that compensation costs relating to share-based payment transactions be recognized in a company's financial statements. ASC 718 applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based on the fair value of those equity instruments. Currently, all of the Partnership's share-based compensation awards are liability-classified and are measured at fair value at the end of each reporting period based on the applicable closing unit price. Compensation expense will fluctuate based on changes in the applicable unit price value and expense reversals resulting from employee terminations prior to award vesting. See Note 3 ("Share-Based Compensation") for further discussion.
CVR Energy's Chief Executive Officer has been awarded share-based compensation awards that contain performance conditions. The fair value of the awards is recognized as compensation expense only if the attainment of the performance conditions is considered probable. Uncertainties involved in this estimate include the continued employment of the Chief Executive Officer and whether or not the performance conditions will be attained. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. If this assumption proves not to be true and the awards do not vest, compensation expense recognized during the performance cycle will be reversed.
Environmental Matters
Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, internal and third-party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Allocation of Costs
CVR Energy and its subsidiaries provide a variety of services to CVR Refining, including cash management and financing services, employee benefits provided through CVR Energy's benefit plans, administrative services provided by CVR Energy's employees and management, insurance and office space leased in CVR Energy's headquarters building and other locations. As such, the accompanying consolidated financial statements include costs that have been incurred by CVR Energy and CRLLC on behalf of CVR Refining. These amounts incurred by CVR Energy are then billed or allocated to CVR Refining and are properly classified on the Consolidated Statements of Operations as either direct operating expenses (exclusive of depreciation and amortization) or as selling, general and administrative expenses (exclusive of depreciation and amortization). The billing and allocation of such costs are governed and billed in accordance with the services agreement entered into between the Partnership, its general partner and CVR Energy. The services agreement provides guidance for the treatment of certain general and administrative expenses and certain direct operating expenses incurred on the Partnership's behalf. Such expenses include, but are not limited to, salaries, benefits, share-based compensation expense, insurance, accounting, tax, legal and technology services. Costs which are specifically incurred on behalf of CVR Refining are billed directly to CVR Refining. See Note 15 ("Related Party Transactions") for a detailed discussion of the billing procedures and the basis for calculating the charges for specific products and services.
Subsequent Events
The Partnership evaluated subsequent events, if any, that would require an adjustment to the Partnership's consolidated financial statements or require disclosure in the notes to the consolidated financial statements through the date of issuance of the consolidated financial statements.
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-09, creating a new topic, FASB ASC Topic 606, “Revenue from Contracts with Customers," which supersedes revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition.” This ASU requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. In addition, an entity is required to disclose sufficient information to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard is effective for interim and annual periods beginning after December 15, 2017. The Partnership adopted this standard, effective January 1, 2018, using the modified retrospective application method, whereby the cumulative effect of initially applying the standard is recognized, if applicable, as an adjustment to the opening balance of partners' capital. The standard is applied prospectively and revenues reported in the periods prior to January 1, 2018 will not be changed. During the evaluation of the standard, the Partnership reviewed its existing revenue streams, including an evaluation of accounting policies, contract reviews and identification of the types of arrangements where differences may arise in the conversion to the new standard, identified practical expedients to be elected and evaluated additional disclosure requirements. The Partnership did not identify any material differences in its existing revenue recognition methods that require modification under the new standard and does not expect to record a cumulative effect adjustment of applying the standard using the modified retrospective method. The standard's most significant impact to the Partnership relates to enhanced disclosure requirements.
In February 2016, the FASB issued ASU No. 2016-02, “Leases” (“ASU 2016-02”) creating a new topic, FASB ASC Topic 842, "Leases," which supersedes lease requirements in FASB ASC Topic 840, "Leases." The new standard revises accounting for operating leases by a lessee, among other changes, and requires a lessee to recognize a liability related to future lease payments and an asset representing its right to use the underlying asset for the lease term in the balance sheet. Quantitative and qualitative disclosures, including disclosures regarding significant judgments made by management, will be required. The standard is effective for the first interim and annual periods beginning after December 15, 2018, with early adoption permitted. At adoption, ASU 2016-02 will be applied using the modified retrospective application method and allows for certain practical expedients. The Partnership expects its assessment and implementation plan to be ongoing during 2018 and is currently unable to reasonably estimate the impact of adopting the new lease standard on its consolidated financial statements and related disclosures. The Partnership currently believes the most significant change will relate to the recognition of right-of-use assets and leases liability on the balance sheet for existing long-term operating leases, and the potential recognition for agreements that do not currently meet the definition of a lease under ASC Topic 840, which will require an evaluation of the Partnership's unconditional purchase obligations primarily related to petroleum transportation and storage service agreements. The right of use asset, lease liability and related disclosures could be material to the Partnership's consolidated financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations (Topic 805) Clarifying the Definition of a Business” ("ASU 2017-01"). The new guidance revises the definition of a business and provides more stringent criteria for use in determining when an acquisition or disposal transaction meets the definition of a business. When substantially all of the fair value of gross assets acquired is concentrated in a single asset (or a group of similar assets), the assets acquired would not represent a business. This introduces an initial required screen that, if met, eliminates the need for further assessment. The new guidance is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted. The Partnership adopted this standard as of January 1, 2017.
(3) Share-Based Compensation
Certain employees of CVR Refining and employees of CVR Energy and its subsidiaries who perform services for CVR Refining participate in the equity compensation plans of CVR Refining's affiliates. Accordingly, CVR Refining has recorded compensation expense for these plans in accordance with Staff Accounting Bulletin ("SAB") Topic 1-B, "Allocations of Expenses and Related Disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity," and in accordance with guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. All compensation expense related to these plans for full-time employees of CVR Refining has been attributed 100% to CVR Refining. For employees of CVR Energy performing services for CVR Refining, CVR Refining recorded share-based compensation relative to the percentage of time spent by each employee providing services to CVR Refining as compared to the total calculated share-based compensation by CVR Energy.
The Partnership has been allocated share-based compensation expense for restricted stock units, performance units and incentive units from CVR Energy. The Partnership is not responsible for payment of cash related to any restricted stock units allocated to the Partnership by CVR Energy; however, the Partnership is responsible for payment of cash on both the performance units and incentive units. For restricted stock units, the Partnership recognizes the costs of the share-based compensation incurred by CVR Energy on its behalf in selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization) and a corresponding increase or decrease to partners' capital, as the costs are incurred on the Partnership's behalf, following the guidance issued by the FASB regarding the accounting for equity instruments that are issued to other than employees for acquiring, or in conjunction with selling goods or services, which require remeasurement at each reporting period through the performance commitment period, or in the Partnership's case, through the vesting period. For performance units and incentive units, the Partnership recognizes the costs of the share-based compensation incurred by CVR Energy on its behalf in selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization), and a corresponding increase or decrease to accrued expenses and other current liabilities.
Long-Term Incentive Plan — CVR Energy
CVR Energy has a Long-Term Incentive Plan ("CVR Energy LTIP") that permits the grant of options, stock appreciation rights ("SARs"), restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted stock). As of December 31, 2017, only performance units under the CVR Energy LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the CVR Energy LTIP include CVR Energy's or its subsidiaries' (including CVR Refining) employees, officers, consultants and directors.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted Stock Units
Through the CVR Energy LTIP, shares of restricted stock and restricted stock units (collectively "restricted shares") were previously granted to employees of CVR Energy and CVR Refining. Restricted shares, when granted, were historically valued at the closing market price of CVR Energy's common stock on the date of issuance. These restricted shares were generally graded-vesting awards, which vested over a three-year period. Compensation expense was recognized on a straight-line basis over the vesting period of the respective tranche of the award. The change of control of CVR Energy in 2012 triggered a modification to outstanding awards under the CVR Energy LTIP converting the awards to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one contingent cash payment right ("CCP") upon vesting. The CCPs expired on August 19, 2013. Restricted shares that vested in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards were settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value of CVR Energy's common stock as determined at the most recent valuation date of December 31 of each year. The awards were remeasured at each subsequent reporting date until they vested.
In December 2012 and during 2013, restricted stock units and dividend equivalent rights were granted to certain employees of CVR Energy and its subsidiaries (including CVR Refining). The awards vested over three years with one-third of the award vesting each year with the exception of awards granted to certain executive officers that vested over one year. The award granted in December 2012 to Mr. Lipinski, CVR Energy's then Chief Executive Officer and President, was canceled in connection with the issuance of certain performance unit awards as discussed further below. Each restricted stock unit and dividend equivalent right represented the right to receive, upon vesting, a cash payment equal to (i) the fair market value of one share of the CVR Energy's common stock, plus (ii) the cash value of all dividends declared and paid per share of CVR Energy's common stock from the grant date to and including the vesting date. The awards, which were liability-classified, were remeasured each subsequent reporting date until they vested.
As of December 31, 2017, no restricted stock units were outstanding. Total compensation expense for the years ended December 31, 2017 and 2016 related to the restricted stock unit awards was nominal. Total compensation expense for the year ended December 31, 2015 was approximately $0.6 million. CVR Refining is not responsible for payment of CVR Energy restricted stock unit awards, and accordingly, the expenses recorded for the years ended December 31, 2017, 2016 and 2015 have been reflected as an increase to partners' capital.
Performance Unit Awards
In December 2015, CVR Energy entered into a performance unit award agreement (the "2015 Performance Unit Award Agreement") with Mr. Lipinski. The performance unit award of 3,500 performance units under the 2015 Performance Unit Award Agreement represents the right to receive, upon vesting, a cash payment equal to $1,000 multiplied by the applicable performance factor. The performance factor is determined based on the level of attainment of the applicable performance objective, set forth as a percentage, which may range from 0-110%. Seventy-five percent of the performance units attributable to the award are subject to a performance objective relating to the average barrels per day crude throughput during the performance cycle, and 25% of the performance units attributable to the award are subject to a performance objective relating to the average gathered crude barrels per day during the performance cycle. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. The amount paid pursuant to the award was paid during the first quarter of 2017. The Partnership reimbursed CVR Energy for its allocated portion of the performance unit award. Compensation cost for the 2015 Performance Unit Award Agreement totaling $1.7 million was recognized over the performance cycle from January 1, 2016 to December 31, 2016.
In December 2016, CVR Energy entered into a performance unit award agreement (the "2016 Performance Unit Award Agreement") with Mr. Lipinski with terms substantially the same as the 2015 Performance Unit Award Agreement. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2018. The Partnership will be responsible for reimbursing CVR Energy for its allocated portion of the performance unit award. Compensation cost for the 2016 Performance Unit Award Agreement of $1.8 million was recognized over the performance cycle from January 1, 2017 to December 31, 2017. As of December 31, 2017, the Partnership had an outstanding liability of $1.8 million related to the 2016 performance unit award.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On November 1, 2017, CVR Energy entered into a performance unit agreement (the "2017 Performance Unit Agreement") with David Lamp, CVR Energy's current Chief Executive Officer and President. Compensation cost for the 2017 Performance Unit Agreement will be recognized over the performance cycle from January 1, 2018 to December 31, 2018. The performance unit award of 1,500 performance units under the 2017 Performance Unit Agreement represents the right to receive, upon vesting, a cash payment equal to $1,000 multiplied by the applicable performance factor. The performance factor is determined based on the level of attainment of the applicable performance objective, and both the performance factor and performance objective(s) will be determined by CVR Energy's compensation committee. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2019. The Partnership is responsible for reimbursing CVR Energy for its allocated portion of the performance unit awards. Assuming a target performance threshold and that the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at December 31, 2017, there was approximately $0.8 million of total unrecognized compensation cost related to the 2017 Performance Unit Agreement to be recognized over a period of one year.
On November 1, 2017, CVR Energy entered into a performance unit award agreement (the "2017 Performance Unit Award Agreement") with Mr. Lamp. The performance unit award represents the right to receive upon vesting, a cash payment equal to $10.0 million if the average closing price of CVR Energy's common stock over the 30-trading day period from January 4, 2022 to February 15, 2022 is equal to or greater than $60 per share. At December 31, 2017, there was approximately $10.0 million of total unrecognized compensation cost related to the 2017 Performance Unit Award Agreement to be recognized over a period of 4 years.
Incentive Unit Awards
In 2015, 2016 and 2017, CVR Energy granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC, CVR Energy and CVR GP, LLC. The awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each incentive unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
Assuming the portion of time spent on CVR Refining related matters by CVR Energy employees providing services to CVR Refining remains consistent with the amount of services provided during December 31, 2017, there was approximately $5.9 million of total unrecognized compensation cost related to the incentive units and associated distribution equivalent rights to be recognized over a weighted-average period of approximately 1.6 years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that occur from time to time. The unrecognized compensation expense has been determined by the number of incentive units and associated distribution equivalent rights and respective allocation percentages for individuals for whom, as of December 31, 2017, compensation expense has been allocated to the Partnership. Total compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 related to the incentive unit awards was $4.1 million, $1.5 million and $3.8 million, respectively. The Partnership is responsible for reimbursing CVR Energy for its allocated portion of the incentive unit awards.
As of December 31, 2017 and 2016, the Partnership had a liability of $2.2 million and $1.5 million, respectively, for its allocated portion of non-vested incentive units and associated distribution equivalent rights, which is recorded in accrued expenses and other current liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2017, 2016 and 2015, the Partnership reimbursed CVR Energy $3.1 million, $1.9 million and $2.4 million for its allocated portion of the incentive unit award payments.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Long-Term Incentive Plan — CVR Refining
Individuals who are eligible to receive awards under the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP") include (i) employees of the Partnership and its subsidiaries, (ii) employees of the general partner, (iii) members of the board of directors of the general partner and (iv) certain employees, consultants and directors of CRLLC and CVR Energy who perform services for the benefit of the Partnership. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards and distribution equivalent rights, each in respect of common units. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. As the phantom unit awards discussed below are cash-settled awards, they did not reduce the number of common units available for issuance under the plan.
In 2015, 2016 and 2017, awards of phantom units and distribution equivalent rights were granted to employees of the Partnership and its subsidiaries, its general partner and certain employees of CRLLC and CVR Energy who perform services solely for the benefit of the Partnership. The awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the Partnership's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the Partnership from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.
A summary of phantom unit activity and changes under the CVR Refining LTIP during the years ended December 31, 2017, 2016 and 2015 is presented below:
Phantom Units | Weighted- Average Grant-Date Fair Value | Aggregate Intrinsic Value | ||||||||
(in millions) | ||||||||||
Non-vested at December 31, 2014 | 403,947 | $ | 18.89 | $ | 6.8 | |||||
Granted | 302,319 | 20.40 | ||||||||
Vested | (136,531 | ) | 19.26 | |||||||
Forfeited | (58,144 | ) | 18.87 | |||||||
Non-vested at December 31, 2015 | 511,591 | $ | 19.68 | $ | 9.7 | |||||
Granted | 644,148 | 9.43 | ||||||||
Vested | (218,351 | ) | 19.78 | |||||||
Forfeited | (32,533 | ) | 19.13 | |||||||
Non-vested at December 31, 2016 | 904,855 | $ | 12.38 | $ | 9.4 | |||||
Granted | 550,172 | 12.66 | ||||||||
Vested | (349,921 | ) | 13.42 | |||||||
Forfeited | (118,626 | ) | 13.52 | |||||||
Non-vested at December 31, 2017 | 986,480 | $ | 12.03 | $ | 16.3 | |||||
As of December 31, 2017, there was approximately $13.1 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.7 years. Total compensation expense recorded for the years ended December 31, 2017, 2016 and 2015 related to the awards under the CVR Refining LTIP was $7.4 million, $1.8 million and $4.6 million, respectively. As of December 31, 2017 and 2016, the Partnership had a liability of $3.7 million and $1.5 million, respectively, for non-vested phantom unit awards and associated distribution equivalent rights, which is recorded in personnel accruals and accrued expenses and other current liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2017, 2016 and 2015, the Partnership paid cash of $5.1 million, $2.6 million and $3.3 million to settle liability-classified phantom unit awards and associated distribution equivalent rights upon vesting.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In December 2014, CVR Energy granted an award of 227,927 incentive units in the form of SARs to an executive of CVR Energy. In April 2015, the award granted was canceled and replaced by an award of notional units in the form of SARs by CVR Refining pursuant to the CVR Refining LTIP. The replacement award is structured on the same economic and other terms as the incentive unit award and did not result in a material impact. Each SAR vests over three years and entitles the executive to receive a cash payment in an amount equal to the excess of the fair market value of one unit of the Partnership's common units for the first ten trading days in the month prior to vesting over the grant price of the SAR. The fair value will be adjusted to include all distributions declared and paid by the Partnership during the vesting period. The fair value of each SAR is estimated at the end of each reporting period using the Black-Scholes option-pricing model. Assumptions utilized to value the award have been omitted due to immateriality of the award. The SARs vested on December 1, 2017 and the awards had a fair value of zero as of December 31, 2017. Total compensation expense during the years ended December 31, 2017, 2016 and 2015 and the liability related to the SARs as of December 31, 2017 and 2016 were not material.
(4) Inventories
Inventories consisted of the following:
December 31, | |||||||
2017 | 2016 | ||||||
(in millions) | |||||||
Finished goods | $ | 158.3 | $ | 135.8 | |||
Raw materials and precious metals | 107.5 | 89.7 | |||||
In-process inventories | 22.4 | 23.9 | |||||
Parts and supplies | 43.0 | 41.7 | |||||
Total Inventories | $ | 331.2 | $ | 291.1 | |||
(5) Property, Plant and Equipment
Property, plant and equipment consisted of the following:
December 31, | |||||||
2017 | 2016 | ||||||
(in millions) | |||||||
Land and improvements | $ | 29.8 | $ | 29.1 | |||
Buildings | 63.6 | 47.3 | |||||
Machinery and equipment | 2,374.7 | 2,306.0 | |||||
Automotive equipment | 24.3 | 24.2 | |||||
Furniture and fixtures | 10.2 | 9.0 | |||||
Leasehold improvements | 0.8 | 0.8 | |||||
Construction in progress | 44.5 | 41.0 | |||||
2,547.9 | 2,457.4 | ||||||
Less: Accumulated depreciation | 1,069.1 | 942.4 | |||||
Total property, plant and equipment, net | $ | 1,478.8 | $ | 1,515.0 | |||
Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2017, 2016 and 2015 totaled approximately $0.9 million, $5.0 million and $3.7 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $24.8 million at both December 31, 2017 and 2016. Amortization of assets held under capital leases is included in depreciation expense.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(6) Equity Method Investments
VPP Joint Venture
On September 19, 2016, Coffeyville Resources Pipeline, LLC ("CRPLLC"), an indirect wholly-owned subsidiary of CVR Refining, entered into an agreement with Velocity Central Oklahoma Pipeline LLC ("Velocity") related to their joint ownership of Velocity Pipeline Partners, LLC ("VPP"), which is a pipeline company that operates a 12-inch crude oil pipeline with a capacity of approximately 65,000 barrels per day and an estimated length of 25 miles with a connection to the Refining Partnership's Wynnewood refinery and a trucking terminal at Lowrance, Oklahoma. CRPLLC holds a 40% interest in VPP. Velocity holds a 60% interest in VPP and serves as the day-to-day operator of VPP. As of December 31, 2017, the carrying value of CRPLLC's investment in VPP was $6.1 million, which is recorded in equity method investments in affiliates on the Consolidated Balance Sheets. Contributions by CRPLLC to VPP during the pipeline construction totaled $7.0 million, of which $1.4 million was contributed in the first quarter of 2017.
The pipeline commenced operations in mid-April 2017 following completion of construction. Equity income from VPP for the nine months ended December 31, 2017 was $0.2 million, which is recorded in other income, net on the Consolidated Statements of Operations. For the nine months ended December 31, 2017, CRPLLC received cash distributions from VPP of $1.1 million.
Coffeyville Resources Refining & Marketing, LLC ("CRRM") is party to a transportation agreement with VPP for an initial term of 20 years under which VPP provides transportation services to CRRM for crude oil purchased within a defined geographic area, and CRRM entered into a terminalling services agreement with Velocity under which it receives access to Velocity’s terminal in Lowrance, Oklahoma to unload and pump crude oil into VPP's pipeline for an initial term of 20 years. For the nine months ended December 31, 2017, CRRM incurred costs of $1.8 million, under the transportation agreement with VPP. CRRM's crude shipments on the pipeline for the nine months ended December 31, 2017 averaged approximately 16,000 barrels per day. As of December 31, 2017, the Consolidated Balance Sheets included a liability of $0.3 million to VPP.
Midway Joint Venture
On October 31, 2017, subsidiaries of CVR Refining and Plains All American Pipeline, L.P. ("Plains") formed a 50/50 joint venture, Midway Pipeline LLC ("Midway"), which acquired the approximately 100-mile, 16-inch Cushing to Broome pipeline system from Plains. The Cushing to Broome pipeline system connects CVR Refining’s Coffeyville, Kansas, refinery to the Cushing, Oklahoma oil hub. Midway has a contract with Plains pursuant to which Plains will continue its role as operator of the pipeline. In November 2017, we contributed $76.0 million to Midway and for the two months ended December 31, 2017 our equity income from Midway was $0.7 million, which is recorded in other income, net on the Consolidated Statements of Operations. As of December 31, 2017, the carrying value of our investment in Midway was $76.7 million, which is recorded equity method investments in affiliates on the Consolidated Balance Sheets.
For the two months ended December 31, 2017, we incurred costs of $3.0 million with Midway for crude oil transportation services. Crude shipments on the pipeline for the two months ended December 31, 2017 averaged approximately 103,000 barrels per day. As of December 31, 2017, the Consolidated Balance Sheets included a liability of $0.0 million to Midway.
(7) Insurance Claims
On July 29, 2014, the Coffeyville refinery experienced a fire at its isomerization unit. The fire was extinguished, and the refinery was subsequently shut down due to a failure of its plant-wide Distributed Control System, which was directly caused by the fire. This interruption adversely impacted production of refined products for the Partnership in the third quarter of 2014. Total gross repair and other costs recorded related to the incident for the year ended December 31, 2014 were approximately $6.3 million.
The Partnership had property damage insurance policies at the time of the incident, which had an associated deductible of $5.0 million for the Coffeyville refinery. The Partnership received net indemnity of approximately $1.2 million from insurers for this incident in the first quarter of 2016. The insurance indemnity reduced direct operating expenses (exclusive of depreciation and amortization).
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(8) Long-Term Debt
Long-term debt consisted of the following:
December 31, | |||||||
2017 | 2016 | ||||||
(in millions) | |||||||
6.5% Senior Notes, due 2022 | $ | 500.0 | $ | 500.0 | |||
Capital lease obligations | 45.0 | 46.9 | |||||
Total debt | 545.0 | 546.9 | |||||
Unamortized debt issuance costs | (4.4 | ) | (5.4 | ) | |||
Current portion of capital lease obligations | (2.1 | ) | (1.8 | ) | |||
Long-term debt, net of current portion | $ | 538.5 | $ | 539.7 | |||
2022 Senior Notes
On October 23, 2012, CVR Refining, LLC ("Refining LLC") and Coffeyville Finance Inc. ("Coffeyville Finance") completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes are unsecured and fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries on a joint and several basis. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. CVR Energy, CVR Partners, LP ("CVR Partners") and their respective subsidiaries are not guarantors.
The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. On September 17, 2013, Refining LLC and Coffeyville Finance consummated a registered exchange offer, whereby all $500.0 million of the outstanding 2022 Notes were exchanged for an equal principal amount of notes with identical terms that were registered under the Securities Act of 1933. The exchange offer fulfilled the Partnership's obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. The Partnership incurred approximately $0.4 million of debt registration costs related to the registration and exchange offer during the year ended December 31, 2013, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method.
The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.
The indenture governing the 2022 Notes imposes covenants that restrict the Partnership's ability to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of its property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of its assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes are rated investment grade by both Standard & Poor's Financial Services LLC and Moody's Investors Service, Inc. However, such covenants would be reinstituted if the 2022 Notes subsequently lost their investment grade rating. In addition, the indenture contains customary events of default, the occurrence of which would result in, or permit the trustee or the holders of at least 25% of the 2022 Notes to cause, the acceleration of the 2022 Notes, in addition to the pursuit of other available remedies.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The indenture governing the 2022 Notes prohibits the Partnership from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits the Partnership's ability to pay distributions to unitholders. The covenants will apply differently depending on our fixed charge coverage ratio (as defined in the indenture). If the fixed charge coverage ratio is not less than 2.5 to 1.0, the Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, the Partnership will generally be permitted to make restricted payments, including distributions to its unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. The Partnership was in compliance with the covenants as of December 31, 2017, and the ratio was satisfied (not less than 2.5 to 1.0).
Included in other current liabilities on the Consolidated Balance Sheets is accrued interest payable totaling approximately $5.4 million as of both December 31, 2017 and 2016 related to the 2022 Notes. At December 31, 2017, the estimated fair value of the 2022 Notes was approximately $515.0 million. This estimate of fair value is Level 2 as it was determined by quotations obtained from a broker dealer who makes a market in these and similar securities.
Amended and Restated Asset Based (ABL) Credit Facility
On November 14, 2017, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into Amendment No. 1 to the Amended and Restated ABL Credit Agreement (the "Amendment") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amendment amends certain provisions of the Amended and Restated ABL Credit Agreement, dated December 20, 2012, by and among Wells Fargo, the group of lenders party thereto and the Credit Parties (the "Existing Credit Agreement" and as amended by the Amendment, the "Amended and Restated ABL Credit Facility"), which was otherwise schedule to mature on December 20, 2017. The Amended and Restated ABL Credit Facility is scheduled to mature on November 14, 2022.
The Amended and Restated ABL Credit Facility is a $400.0 million asset-based revolving credit facility, with sub-limits for letters of credit and swingline loans of $60.0 million and $40.0 million, respectively. The Amended and Restated ABL Credit Facility also includes a $200.0 million uncommitted incremental facility. The Amended and Restated ABL Credit Facility permits the payment of distributions, subject to the following conditions: (i) no default or event of default exists, (ii) excess availability exceeds 15% of the lesser of the borrowing base and the total commitments and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.00 to 1.00. The Amended and Restated ABL Credit Facility has a five-year maturity and may be used for working capital and other general corporate purposes (including permitted acquisitions).
Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.50% for LIBOR borrowings and (b) 0.50% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.375% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.25% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Partnership is also required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.
The lenders under the Amended and Restated ABL Credit Facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investments and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The Amended and Restated ABL Credit Facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. The Credit Parties were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2017.
In connection with the Amended and Restated ABL Credit Facility, CRLLC and its subsidiaries incurred lender and other third-party costs of approximately $1.6 million for the year ended December 31, 2017, which are being deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. Additionally, in accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $0.1 million of unamortized deferred financing costs associated with the prior ABL credit facility will continue to be amortized over the term of the Amended and Restated ABL credit facility.
As of December 31, 2017, the Partnership had availability under the Amended and Restated ABL Credit Facility of $337.7 million and had letters of credit outstanding of approximately $28.4 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of December 31, 2017. Availability under the Amended and Restated ABL Credit Facility was limited by borrowing base conditions as of December 31, 2017.
Intercompany Credit Facility
On January 23, 2013, prior to the closing of the Initial Public Offering, the Partnership entered into a new $150.0 million senior unsecured revolving credit facility (the "intercompany credit facility") with CRLLC as the lender, to be used to fund growth capital expenditures. The intercompany credit facility is for a term of six years and bears interest at a rate of LIBOR plus 3% per annum, payable quarterly. On October 29, 2014, the Partnership entered into a first amendment to the intercompany credit facility with CRLLC to expand the borrowing capacity to $250.0 million. In conjunction with the Amended and Restated ABL Credit Facility extension in 2017, the Partnership reviewed the needs of the intercompany credit facility and decided to lower the borrowing capacity back to the original level of $150.0 million effective December 1, 2017.
The intercompany credit facility contains covenants that require the Partnership to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of the Partnership's business and financial status as it may reasonably require, including, but not limited to, copies of its unaudited quarterly financial statements and its audited annual financial statements. The Partnership was in compliance with the covenants of the intercompany credit facility as of December 31, 2017.
In addition, the intercompany credit facility contains customary events of default, including, among others, failure to pay any sum payable when due; the occurrence of a default under other indebtedness in excess of $25.0 million; and the occurrence of an event that results in either (i) CRLLC no longer directly or indirectly controlling the general partner, or (ii) CRLLC and its affiliates no longer owning a majority of the Partnership's equity interests. As of December 31, 2017, the Partnership had no borrowings outstanding and $150.0 million was available under the intercompany credit facility.
Deferred Financing Costs
For the years ended December 31, 2017, 2016 and 2015, amortization of deferred financing costs reported as interest expense and other financing costs totaled approximately $1.8 million, $1.9 million and $1.9 million, respectively.
Capital Lease Obligations
CVR Refining maintains two leases, accounted for as a capital lease and a financial obligation, which related to Magellan Pipeline Terminals, L.P. ("Magellan Pipeline") and Excel Pipeline LLC ("Excel Pipeline"). The underlying assets and related depreciation are included in property, plant and equipment. The capital lease, which relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline, has 142 months remaining of its term and will expire in September 2029. The financing arrangement, which relates to the Magellan Pipeline terminals, bulk terminal and loading facility, has 141 months remaining of its lease term and will expire in September 2029. As of December 31, 2017, the outstanding obligation associated with these arrangements totaled approximately $45.0 million, of which $42.9 million is included in long-term liabilities and $2.1 million is included in current liabilities in the Consolidated Balance Sheets.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Future payments required under capital lease at December 31, 2017 are as follows:
Year Ending December 31, | Capital Lease | ||
(in millions) | |||
2018 | $ | 6.5 | |
2019 | 6.5 | ||
2020 | 6.5 | ||
2021 | 6.5 | ||
2022 | 6.5 | ||
Thereafter | 44.2 | ||
Total future payments | 76.7 | ||
Less: amount representing interest | 31.7 | ||
Present value of future minimum payments | 45.0 | ||
Less: current portion | 2.1 | ||
Long-term portion | $ | 42.9 | |
(9) Partners’ Capital and Partnership Distributions
The Partnership had two types of partnership interests outstanding at December 31, 2017:
• | common units; and |
• | a general partner interest, which is not entitled to any distributions, and which is held by the general partner. |
At both December 31, 2017 and 2016, the Partnership had a total of 147,600,000 common units issued and outstanding, of which 97,315,764 common units were owned by CVR Refining Holdings representing approximately 66% of the total Partnership common units outstanding.
The board of directors of the Partnership's general partner has adopted a policy for the Partnership to distribute all available cash generated on a quarterly basis. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for distribution for each quarter will be determined by the board of directors of the general partner following the end of such quarter. Available cash for distribution for each quarter will generally equal Adjusted EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of the general partner deems necessary or appropriate, if any. Adjusted EBITDA represents EBITDA (net income before interest expense and other financing costs, net of interest income; income tax expense; and depreciation and amortization) adjusted for (i) FIFO impact (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses (that many of our competitors capitalize and thereby exclude from their measures of EBITDA and adjusted EBITDA), (v) (gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) flood insurance recovery. Available cash for distribution may be increased by the release of previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of the general partner. The board of directors of the general partner does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in the Partnership's quarterly distribution or to otherwise reserve cash for distributions, nor does the board of directors of the general partner intend to incur debt to pay quarterly distributions. Further, it is the intent of the board of directors of the general partner, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified potential future needs. The board of directors of the general partner may modify the cash distribution policy at any time, and the partnership agreement does not require the board of directors of the general partner to make distributions at all.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On October 31, 2017, the board of directors of the Partnership's general partner declared a cash distribution to the Partnership's unitholders of $0.94 per common unit. The distribution included amounts paid to CVR Refining Holdings and affiliates was $96.9 million and amounts paid to non-affiliates were $41.8 million, respectively, or $138.7 million in aggregate. No distributions were paid during 2016.
(10) Net Income per Common Unit
The Partnership's net income is allocated wholly to the common units as the general partner does not have an economic interest. Basic and diluted net income per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period and, when applicable, giving effect to unvested common units granted under the CVR Refining LTIP. There were no dilutive awards outstanding during the years ended December 31, 2017, 2016 or 2015 as all unvested awards under the CVR Refining LTIP were liability-classified awards.
The following table illustrates the Partnership's calculation of net income per common unit for the years ended December 31, 2017, 2016 and 2015:
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions, except per unit data) | |||||||||||
Net income | $ | 88.8 | $ | 15.3 | $ | 291.2 | |||||
Net income per common unit, basic and diluted | $ | 0.60 | $ | 0.10 | $ | 1.97 | |||||
Weighted-average common units outstanding, basic and diluted | 147.6 | 147.6 | 147.6 | ||||||||
(11) Benefit Plans
A subsidiary of CVR Energy sponsors and administers two defined-contribution 401(k) plans, the CVR Energy 401(k) Plan and the CVR Energy 401(k) Plan for Represented Employees (the "Plans"), in which employees of the general partner, CVR Refining and its subsidiaries may participate. Participants in the Plans may elect to contribute a designated percentage of their eligible compensation in accordance with the Plans, subject to statutory limits. The Partnership provides a matching contribution of 100% of the first 6% of eligible compensation contributed by participants. Contributions for the represented plan are determined in accordance with provisions of negotiated labor contracts. Participants in both Plans are immediately vested in their individual contributions. Both Plans provide for a three-year vesting schedule for the Partnership's matching contributions and contain a provision to count service with predecessor organizations. The Partnership's contributions under the Plans for employees of CVR Refining were approximately $5.6 million, $5.5 million and $5.2 million for the years ended December 31, 2017, 2016 and 2015, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(12) Commitments and Contingencies
The minimum required payments for CVR Refining's operating lease agreements and unconditional purchase obligations are as follows:
Year Ending December 31, | Operating Leases | Unconditional Purchase Obligations(1) | |||||
(in millions) | |||||||
2018 | $ | 0.6 | $ | 140.7 | |||
2019 | 0.4 | 113.5 | |||||
2020 | 0.1 | 96.9 | |||||
2021 | 0.1 | 87.7 | |||||
2022 | — | 82.7 | |||||
Thereafter | 0.2 | 540.2 | |||||
$ | 1.4 | $ | 1,061.7 | ||||
(1) | This amount includes approximately $698.6 million payable ratably over 13 years pursuant to petroleum transportation service agreements between CRRM and each of TransCanada Keystone Pipeline Limited Partnership and TransCanada Keystone Pipeline, LP (together "TransCanada"). The purchase obligation reflects the exchange rate between the Canadian dollar and the U.S. dollar as of December 31, 2017, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of 20 years on TransCanada's Keystone pipeline system. |
CVR Refining leases equipment, including railcars and real properties, under long-term operating leases expiring at various dates through 2035. For the years ended December 31, 2017, 2016 and 2015, lease expense totaled approximately $0.9 million, $1.3 million and $1.7 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR Refining's option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.
Additionally, in the normal course of business, CVR Refining has long-term commitments to purchase storage capacity and pipeline transportation services. For the years ended December 31, 2017, 2016 and 2015, total expense of $146.4 million, $129.1 million and $125.0 million, respectively, was incurred related to long-term commitments.
Crude Oil Supply Agreement
On August 31, 2012, CRRM and Vitol Inc. ("Vitol"), entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Partnership's inventory position and mitigate crude oil pricing risk. The Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term. The Vitol Agreement currently extends through December 31, 2018.
Litigation
From time to time, CVR Refining is involved in various lawsuits arising in the normal course of business, including matters such as those described below under "Environmental, Health, and Safety ("EHS") Matters." Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. It is possible that management's estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management's beliefs or opinions with respect to liability for potential litigation matters will prove to be accurate.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The U.S. Attorney’s office for the Southern District of New York contacted CVR Energy in September 2017 seeking production of information pertaining to our, CVR Energy’s and Mr. Carl C. Icahn’s activities relating to the RFS and Mr. Icahn’s role as an advisor to the President. We are cooperating with the request and are providing information in response to the subpoena. The U.S. Attorney’s office has not made any claims or allegations against us or Mr. Icahn. We maintain a strong compliance program and, while no assurances can be made, we do not believe this inquiry will have a material impact on our business, financial condition, results of operations or cash flows.
Flood, Crude Oil Discharge and Insurance
Crude oil was discharged from CRRM's Coffeyville refinery on July 1, 2007, due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. On October 25, 2010, CRRM received a letter from the United States Coast Guard on behalf of the U.S. Environmental Protection Agency ("EPA") seeking approximately $1.8 million in oversight cost reimbursement. CRRM responded by asserting defenses to the Coast Guard's claim for oversight costs. On September 23, 2011, the United States Department of Justice ("DOJ"), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act's Risk Management Program ("RMP"), the Clean Water Act ("CWA") and the Oil Pollution Act of 1990 ("OPA"). CRRM reached an agreement with the DOJ resolving its claims under CWA and OPA. The agreement was memorialized in a Consent Decree that was filed with and approved by the Court on February 12, 2013 and March 25, 2013, respectively (the "2013 Consent Decree"). On April 19, 2013, CRRM paid a civil penalty (including accrued interest) in the amount of $0.6 million related to the CWA claims and reimbursed the Coast Guard for oversight costs under OPA in the amount of $1.7 million. The 2013 Consent Decree also requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training, all of which have been completed.
The parties also reached an agreement to settle DOJ's claims related to the alleged non-compliance with RMP. The agreement was memorialized in a separate consent decree that was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively (the "RMP Consent Decree"), and provided for a civil penalty of $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP claims. CRRM has completed the implementation of the recommendations of several audits required by the RMP Consent Decree, which were related to compliance with RMP requirements.
CRRM sought insurance coverage for the crude oil release and for the ultimate costs for remediation and third-party property damage claims. On July 10, 2008, CRRM filed a lawsuit in the United States District Court for the District of Kansas against certain of its environmental insurance carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. The Court issued summary judgment opinions that eliminated the majority of the insurance defendants' reservations and defenses. CRRM has received $25.0 million of insurance proceeds under its primary environmental liability insurance policy, which constitutes full payment of the primary pollution liability policy limit. During the second quarter of 2015, CRRM entered into a settlement agreement and release with the insurance carriers involved in the lawsuit, pursuant to which (i) CRRM received settlement proceeds of approximately $31.3 million, (ii) the parties mutually released each other from all claims relating to the flood and crude oil discharge and (iii) all pending appeals have been dismissed. Of the settlement proceeds received, $27.3 million were recorded as a flood insurance recovery in the Consolidated Statements of Operations for the year ended December 31, 2015. The remaining $4.0 million of settlement proceeds reduced CVR Refining's $4.0 million receivable related to this matter, which had been included in other assets on the Consolidated Balance Sheets as of December 31, 2014.
Environmental, Health, and Safety ("EHS") Matters
CRRM, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Coffeyville Resources Terminal, LLC ("CRT") and Wynnewood Refining Company, LLC ("WRC") are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CRRM, CRCT, CRT and WRC own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution. Therefore, CRRM, CRCT, CRT and WRC have exposure to potential EHS liabilities related to past and present EHS conditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, OPA generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States, which has been broadly interpreted to include most water bodies including intermittent streams.
CRRM, CRCT, CRT and WRC are subject to extensive and frequently changing federal, state and local environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water and the storage, handling, use and transportation of petroleum and the characteristics and composition of gasoline and diesel fuels. The ultimate impact of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that the Partnership's operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.
On August 1, 2016, CRCT received a Notice of Probable Violation, Proposed Civil Penalty and Proposed Compliance Order (the "NOPV") from the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (the "PHMSA"). The NOPV alleges violations of the Pipeline Safety Regulations, Title 49, Code of Federal Regulations. The alleged violations include alleged failures (during various time periods) to (i) conduct quarterly notification drills, (ii) maintain certain required records, (iii) utilize certain required safety equipment (including line markers), (iv) take certain pipeline integrity management activities, (v) conduct certain cathodic protection testing, and (vi) make certain atmospheric corrosion inspections. The preliminary assessed civil penalty is approximately $0.5 million and the NOPV contained a compliance order outlining remedial compliance steps to be undertaken by CRCT. CRCT paid approximately $0.2 million of the preliminary assessed civil penalty in September 2016, and contested and requested mitigation of the remainder, and also requested reconsideration of the proposed compliance order. In November 2017, CRCT received a final order from PHMSA assessing a revised civil penalty of approximately $0.5 million. CRCT paid the remaining $0.3 million in civil penalty and has completed all items required by the compliance order.
CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-20 and Docket No. VII-95-H-11, respectively). WRC and the Oklahoma Department of Environmental Quality ("ODEQ") have entered into a Consent Order (Case No. 15-056) to resolve certain legacy environmental issues related to historical groundwater contamination and the operation of a wastewater conveyance. As of December 31, 2017 and 2016, environmental accruals of approximately $3.9 million and $4.8 million, respectively, were reflected in the Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the ODEQ Consent Order, for which approximately $1.3 million and $0.2 million, respectively, are included in other current liabilities. Accruals were determined based on an estimate of payment costs through 2026, for which the scope of remediation was arranged with the EPA and ODEQ, and were discounted at the appropriate risk free rates at December 31, 2017 and 2016, respectively. The accruals include estimated closure and post-closure costs of approximately $0.4 million for two landfills at December 31, 2017 and 2016.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The estimated future payments for these required obligations are as follows:
Year Ending December 31, | Amount | ||
(in millions) | |||
2018 | $ | 2.9 | |
2019 | 1.1 | ||
2020 | — | ||
2021 | — | ||
2022 | — | ||
Thereafter | — | ||
Undiscounted total | 4.0 | ||
Less amounts representing interest at 1.98% | 0.1 | ||
Accrued environmental liabilities at December 31, 2017 | $ | 3.9 | |
Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.
Tier 3 Motor Vehicle Emission and Fuel Standards
In April 2014, the EPA promulgated the Tier 3 Motor Vehicle Emission and Fuel Standards, which will require that gasoline contain no more than ten parts per million of sulfur on an annual average basis. Refineries were required to be in compliance with the more stringent emission standards as of January 1, 2017; however, compliance with the rule was extended until January 1, 2020 for approved small volume refineries and small refiners. In March 2015, the EPA approved the Wynnewood refinery's application requesting "small volume refinery" status. In June 2016, because it exceeded the EPA’s specified throughput limit for a “small volume refinery.” the Wynnewood refinery became disqualified as a “small volume refinery.” Therefore, the Wynnewood refinery’s compliance deadline was accelerated to December 21, 2018. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the new standard.
Renewable Fuel Standards
CVR Refining is subject to the Renewable Fuel Standard ("RFS") which requires refiners to either blend "renewable fuels" in with their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. transportation fuel market, there may be a decrease in demand for petroleum products. CVR Refining is not able to blend the substantial majority of its transportation fuels and has to purchase RINs on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS.
The cost of RINs has been extremely volatile as the EPA's renewable fuel volume mandates approached and exceeded the "blend wall." The blend wall refers to the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume is blended into transportation fuel.
In December 2015, 2016 and 2017, the EPA published in the Federal Register final rules establishing the renewable fuel volume mandates for 2016, 2017 and 2018, and the biomass-based diesel volume mandates for 2017, 2018 and 2019, respectively. The volumes included in the EPA's final rule increase each year, but are lower, with the exception of the volumes for biomass-based diesel, than the volumes required by the Clean Air Act. The EPA used its waiver authorities to lower the volumes in each rulemaking, but its decision to do so for the 2014-2016 compliance years was challenged in the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit"). In a July 2017 decision, the D.C. Circuit rejected all challenges to the 2014-2016 compliance years rule except for one, vacated the EPA’s decision to reduce the total renewable fuel volume requirements for 2016 through use of its “inadequate domestic supply” waiver authority, and remanded the rule to the EPA for further consideration. The EPA has not yet proposed a new rule establishing the volume requirements for 2016 following the D.C. Circuit’s opinion. In addition to establishing the renewable volume obligations, the EPA has articulated a policy that high RINs prices incentivize additional investments in renewable fuel blending and distribution infrastructure.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RINs expense for the years ended December 31, 2017, 2016 and 2015 was approximately $249.0 million, $205.9 million and $123.9 million, respectively. As of December 31, 2017 and 2016, CVR Refining's biofuel blending obligation was approximately $28.3 million and $186.2 million, respectively, which is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets. The price of RINs has been extremely volatile over the last year. The future cost of RINs for the petroleum business is difficult to estimate. Additionally, the cost of RINs is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed at its refineries and downstream terminals, all of which can vary significantly from period to period.
Coffeyville Second Consent Decree
In March 2004, CRRM and CRT entered into a Consent Decree (the "2004 Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.'s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 Consent Decree, CRRM agreed to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its fluid catalytic cracking unit ("FCCU") by January 1, 2011. In addition, pursuant to the 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities.
In March 2012, CRRM entered into a second consent decree (the "Second Consent Decree") with the EPA and KDHE, which replaced the 2004 Consent Decree (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012. The Second Consent Decree gave CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a "global settlement" under the EPA's "National Petroleum Refining Initiative." Under the National Petroleum Refining Initiative, the EPA alleged industry-wide non-compliance with four "marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants ("NESHAP"). The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 95% of the U.S. refining capacity) entering into consent decrees requiring the payment of civil penalties and the installation of air pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, CRRM was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. In March 2016, the United States District Court for the District of Kansas approved a modification to the Second Consent Decree memorializing an agreement with the EPA and KDHE to modify provisions in the Second Consent Decree relating to the installation of controls to reduce air emissions of sulfur dioxide from the refinery's FCCU. Pursuant to the terms of the modification, CRRM is permitted to use alternative means of control to those currently specified in the Second Consent Decree provided it can meet the limits specified in the modification. The additional incremental capital expenditures associated with the Second Consent Decree are expected to be approximately $0.7 million.
RCRA Compliance Matters
In January 2014, the EPA issued an inspection report to the Wynnewood refinery related to a RCRA compliance evaluation inspection conducted in March 2013. In February 2014, ODEQ notified WRC that it concurred with the EPA's inspection findings and would be pursuing enforcement. WRC and ODEQ entered into a Consent Order in June 2015 resolving all alleged non-compliance associated with the RCRA compliance evaluation inspection, as well as issues related to possible soil and groundwater contamination associated with the prior owner's operation of the refinery. The Consent Order requires WRC to take certain corrective actions, including specified groundwater remediation and monitoring measures pursuant to a work plan and replacement of a wastewater conveyance to be approved by ODEQ. ODEQ approved the work plan submitted by WRC on February 1, 2016 and the replacement of a wastewater conveyance on August 15, 2016. WRC is in the process of implementing the specified groundwater remediation and monitoring measures. The costs of complying with the Consent Order are estimated to be approximately $4.2 million.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the years ended December 31, 2017, 2016 and 2015, capital expenditures were approximately $15.1 million, $17.2 million and $34.7 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CRRM, CRCT, CRT and WRC each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.
Wynnewood Refinery Incident
On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit during startup after a short outage as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler. Additionally, there was no environmental impact. The refinery was in the final stages of shutdown for turnaround maintenance at the time of the incident. WRC completed an internal investigation of the incident and cooperated with the Occupational Safety and Health Administration ("OSHA") in its investigation. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its Severe Violators Enforcement Program ("SVEP"). WRC is vigorously contesting the citations and OSHA's placement of WRC in the SVEP. Any penalties associated with OSHA's citations are not expected to have a material adverse effect on the consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(13) Fair Value Measurements
In accordance with FASB ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820"), the Partnership utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets or liabilities, such as a business.
ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
• | 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) |
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of December 31, 2017 and 2016:
December 31, 2017 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(in millions) | |||||||||||||||
Location and Description | |||||||||||||||
Other current liabilities (derivative agreements) | $ | — | $ | (64.3 | ) | $ | — | $ | (64.3 | ) | |||||
Other current liabilities (biofuel blending obligation) | — | (1.0 | ) | — | (1.0 | ) | |||||||||
Total Liabilities | $ | — | $ | (65.3 | ) | $ | — | $ | (65.3 | ) | |||||
December 31, 2016 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(in millions) | |||||||||||||||
Location and Description | |||||||||||||||
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 | ) | |||||
As of December 31, 2017 and 2016, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining's derivative instruments, uncommitted biofuel blending obligation and benzene obligations. Additionally, the fair value of the debt issuances is disclosed in Note 8 ("Long-Term Debt"). The commodity derivative contracts, the uncommitted biofuel blending obligation and the benzene obligation, which use fair value measurements and are valued using broker quoted market prices of similar instruments, are considered Level 2 inputs. CVR Refining had no transfers of assets or liabilities between any of the above levels during the year ended December 31, 2017.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(14) Derivative Financial Instruments
Current period settlements on derivative contracts and Loss on derivatives, net were as follows:
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Current period settlements on derivative contracts | $ | (16.6 | ) | $ | 36.4 | $ | (26.0 | ) | |||
Gain (loss) on derivatives, net | (69.8 | ) | (19.4 | ) | (28.6 | ) | |||||
CVR Refining is subject to price fluctuations caused by supply conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR Refining from time to time enters into various commodity derivative transactions.
CVR Refining has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR Refining holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges under GAAP. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Consolidated Statements of Operations. There are no premiums paid or received at inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts.
CVR Refining maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Consolidated Balance Sheets. Dependent upon the position of the open commodity derivatives, the amounts are accounted for as other current assets or other current liabilities within the Consolidated Balance Sheets. From time to time, CVR Refining may be required to deposit additional funds into this margin account. There were no open commodity positions as of December 31, 2017 or 2016. For the years ended December 31, 2017, 2016 and 2015, CVR Refining recognized a net loss of $0.5 million, a net loss of $0.5 million and a net gain of $3.2 million, respectively, which are recorded in loss on derivatives, net in the Consolidated Statements of Operations.
Commodity Swaps
CVR Refining enters into commodity swap contracts in order to fix the margin on a portion of future production. Additionally, CVR Refining may enter into price and basis swaps in order to fix the price on a portion of its commodity purchases and product sales. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Consolidated Balance Sheets with changes in fair value currently recognized in the Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At December 31, 2017, CVR Refining had open commodity swap instruments consisting of 7.1 million barrels of 2-1-1 crack spreads, 3.6 million barrels of distillate crack spreads, and 3.6 million barrels of gasoline crack spreads. Additionally, as of December 31, 2017, CVR Refining had open forward purchase and sale commitments for 5.8 million barrels of Canadian crude oil priced at fixed differentials that are not considered probable of physical settlement and are accounted for as derivatives at December 31, 2017. As of December 31, 2016, CVR Refining had open commodity hedging instruments consisting of 4.0 million barrels of crack spreads primarily to fix the margin on a portion of its future gasoline and distillate production. Additionally, at December 31, 2015, CVR Refining had open commodity hedging instruments consisting of 1.4 million barrels primarily to fix the price on a portion of its future crude oil purchases or the basis on a portion of its future product sales. The fair value of the outstanding contracts at December 31, 2017 was a net unrealized loss of $64.3 million, of which the entire balance is included in other current liabilities. The fair value of the outstanding contracts at December 31, 2016 was a net unrealized loss of $11.1 million, of which the entire balance is included in other current liabilities. For the years ended December 31, 2017, 2016 and 2015, the Partnership recognized a net loss of $69.3 million, $18.9 million and $36.4 million, respectively, which are recorded in loss on derivatives, net in the Consolidated Statements of Operations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Counterparty Credit Risk
CVR Refining's exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. CVR Refining manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. CVR Refining also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Consolidated Balance Sheets. As of December 31, 2017, the counterparty credit risk adjustment was not material to the consolidated financial statements. Additionally, CVR Refining does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.
Offsetting Assets and Liabilities
The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which CVR Refining has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by CVR Refining. As a result of the right to setoff, CVR Refining's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Consolidated Balance Sheets. The tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Consolidated Balance Sheets for the various types of open derivative positions.
The offsetting assets and liabilities for CVR Refining's derivatives as of December 31, 2017 and 2016 are recorded as current assets and current liabilities in prepaid expenses and other current assets and accrued expenses and other current liabilities, respectively, in the Consolidated Balance Sheets as follows:
As of December 31, 2017 | |||||||||||||||||||
Description | Gross Current Assets | Gross Amounts Offset | Net Current Assets Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 7.0 | $ | (7.0 | ) | $ | — | $ | — | $ | — | ||||||||
Total | $ | 7.0 | $ | (7.0 | ) | $ | — | $ | — | $ | — | ||||||||
As of December 31, 2017 | |||||||||||||||||||
Description | Gross Current Liabilities | Gross Amounts Offset | Net Current Liabilities Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 71.3 | $ | (7.0 | ) | $ | 64.3 | $ | — | $ | 64.3 | ||||||||
Total | $ | 71.3 | $ | (7.0 | ) | $ | 64.3 | $ | — | $ | 64.3 | ||||||||
As of December 31, 2016 | |||||||||||||||||||
Description | Gross Current Liabilities | Gross Amounts Offset | Net Current Liabilities Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 11.1 | $ | — | $ | 11.1 | $ | — | $ | 11.1 | |||||||||
Total | $ | 11.1 | $ | — | $ | 11.1 | $ | — | $ | 11.1 | |||||||||
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(15) Related Party Transactions
CVR Refining and CRRM are party to, or otherwise subject to certain agreements with CVR Energy and its subsidiaries (including CVR Partners and its subsidiary Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF")) that govern the business relationships among each party. The agreements are described as in effect at December 31, 2017.
Amounts owed to CVR Refining and CRRM from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable and prepaid expenses and other current assets on the Consolidated Balance Sheets. Conversely, amounts owed to CVR Energy and its subsidiaries by CVR Refining and CRRM with respect to these agreements are included in accounts payable, personnel accruals, accrued expenses and other current liabilities, long-term debt and other long-term liabilities, on CVR Refining's Consolidated Balance Sheets.
Feedstock and Shared Services Agreement
CRRM is party to a feedstock and shared services agreement with CRNF, under which the two parties provide feedstocks and other services to one another. These feedstocks and services are utilized in the respective production processes of CRRM's Coffeyville, Kansas refinery and CRNF's Coffeyville, Kansas nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas. The agreement was amended and restated effective January 1, 2017.
Prior to January 1, 2017, CRRM and CRNF transferred hydrogen to one another pursuant to the Feedstock and Shared Services Agreement. Net monthly sales of hydrogen to CRNF have been reflected as net sales for CVR Refining. Net monthly receipts of hydrogen from CRNF have been reflected in cost of materials and other for CVR Refining, when applicable. For the year ended December 31, 2016, the gross sales of hydrogen to CRNF were approximately $0.2 million and a nominal amount for the year ended December 31, 2015. For the years ended December 31, 2016 and 2015, CVR Refining recognized $3.2 million and $11.8 million, respectively, of cost of materials and other related to the net purchases of hydrogen from the Coffeyville fertilizer facility. At December 31, 2016, there was approximately $0.1 million of accounts receivable included in prepaid expenses and other current assets on the Consolidated Balance Sheet associated with hydrogen sales.
Beginning January 1, 2017, hydrogen sales to CRNF are governed pursuant to the hydrogen purchase and sales agreement discussed below, but hydrogen purchases from CRNF remain governed pursuant to the feedstock and shared services agreement. For the year ended December 31, 2017, the gross purchases of hydrogen from CRNF pursuant to the feedstock and shared services agreement were approximately $0.4 million and were included in cost of materials and other in the Consolidated Statements of Operations. The monthly hydrogen purchases are cash settled net on a monthly basis with hydrogen sales, pursuant to the hydrogen purchase and sale agreement.
Prior to November 1, 2017, the feedstock and shared services agreement provided a mechanism pursuant to which CRNF transferred a tail gas stream to CRRM. For the years ended December 31, 2017, 2016 and 2015 CRRM recognized a nominal amount of direct operating expenses generated from the purchase of tail gas from CRNF. In April 2011, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF paid CRRM the cost of installing the pipe and provided an additional 15% to cover the cost of capital, which was due from CRNF to CRRM over four years.
Effective November 1, 2017, the feedstock and shared services agreement was amended to provide a mechanism to transfer a natural gas stream from CRRM to CRNF, and CRNF will no longer transfer tail gas to CRRM. The pipe previously used for the transfer of tail gas was altered to exclusively allow for the transportation of natural gas. CRRM will nominate and purchase natural gas transportation and natural gas supplies for CRNF in exchange for a nominal fee.
At December 31, 2016, a liability of approximately $0.2 million was included in accrued expenses and other current liabilities. Additionally, at December 31, 2017 there was no liability included in other long term-liabilities in the Consolidated Balance Sheets and in December 31, 2016, a liability of approximately $0.6 million was included in other long term-liabilities in the Consolidated Balance Sheets.
At December 31, 2017 and 2016, payables of approximately $0.2 million and $0.3 million, respectively, were included in accounts payable on the Consolidated Balance Sheets associated with amounts yet to be paid related to components of the feedstock and shared services agreement, other than amounts associated with hydrogen purchases and tail gas discussed above.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At December 31, 2017 and 2016, receivables of approximately $1.0 million and $0.9 million, respectively, were included in prepaid expenses and other current assets on the Consolidated Balance Sheets associated with receivables related to components of the feedstock and shared services agreement.
Hydrogen Purchase and Sale Agreement
CRRM and CRNF entered into a hydrogen purchase and sale agreement that was effective on January 1, 2017, pursuant to which CRRM agrees to sell and deliver a committed hydrogen volume of 90,000 mscf per month, and CRNF agrees to purchase and receive the committed volume. The committed volume pricing is based on a monthly fixed fee (based on the fixed and capital charges associated with producing the committed volume) and a monthly variable fee (based on the natural gas price associated with hydrogen actually received). In the event CRNF fails to take delivery of the full committed volume in a month, CRNF remains obligated to pay CRRM for the monthly fixed fee and a monthly variable fee based upon the actual hydrogen volume received, if any. In the event CRRM fails to deliver any portion of the committed volume for the applicable month for any reason other than planned repairs and maintenance, CRNF will be entitled to a pro-rata reduction of the monthly fixed fee. CRNF also has the option to purchase excess volume of up to 60,000 mscf per month, or more upon mutual agreement, from CRRM, if available for purchase.
A portion of the monthly variable fee, as defined in the terms of the agreement, is determined according to the natural gas costs incurred by CRRM in operation of the hydrogen plant, which will reflect market-driven changes in the natural gas prices. In addition, certain fixed fees will be adjusted on an annual basis according to the changes in a cost index, as defined in the terms of the agreement.
CRRM is not required to sell hydrogen to CRNF if such sale would adversely affect CVR Refining’s classification as a partnership for federal income tax purposes, and is not required to sell hydrogen to CRNF in excess of the committed volume if such volumes are needed for CRRM’s operations.
The agreement has an initial term of 20 years and will be automatically extended following the initial term for additional successive five-year renewal terms unless either party gives 180 days' written notice. Certain fees under the agreement are subject to modification after this initial term. The agreement contains customary terms related to indemnification, as well as termination for breach, by mutual consent, or due to insolvency or cessation of operations.
For the year ended December 31, 2017, the gross sales of hydrogen to CRNF were approximately $4.2 million. The monthly hydrogen sales are cash settled net with hydrogen purchases pursuant to the feedstock and shared services agreement. At December 31, 2017, approximately $0.3 million was included in accounts receivables on the Consolidated Balance Sheets associated with the net hydrogen sales to CRNF.
Coke Supply Agreement
CRRM is party to a coke supply agreement with CRNF pursuant to which CRRM supplies CRNF with pet coke. This agreement provides that CRRM must deliver to CRNF during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100% of the pet coke produced at CRRM's Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CRNF is also obligated to purchase this annual required amount. If during a calendar month CRRM produces more than 41,667 tons of pet coke, then CRNF will have the option to purchase the excess at the purchase price provided for in the agreement. If CRNF declines to exercise this option, CRRM may sell the excess to a third party.
The price CRNF pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for urea ammonium nitrate ("UAN") (the "UAN-based price") or a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN that excludes transportation cost ("netback price") of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.
CRNF pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. Amounts payable under the feedstock and shared services agreements can be offset with any amount receivable for pet coke.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The agreement has an initial term of 20 years, ending in 2027, and will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable for breach, by mutual consent, or due to insolvency or cessation of operation.
Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $2.0 million, $1.8 million and $6.8 million for the years ended December 31, 2017, 2016 and 2015, respectively. Receivables of approximately $0.1 million related to the coke supply agreement were included in accounts receivable on the Consolidated Balance Sheets for both December 31, 2017 and 2016.
Environmental Agreement
CRRM entered into an environmental agreement with CRNF which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville, Kansas refinery and the nitrogen fertilizer plant. Generally, both CRRM and CRNF have agreed to indemnify and defend each other and each other's affiliates against liabilities associated with certain hazardous materials and violations of environmental laws that are a result of or caused by the indemnifying party's actions or business operations. This obligation extends to indemnification for liabilities arising out of off-site disposal of certain hazardous materials. Indemnification obligations of the parties will be reduced by applicable amounts recovered by an indemnified party from third parties or from insurance coverage.
The term of the agreement is for at least 20 years, ending in 2027, or for so long as the feedstock and shared services agreement is in force, whichever is longer.
Services Agreement
CVR Refining obtains certain management and other services from CVR Energy pursuant to a services agreement between the Partnership, CVR Refining GP and CVR Energy. Under this agreement, the Partnership's general partner has engaged CVR Energy to provide certain services, including the following, among others:
• | 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. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As payment for services provided under the agreement, the Partnership, its general partner or subsidiaries must pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees who provide the Partnership services under the agreement on a full-time basis, but excluding certain share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees who provide the Partnership services under the agreement on a part-time basis, but excluding certain share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percentage of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges.
Either CVR Energy or the Partnership's general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days' notice. CVR Energy or the Partnership's general partner may terminate the agreement upon at least 180 days' notice, but not more than one year's notice. Furthermore, the Partnership's general partner may terminate the agreement immediately if CVR Energy becomes bankrupt or dissolves or commences liquidation or winding-up procedures.
In order to facilitate the carrying out of services under the agreement, CVR Refining and CVR Energy have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another's intellectual property under certain circumstances.
The agreement also contains an indemnity provision whereby the Partnership, its general partner, and our subsidiaries, as indemnifying parties, agree to indemnify CVR Energy and its affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by CVR Energy or other misconduct on its part, as provided in the agreement. The agreement contains a provision stating that CVR Energy is an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by CVR Energy, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from CVR Energy or certain affiliates.
Net amounts incurred under the services agreement for the years ended December 31, 2017, 2016 and 2015 were as follows:
Year Ended December 31, | |||||||||||
2017 | 2016 | 2015 | |||||||||
(in millions) | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | $ | 11.8 | $ | 13.0 | $ | 18.1 | |||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 50.0 | 49.2 | 53.2 | ||||||||
Total | $ | 61.8 | $ | 62.2 | $ | 71.3 | |||||
At December 31, 2017 and 2016, payables and liabilities of $14.0 million and $11.9 million, respectively, were included in accounts payable, personnel accruals and accrued expenses and other current liabilities on the Consolidated Balance Sheets with respect to amounts billed in accordance with the services agreement.
Limited Partnership Agreement
In connection with the Initial Public Offering, CVR Refining GP and CVR Refining Holdings entered into the first amended and restated agreement of limited partnership of the Partnership, dated January 23, 2013.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Partnership's general partner manages the Partnership's operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. CVR Refining Holdings has the right to select the directors of the general partner. Actions by the general partner that are made in its individual capacity are made by CVR Refining Holdings as the sole member of the general partner and not by its board of directors. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to re-election on a regular basis by the unitholders. The officers of the general partner manage the day-to-day affairs of the Partnership's business.
The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person to perform services for the Partnership or for its general partner in connection with operating the Partnership). For the years ended December 31, 2017, 2016 and 2015 approximately $9.7 million, $6.9 million and $9.1 million were incurred under the partnership agreement, respectively.
Intercompany Credit Facility
On January 23, 2013, prior to the closing of the Initial Public Offering, the Partnership entered into a $150.0 million intercompany credit facility, with CRLLC as the lender, to be used to fund growth capital expenditures. On October 29, 2014, the Partnership entered into a first amendment to the intercompany credit facility with CRLLC to expand the borrowing capacity to $250.0 million. The intercompany credit facility is for a term of six years and bears interest at a rate of LIBOR plus 3% per annum. In conjunction with the Amended and Restated ABL Credit Facility extension in 2017, the Partnership reviewed the needs of the intercompany credit facility and decided to lower the borrowing capacity back to the original level of $150.0 million effective December 1, 2017.
As of December 31, 2017 and 2016, the Partnership had no borrowings outstanding. For the years ended December 31, 2017, 2016 and 2015, the Partnership paid $0.0 million, $1.0 million and $1.0 million of interest to CRLLC. See Note 8 ("Long-Term Debt") for additional discussion of the intercompany credit facility.
Insight Portfolio Group
Insight Portfolio Group LLC ("Insight Portfolio Group") is an entity formed by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013, CVR Energy acquired a minority equity interest in Insight Portfolio Group. The Partnership participates in Insight Portfolio Group's buying group through its relationship with CVR Energy. The Partnership may purchase a variety of goods and services as members of the buying group at prices and on terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.
Joint Venture Agreements
The partnership holds a 40% and 50% interest in the VPP and Midway joint ventures, respectively. The joint ventures provide the Partnership with crude oil transportation services. See Note 6 ("Equity Method Investments") for additional discussion of the joint ventures.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(16) Major Customers and Suppliers
Sales to major customers were as follows:
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Customer A | 19 | % | 15 | % | 14 | % | ||
CRRM obtained crude oil from one third-party supplier under a long-term supply agreement during 2017, 2016 and 2015. Volume contracted as a percentage of the total crude oil purchases (in barrels) for each of the periods was as follows:
Year Ended December 31, | ||||||||
2017 | 2016 | 2015 | ||||||
Supplier A | 55 | % | 61 | % | 61 | % | ||
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(17) Selected Quarterly Financial Information (unaudited)
Summarized quarterly financial data for December 31, 2017 and 2016 is as follows:
Year Ended December 31, 2017 | |||||||||||||||
Quarter | |||||||||||||||
First | Second | Third | Fourth | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Net sales | $ | 1,423.5 | $ | 1,338.2 | $ | 1,385.8 | $ | 1,516.7 | |||||||
Operating costs and expenses: | |||||||||||||||
Cost of materials and other | 1,201.3 | 1,208.0 | 1,114.4 | 1,281.0 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 102.1 | 86.3 | 120.9 | 134.5 | |||||||||||
Depreciation and amortization | 33.3 | 31.7 | 31.8 | 32.5 | |||||||||||
Cost of sales | 1,336.7 | 1,326.0 | 1,267.1 | 1,448.0 | |||||||||||
Selling, general and administrative (exclusive of depreciation and amortization as reflected below) | 20.0 | 18.9 | 18.8 | 21.1 | |||||||||||
Depreciation and amortization | 0.8 | 0.7 | 1.2 | 1.1 | |||||||||||
Total operating costs and expenses | 1,357.5 | 1,345.6 | 1,287.1 | 1,470.2 | |||||||||||
Operating income (loss) | 66.0 | (7.4 | ) | 98.7 | 46.5 | ||||||||||
Other income (expense): | |||||||||||||||
Interest expense and other financing costs | (11.2 | ) | (12.0 | ) | (12.0 | ) | (12.0 | ) | |||||||
Interest income | — | 0.2 | 0.2 | 0.1 | |||||||||||
Gain (loss) on derivatives, net | 12.2 | — | (17.0 | ) | (65.0 | ) | |||||||||
Other income, net | — | — | 0.1 | 1.4 | |||||||||||
Total other income (expense) | 1.0 | (11.8 | ) | (28.7 | ) | (75.5 | ) | ||||||||
Income (loss) before income tax expense | 67.0 | (19.2 | ) | 70.0 | (29.0 | ) | |||||||||
Income tax expense | — | — | — | — | |||||||||||
Net income (loss) | $ | 67.0 | $ | (19.2 | ) | $ | 70.0 | $ | (29.0 | ) | |||||
Net income (loss) per common unit - basic and diluted | $ | 0.45 | $ | (0.13 | ) | $ | 0.47 | $ | (0.20 | ) | |||||
Weighted-average common units outstanding: | |||||||||||||||
Basic and diluted | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 | |||||||||||
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 | |||||||||||
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 | |||||||||||
Factors Impacting the Comparability of Quarterly Results of Operations
As discussed in Note 2 ("Summary of Significant Accounting Policies"), the Wynnewood refinery completed the first phase of its most recent major scheduled turnaround in the fourth quarter of 2017. The second phase of the Wynnewood turnaround is expected to occur in 2019. In addition to the two phase turnaround, the Partnership accelerated certain planned turnaround activities in the first quarter of 2017 on the hydrocracker unit for a catalyst change-out. The Partnership incurred approximately $80.4 million of major scheduled turnaround expenses during 2017, of which approximately $13.0 million, $2.7 million, $21.7 million and $43.0 million were incurred in the first, second, third and fourth quarters of 2017, respectively. The Coffeyville refinery completed the second phase of its most recent major scheduled turnaround during the first quarter of 2016 at a total cost of approximately $31.5 million for the year ended December 31, 2016, of which approximately $29.4 million and $2.1 million were incurred in the first and second quarters of 2016, respectively.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(18) Subsequent Events
Distribution
On February 21, 2018, the board of directors of the Partnership's general partner declared a cash distribution for the fourth quarter of 2017 to the Partnership's unitholders of $0.45 per common unit, or $66.4 million in aggregate. The cash distribution will be paid on March 12, 2018 to unitholders of record at the close of business on March 5, 2018.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. As of December 31, 2017, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management's Report On Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, the Partnership conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that the Partnership's internal control over financial reporting was effective as of December 31, 2017. Our independent registered public accounting firm, that audited the consolidated financial statements included herein under Item 8, has issued a report on the effectiveness of our internal control over financial reporting. This report can be found under Item 8.
Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended December 31, 2017 that has materially affected or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
Management of CVR Refining, LP
Our general partner, CVR Refining GP, LLC, manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Our general partner is owned by CVR Refining Holdings, a wholly-owned indirect subsidiary of CVR Energy. The operations of our general partner in its capacity as general partner are managed by its board of directors. Actions by our general partner that are made 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. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. The officers of our general partner manage the day-to-day affairs of our business.
Limited partners are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains various provisions that replace default fiduciary duties with contractual corporate governance standards. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it. Our debt instruments are non-recourse to our general partner.
As a publicly traded partnership, we qualify for certain exemptions from the NYSE's corporate governance requirements. Our general partner's board of directors has not and does not currently intend to establish a nominating/corporate governance committee. Additionally, a majority of the directors of our general partner do not need to be independent, and the compensation committee of the board of directors of our general partner does not need to be composed entirely of independent directors. Accordingly, unitholders do not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE.
The board of directors of our general partner consisted of nine directors in 2017, three of whom the board has affirmatively determined are independent in accordance with the rules of the NYSE (Glenn R. Zander, Jon R. Whitney and Kenneth Shea). The board of directors of our general partner met seven times in 2017. All of the directors who served during 2017 attended at least 75% of the total meetings of the board of directors of our general partner and each of the committees on which such director served during their respective tenure on the board.
The board of directors of our general partner has established an audit committee. The audit committee consists of Glenn R. Zander (chairman), Jon R. Whitney and Kenneth Shea. Each of the members of the audit committee meets the independence and experience standards established by the NYSE and the Exchange Act. The audit committee's responsibilities are to (i) appoint, terminate, retain, compensate and oversee the work of the independent registered public accounting firm, (ii) pre-approve all audit, review and attest services and permitted non-audit services provided by the independent registered public accounting firm, (iii) oversee the performance of the Partnership's internal audit function, (iv) evaluate the qualifications, performance and independence of the independent registered public accounting firm, (v) review external and internal audit reports and management's responses thereto, (vi) oversee the integrity of the financial reporting process, system of internal accounting controls, and financial statements and reports of the Partnership, (vii) review the Partnership's annual and quarterly financial statements, including disclosures made in "Management's Discussion and Analysis of Financial Condition and Results of Operations" set forth in periodic reports filed with the SEC, (viii) oversee the receipt, investigation, resolution and retention of all complaints submitted under the whistleblower policy, and (ix) otherwise comply with its responsibilities and duties as stated in its audit committee charter. The board of directors of our general partner has determined that Glenn R. Zander qualifies as an "audit committee financial expert," as defined by applicable rules of the SEC, and that each member of the audit committee is "financially literate" under the requirements of the NYSE. The audit committee met ten times in 2017.
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In addition, the board of directors of our general partner established a conflicts committee consisting entirely of independent directors. The conflicts committee consists of Glenn R. Zander, Jon R. Whitney and Kenneth Shea. Pursuant to our partnership agreement, the board may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other. The conflicts committee may then determine whether the resolution of the conflict of interest is adverse to the interest of the Partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by the general partner of any duties it may owe us or our unitholders. The conflicts committee met three times in 2017.
The board of directors of our general partner has also established a compensation committee. The compensation committee consists of Andrew Langham (chairman) and Jonathan Frates. The compensation committee (i) establishes policies and periodically determines matters involving executive compensation, (ii) grants or recommends the grant of equity awards under the CVR Refining LTIP, (iii) provides counsel regarding key personnel selection, (iv) may elect to retain independent compensation consultants, (v) recommends to the board of directors the structure of non-employee director compensation and (vi) assists the board of directors in assessing any risks to the Partnership associated with employee compensation practices and policies. In addition, the compensation committee reviews and discusses our Compensation Discussion and Analysis with management and produces a report on executive compensation for inclusion in our annual report on Form 10-K in compliance with applicable federal securities laws. The compensation committee met one time in 2017.
The board of directors of our general partner has created an environmental, health and safety committee. The committee consists of Jon R. Whitney (chairman) and Jonathan Frates. The environmental, health and safety committee's responsibilities are to provide oversight with respect to management's establishment and administration of environmental, health and safety policies, programs, procedures and initiatives. The environmental, health and safety committee met one time in 2017.
Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right or its registration rights, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership. Decisions by our general partner that are made in its individual capacity are made by CVR Refining Holdings, the sole member of our general partner, not by the board of directors of our general partner.
Meetings of Independent or Non-Management Directors and Executive Sessions
To promote open discussion among independent and non-management directors, we schedule regular executive sessions in which our independent or non-management directors meet without management participation. At the end of 2017, three of our nine directors were independent, and eight of our nine directors were non-management. Our independent directors met during four executive sessions in 2017. Mr. Zander (independent) presided over the executive session held by our independent directors. Our non-management directors did not meet in executive session in 2017. In the absence of further action, Mr. Icahn will preside over the executive session held by our non-management directors.
Communications with Directors
Unitholders and other interested parties wishing to communicate with our board may send a written communication addressed to:
CVR Refining, LP
2277 Plaza Drive, Suite 500
Sugar Land, Texas 77479
Attention: Executive Vice President, General Counsel and Secretary
Our General Counsel will forward all appropriate communications directly to our board or to any individual director or directors, depending upon the facts and circumstances outlined in the communication. Any unitholder or other interested party who is interested in contacting only the independent directors or non-management directors as a group or the director who presides over the meetings of the independent directors or non-management directors may also send written communications to the contact above and should state for whom the communication is intended.
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Compensation Committee Interlocks and Insider Participation
None of the members of the compensation committee of our general partner during 2017 has, at any time, been an officer or employee of the Partnership or our general partner and none has any relationship requiring disclosure under Item 404 Regulation S-K under the Exchange Act. No interlocking relationship exists between the board of directors or compensation committee of our general partner and the board of directors or compensation committee of any other company.
Executive Officers and Directors
The following table sets forth the names, positions and ages (as of February 20, 2018) of the executive officers and directors of our general partner.
Certain of the executive officers of our general partner are also executive officers of CVR Energy and are providing their services to our general partner and us pursuant to the services agreement among us, CVR Energy and our general partner. The executive officers listed below divide their working time between the management of CVR Energy, CVR Partners and us. The approximate weighted-average percentages of the amount of time the shared executive officers spent on management of our partnership in 2017 are as follows: David L. Lamp (50%), Susan M. Ball (55%), David L. Landreth (100%), John R. Walter (41%), Mark A. Pytosh (15%) and Janice T. DeVelasco (69%).
John J. Lipinski retired as Chief Executive Officer and President and a director of our general partner on December 31, 2017. David L. Lamp succeeds Mr. Lipinski. He was appointed as co-Chief Executive Officer and President of our general partner on December 1, 2017 and joined the board of directors of our general partner effective January 1, 2018. Martin J. Power retired as Chief Commercial Officer on December 31, 2017. Mark A. Pytosh and Janice T. DeVelasco were appointed as executive officers of our general partner effective January 1, 2018.
Name | Age | Position With Our General Partner | |||
David L. Lamp | 60 | President and Chief Executive Officer, Director | |||
Susan M. Ball | 54 | Executive Vice President, Chief Financial Officer and Treasurer | |||
David L. Landreth | 61 | Executive Vice President and Chief Commercial Officer | |||
John R. Walter | 41 | Executive Vice President, General Counsel and Secretary | |||
Mark A. Pytosh | 53 | Executive Vice President - Corporate Services | |||
Janice T. DeVelasco | 59 | Vice President - Environmental, Health, Safety & Security | |||
Carl C. Icahn | 82 | Director | |||
SungHwan Cho | 43 | Director | |||
Jonathan Frates | 35 | Director | |||
Andrew Langham | 44 | Director | |||
Louis J. Pastor | 33 | Director | |||
Kenneth Shea | 59 | Director | |||
Jon R. Whitney | 73 | Director | |||
Glenn R. Zander | 71 | Director | |||
David L. Lamp serves as President, Chief Executive Officer and a Director of CVR Energy, as well as President, Chief Executive Officer and a Director of the general partner of CVR Refining and Executive Chairman and a Director of the general partner of CVR Partners. Mr. Lamp joined the company in December 2017, and joined our boards in January 2018. Mr. Lamp previously served as President and Chief Operating Officer for Western Refining Inc. from July 2016 to June 2017. He previously served as Chief Executive Officer and President and a director of Northern Tier Energy Corporation from March 2014 until July 2016. Prior to Northern Tier, Mr. Lamp was with HollyFrontier Corporation and served as Chief Operating Officer and Executive Vice President. In 2011, Holly and Frontier completed a merger of equals and changed their name to HollyFrontier Corporation. Mr. Lamp joined Holly in January 2004 as Vice President, Refinery Operations and was responsible for all aspects of its refining operations. In November 2005, he was named Executive Vice President, Refining and Marketing, adding the additional responsibilities of its crude, light products marketing and asphalt businesses. Mr. Lamp was named President of Holly in November 2007. Mr. Lamp has more than 37 years of technical, commercial and operational experience in the refining and chemical industries. Prior to joining Holly, Mr. Lamp was the Vice President and General Manager of El Paso Energy’s Aruba refining complex. Earlier in his career he served as Director of Operations for KOSA, a polyester
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production joint venture between Koch Industries and Saba, where he oversaw KOSA’s 15 chemical and fiber plants in the U.S., Canada, Mexico and Europe. Prior to joining KOSA, Mr. Lamp had a long and distinguished career with Koch Industries, spanning more than 20 years. Mr. Lamp rose through various positions of increasing authority, ultimately becoming Executive Vice President-Refining and Chemical Operations where he had responsibility for all operating aspects of Koch’s 500,000 barrels-per-day of crude refining capacity and all of Koch’s chemical plants. Mr. Lamp obtained a Bachelor of Science in Chemical Engineering from Michigan State University. Mr. Lamp’s extensive knowledge and experience in the refining and chemical industries, as well as his significant background serving in key leadership roles at public and private companies make him well qualified to serve as a director of our general partner.
Susan M. Ball serves as Executive Vice President, Chief Financial Officer and Treasurer of CVR Energy, the general partner of CVR Refining, and the general partner of CVR Partners, in each case, as of January 2018. She previously served as Chief Financial Officer and Treasurer of CVR Energy and CVR Partners’ general partner from August 2012 to December 2017. She also previously served as Vice President, Chief Accounting Officer and Assistant Treasurer of CVR Energy and the general partner of CVR Partners since October 2007 and as Vice President, Chief Accounting Officer and Assistant Treasurer for CRLLC since May 2006. In addition, Ms. Ball also served as the Chief Financial Officer and Treasurer of CVR Refining’s general partner from its inception in September 2012 to December 2017. Ms. Ball has more than 30 years of experience in the accounting industry, with more than 12 years serving clients in the public accounting industry. Prior to joining CVR Energy, she served as a Tax Managing Director with KPMG LLP, where she was responsible for all aspects of federal and state income tax compliance and tax consulting, which included a significant amount of mergers and acquisition work on behalf of her clients. Ms. Ball received a Bachelor of Science in Business Administration from Missouri Western State University and is a Certified Public Accountant.
David L. Landreth has served as Executive Vice President and Chief Commercial Officer for the general partner of CVR Refining since January 2018. He previously served as Senior Vice President - Economics and Planning for the general partner of CVR Refining from its inception in September 2012 to December 2017. Mr. Landreth joined the predecessor to the company in 2005 and has served in an economics and planning role since that time. Mr. Landreth has more than 30 years’ experience in refining and petrochemicals in areas relating to crude, feedstock, product and process optimization, commercial activities, acquisitions and capital utilization. He has served in numerous management positions in the petroleum industry. Most of his career was in various refining and marketing positions with the Coastal Corporation. Following the merger between Coastal and El Paso in 2001, Mr. Landreth assumed the position of Director of Refining Optimization and Commercial Management. Following El Paso, he was the Director of Refining and Marketing Economics and Planning at Holly Corporation in Dallas. Mr. Landreth received a B.S. degree in Chemistry from Northwestern Oklahoma State University.
John R. Walter serves as Executive Vice President, General Counsel and Secretary of CVR Energy, the general partner of CVR Refining, and the general partner of CVR Partners, in each case, as of January 2018. He previously served as Senior Vice President, General Counsel and Secretary of CVR Energy and each of the general partners of CVR Refining and CVR Partners from January 2015 to December 2017. He has served as Vice President, Associate General Counsel since January 2011, Assistant Secretary since May 2011 and Associate General Counsel since March 2008. Prior to joining CVR Energy, Mr. Walter was an associate at Stinson Leonard Street LLP in Kansas City, Missouri, from 2006 to 2008, and was an associate at Seigfreid Bingham, P.C. in Kansas City, Missouri, from 2002 to 2006. Mr. Walter received a Bachelor of Science in psychology from Colorado State University and a Juris Doctor from the University of Kansas.
Mark A. Pytosh serves as Executive Vice President - Corporate Services of CVR Energy and the general partner of CVR Refining, and President and Chief Executive Officer of the general partner of CVR Partners, in each case, as of January 2018. He has served as President and Chief Executive Officer of the general partner of CVR Partners since May 2014, and has served as a director of the general partner of CVR Partners since June 2011. Mr. Pytosh previously served as Senior Vice President - Administration for CVR Energy and CVR Refining from December 2014 to December 2017. Prior to joining CVR Partners, Mr. Pytosh served as Executive Vice President and Chief Financial Officer for Alberta, Canada-based Tervita Corporation, an environmental and energy services company. From 2006 to 2010, he served as Senior Vice President and Chief Financial Officer for Covanta Energy Corporation, which owns and operates energy-from-waste power facilities, biomass power facilities and independent power plants in the United States, Europe and Asia. Prior to Covanta, Mr. Pytosh served as Executive Vice President from 2004 to 2006, and Chief Financial Officer from 2005 to 2006, for Waste Services, Inc., an integrated solid waste services company that operates in the United States and Canada. Prior to joining the renewable energy and waste industries, Mr. Pytosh spent 18 years in the investment banking industry, working with a broad range of clients in the environmental services, automotive, construction equipment and a variety of other industrial sectors. From 2000 to 2004, he was a Managing Director in investment banking at Lehman Brothers, where he led the firm’s global industrial group. Prior to joining Lehman Brothers, he was a Managing Director at Donaldson, Lufkin & Jenrette, where he led the firm’s environmental services and automotive industry groups. Mr. Pytosh received a Bachelor of Science degree in chemistry from the University of Illinois, Urbana-Champaign. He serves on the boards of directors for The Fertilizer Institute and the University of Illinois Foundation.
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Janice T. DeVelasco serves as Vice President - Environmental, Health, Safety & Security of CVR Energy, the general partner of CVR Refining, and the general partner of CVR Partners, in each case, as of January 2018. She previously served as Vice President - Environmental, Health & Safety for CVR since April 2014. Ms. DeVelasco has more than 30 years’ experience in environmental, health, safety and risk management. Before joining the company, she served in progressive technical, management and consulting positions with CITGO Petroleum Corporation and its predecessor companies from 1981 to 2007 and Sage Environmental Consulting, L.P. from 2007 to 2014. Ms. DeVelasco is a licensed professional engineer and holds a bachelor’s degree in chemical engineering from the University of Oklahoma and a master’s degree in business administration from Texas A&M University.
Carl C. Icahn has served as chairman of the board and a director of Starfire Holding Corporation, a privately-held holding company, and chairman of the board and a director of various subsidiaries of Starfire, since 1984. Since August 2007, through his position as Chief Executive Officer of Icahn Capital LP, a wholly owned subsidiary of Icahn Enterprises L.P., and certain related entities, Mr. Icahn’s principal occupation is managing private investment funds, including Icahn Partners LP and Icahn Partners Master Fund LP. Since November 1990, Mr. Icahn has been chairman of the board of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, mining, real estate and home fashion). Mr. Icahn has been: chairman of the board of CVR Refining since January 2013; chairman of the board of CVR Energy since June 2012; chairman of the board of Tropicana Entertainment Inc., a company that is primarily engaged in the business of owning and operating casinos and resorts, since March 2010; and President and a member of the executive committee of XO Holdings, a competitive provider of telecom services, since September 2011, and chairman of the board and a director of its predecessors since January 2003. Mr. Icahn was previously: director of Federal-Mogul Holdings Corporation, a supplier of automotive powertrain and safety components, from December 2007 to May 2015, and the non-executive chairman of the board of Federal-Mogul from January 2008 to May 2015; chairman of the board and a director of American Railcar Industries, Inc., a railcar manufacturing company, from 1994 to July 2014; a director of American Railcar Leasing LLC, a lessor and seller of specialized railroad tank and covered hopper railcars, from June 2004 to November 2013; a director of WestPoint Home LLC, a home textiles manufacturer, from October 2005 until December 2011; and a director of Cadus Corporation, a company engaged in the acquisition of real estate for renovation or construction and resale, from July 1993 to July 2010. Mr. Icahn received his B.A. from Princeton University. Mr. Icahn brings to his role as director his significant business experience and leadership role as director in various companies as discussed above. In addition, Mr. Icahn is uniquely qualified based on his historical background for creating value in companies across multiple industries. Mr. Icahn has proven to be a successful investor over the past 40 years.
SungHwan Cho has served as Chief Financial Officer of Icahn Enterprises L.P., a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, mining, real estate and home fashion, since March 2012. Prior to that time, he was Senior Vice President and previously Portfolio Company Associate at Icahn Enterprises L.P. since October 2006. Mr. Cho has been a director of: Hertz Global Holdings, Inc., a company engaged in the car rental business, since May 2017; Ferrous Resources Limited, an iron ore mining company with operations in Brazil, since June 2015; CVR Refining since January 2013; Icahn Enterprises L.P., since September 2012; CVR Energy since May 2012; and American Railcar Industries, Inc., a railcar manufacturing company, since June 2011 (and has been Chairman of the Board of American Railcar Industries since July 2014). In addition, Mr. Cho serves as a director of certain wholly-owned subsidiaries of Icahn Enterprises L.P., including: Federal-Mogul Holdings LLC (formerly known as Federal-Mogul Holdings Corporation), a supplier of automotive powertrain and safety components; Icahn Automotive Group LLC, an automotive parts installer, retailer and distributor; PSC Metals Inc., a metal recycling company; and WestPoint Home LLC, a home textiles manufacturer. Mr. Cho was previously: a member of the Executive Committee of American Railcar Leasing LLC, a lessor and seller of specialized railroad tank and covered hopper railcars, from September 2013 to June 2017; a director of CVR Partners from May 2012 to April 2017; a director of Viskase Companies, Inc., a meat casing company, from November 2006 to April 2017; and a director of Take-Two Interactive Software Inc., a publisher of interactive entertainment products, from April 2010 to November 2013. Ferrous Resources Limited, CVR Refining, Icahn Enterprises, CVR Energy, CVR Partners, Federal-Mogul, Icahn Automotive, American Railcar Industries, WestPoint Home, PSC Metals and Viskase Companies each are indirectly controlled by Carl C. Icahn, and American Railcar Leasing was previously indirectly controlled by Mr. Icahn. Mr. Icahn also has or previously had a non−controlling interest in each of Hertz Global Holdings and Take-Two Interactive Software through the ownership of securities. Mr. Cho received a B.S. in Computer Science from Stanford University and an MBA from New York University, Stern School of Business. Based upon Mr. Cho’s deep understanding of finance and risk obtained from his past experience, including his position as an investment banker at Salomon Smith Barney, we believe that Mr. Cho has the requisite set of skills to serve as a member of our board.
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Jonathan Frates has been a Portfolio Company Associate at Icahn Enterprises L.P., a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, mining, real estate and home fashion, since November 2015. Prior to joining Icahn Enterprises, Mr. Frates served as a Senior Business Analyst at First Acceptance Corp. and as an Associate at its holding company, Diamond A Ford Corp. Mr. Frates began his career as an Investment Banking Analyst at Wachovia Securities LLC. Mr. Frates has served as a director of: Ferrous Resources Limited, an iron ore mining company with operations in Brazil, since December 2016; CVR Partners since April 2016; American Railcar Industries, Inc., a railcar manufacturing company, since March 2016; Viskase Companies, Inc., a meat casing company, since March 2016; CVR Energy since March 2016; and CVR Refining since March 2016. Ferrous Resources, American Railcar Industries, Viskase Companies, CVR Energy, CVR Refining and CVR Partners are each indirectly controlled by Carl C. Icahn. Mr. Frates received a BBA from Southern Methodist University and an MBA from Columbia Business School. Based on Mr. Frates strong financial background and experience as an analyst, we believe that Mr. Frates has the requisite set of skills to serve as a member of our board.
Andrew Langham has been General Counsel of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, mining, real estate and home fashion) since 2014. From 2005 to 2014, Mr. Langham was Assistant General Counsel of Icahn Enterprises. Prior to joining Icahn Enterprises, Mr. Langham was an associate at Latham & Watkins LLP focusing on corporate finance, mergers and acquisitions, and general corporate matters. Mr. Langham has been a director of: Cheniere Energy, Inc., a developer of natural gas liquefaction and export facilities and related pipelines, since 2017; Welbilt, Inc. (formerly known as Manitowoc Foodservice, Inc.), a commercial foodservice equipment manufacturer, since 2016; Freeport-McMoRan Inc., the world’s largest publicly traded copper producer, since 2015; CVR Partners since 2015; and CVR Refining since 2014. Mr. Langham was previously a director of CVR Energy from 2014 to 2017. CVR Partners, CVR Refining and CVR Energy are each indirectly controlled by Carl C. Icahn. Mr. Icahn also has non-controlling interests in Cheniere, Welbilt and Freeport-McMoRan through the ownership of securities. Mr. Langham received a B.A. from Whitman College, and a J.D. from the University of Washington. Based on Mr. Langham's extensive corporate and public company experience, we believe that Mr. Langham has the requisite set of skills to serve as a member of our board.
Louis J. Pastor has been Deputy General Counsel of Icahn Enterprises L.P. (a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, mining, real estate and home fashion) since 2015. From 2013 to 2015, Mr. Pastor was Assistant General Counsel of Icahn Enterprises. Prior to joining Icahn Enterprises, Mr. Pastor was an Associate at Simpson Thacher & Bartlett LLP, where he advised corporate, private equity and investment banking clients on a wide array of corporate finance transactions, business combination transactions and other general corporate matters. Mr. Pastor has been a director of: CVR Energy since August 2017; Herc Holdings Inc., an international provider of equipment rental and services, since June 2016; CVR Partners since April 2016; and CVR Refining since September 2014. Mr. Pastor has also been a member of the Executive Committee of ACF Industries LLC, a railcar manufacturing company, since July 2015. Mr. Pastor was previously a director of Federal-Mogul Holdings Corporation, a supplier of automotive powertrain and safety components, from May 2015 to January 2017. Each of CVR Energy, CVR Refining, CVR Partners, Federal-Mogul and ACF Industries is indirectly controlled by Carl C. Icahn. Mr. Icahn also has a non-controlling interest in Herc Holdings through the ownership of securities. Mr. Pastor received a B.A. from The Ohio State University and a J.D. from the University of Pennsylvania. Based on Mr. Pastor's strong finance and corporate experience, we believe that Mr. Pastor has the requisite set of skills to serve as a member of our board.
Kenneth Shea has been a member of the board of directors of our general partner since January 2013. Mr. Shea is a Senior Managing Director of Guggenheim Securities, LLC, an investment banking firm. Prior to joining Guggenheim Securities in September 2014, Mr. Shea served as President of Coastal Capital Management LLC, an affiliate of Coastal Development, LLC, a New York based privately-held developer of resort destinations, luxury hotels and casino gaming facilities. Prior to joining Coastal in September 2009, from July 2008 to August 2009, Mr. Shea was a Managing Director for Icahn Capital LP, a wholly owned subsidiary of Icahn Enterprises L.P. (a diversified holding company controlled by Carl Icahn that is engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion) through which Mr. Icahn manages various private investment funds, including Icahn Partners, Icahn Master, Icahn Master II and Icahn Master III. At Icahn Capital, Mr. Shea had responsibility for all principal investments in the gaming and leisure industries. Prior to serving at Icahn Capital, Mr. Shea was employed by Bear, Stearns & Co., Inc., from 1996 to 2008, where he was a Senior Managing Director and global head of the Gaming and Leisure investment banking department. At Bear, Stearns, Mr. Shea oversaw the execution of various complex capital raising and merger & acquisition transactions for a wide variety of public and private companies. Mr. Shea currently serves on the board of directors of Equity Commonwealth, a commercial office real estate investment trust. Mr. Shea holds a Bachelor of Arts in Economics, magna cum laude, from Boston College and an M.B.A. from the University of Virginia's Darden School. Based upon his significant experience in corporate finance, mergers and acquisitions and investing, and deep knowledge of the capital markets, we believe that Mr. Shea has the requisite skills to serve as a member of our board.
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Jon R. Whitney has been a member of the board of directors of our general partner since January 2013. Mr. Whitney was a member of the board of directors of CVR Partners' general partner from June 2011 until his resignation in January 2013. He previously worked at Colorado Interstate Gas Company (CIG), a natural gas transmission company, from 1968 until 2001. He served as President and Chief Executive Officer of CIG from 1990 until it merged with El Paso Corporation in 2001. After leaving CIG, he served as Co-Chairman of the Board for TransLink, an independent electric power system operator, was a member of Peak Energy Ventures, LLC, a natural gas consulting company, and served on the boards of directors of Storm Cat Energy Corporation, Patina Oil and Gas Corporation (prior to its merger with Noble Energy in 2005), American Oil and Gas Corporation (prior to its merger with Hess Corporation in 2010), Bear Cub Energy, Bear Paw Energy and Bear Tracker Energy. He also held committee positions with the Interstate Natural Gas Association of America and the American Gas Association. He is currently a director of 3 Bear Energy LLC, a private company in the midstream energy business. We believe Mr. Whitney's experience in the natural gas industry and as a director to multiple companies in the energy space is an asset to our board.
Glenn R. Zander has been a member of the board of directors of our general partner since January 2013. Mr. Zander served as a director of CVR Energy from May 2012 until his resignation in January 2013. Mr. Zander was the Chief Executive Officer, President and director of Aloha Airgroup, Inc., a privately owned passenger and cargo transportation airline, from 1994 to 2004. From 1990 to 1994, Mr. Zander served as Vice Chairman, Co-Chief Executive Officer and director of Trans World Airlines, an international airline. He also served as Chief Financial Officer of TWA within that period. During 1992 and 1993, Mr. Zander served as the Chief Restructuring Officer of TWA following its Chapter 11 bankruptcy in 1992 and its emergence therefrom in 1993. From 2004 to 2009, Mr. Zander served as a director of Centerplate, Inc., a provider of food/concession services at sports facilities and convention centers in the United States and Canada. TWA was formerly indirectly controlled by Carl C. Icahn. Based upon Mr. Zander's substantial operational background, having served as chief executive officer and chief financial officer and other executive positions, we believe that Mr. Zander has the requisite set of skills to serve as a member of our board.
The directors of our general partner hold office until the earlier of their death, resignation or removal.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our executive officers and directors and each person who owns more than 10% of our outstanding common units, to file reports of their common unit ownership and changes in their ownership of our common units with the SEC. These same people must also furnish us with copies of these reports and representations made to us that no other reports were required. We have performed a general review of such reports and amendments thereto filed in 2017. Based solely on our review of the copies of such reports furnished to us or such representations, as appropriate, to our knowledge all of our executive officers and directors, and other persons who owned more than 10% of our outstanding common units, fully complied with the reporting requirements of Section 16(a) during 2017.
Corporate Governance Guidelines and Codes of Ethics
Our Corporate Governance Guidelines, as well as our Code of Ethics and Business Conduct, which applies to all of our directors, officers and employees (and which includes additional provisions that apply to our principal executive officer, principal financial officer, principal accounting officer, controller and other persons performing similar functions) are available free of charge on our website at www.cvrrefining.com. These documents are also available in print without charge to any unitholder requesting them. We intend to disclose any changes in or waivers from our Code of Ethics and Business Conduct by posting such information on our website or by filing a Form 8-K with the SEC.
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Item 11. Executive Compensation
Compensation Discussion and Analysis
Overview
The Partnership does not directly employ any of the executives responsible for the management of our business. Our general partner employs Mr. David L. Landreth, as executive vice president and chief commercial officer (he served as senior vice president, economics and planning in 2017). The remaining executive officers that are responsible for managing our day-to-day affairs are executive officers of, and are (or were) employed by, CVR Energy, including John J. Lipinski (our former chief executive officer), David L. Lamp, (our chief executive officer), Susan M. Ball (our chief financial officer), John R. Walter (our general counsel) and Martin J. Power (our former chief commercial officer). Throughout this Annual Report, we refer to Messrs. Lipinski and Lamp, Ms. Ball and Messrs. Walter, Landreth and Power as our "named executive officers".
The approximate weighted-average percentages of the amount of time that the named executive officers dedicated to the management of our business in 2017 are as follows: John J. Lipinski (50%); David L. Lamp (50%); Susan M. Ball (55%); John R. Walter (41%); David L. Landreth (100%) and Martin J. Power (95%). These numbers are weighted because the named executive officers may spend a different percentage of their time dedicated to our business each quarter. The remainder of their time, if any, was spent working for CVR Energy and its subsidiaries (including CVR Partners).
During 2017, Messrs. Lipinski and Lamp, Ms. Ball, and Messrs. Walter and Power were employed and paid by CVR Energy. Their compensation was determined by CVR Energy. Mr. Landreth is employed by our general partner and his compensation is determined by our general partner. In addition, during 2017 all of the named executive officers participated in the welfare and retirement plans of CVR Energy. The Partnership has no control and does not establish or direct the compensation policies or practices of CVR Energy. The Partnership bears an allocated portion of CVR Energy's costs of providing compensation and benefits to the CVR Energy employees who serve as executive officers of our general partner pursuant to the services agreement described below.
Pursuant to the services agreement between us, our general partner and CVR Energy, among other matters:
• | 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 employees providing services to the Partnership via the services agreement. |
Under the services agreement, either our general partner, our subsidiaries or we pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees who provide us services under the agreement on a full-time basis, but excluding certain share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees who provide us services under the agreement on a part-time basis, but excluding certain share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percent of total working time that such shared employees are engaged in performing services for us; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement. We are required to pay all compensation amounts allocated to us by CVR Energy (except for certain share-based compensation), although we may object to amounts that we deem unreasonable. Either CVR Energy or our general partner may terminate the services agreement upon at least 180 days' notice. For more information on this services agreement, see "Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy and CVR Partners."
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With the exception of Mr. Landreth, (who is employed by and whose compensation is determined by, our general partner), during 2017 our named executive officers received all of their compensation and benefits for services performed for our business from CVR Energy, which compensation was set by CVR Energy. Although we bear an allocated portion of CVR Energy's costs of providing compensation and benefits (excluding certain share-based compensation) to the named executive officers, we have no control over such costs and do not establish or direct the compensation policies or practices of CVR Energy. We maintain the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"), which was adopted on January 16, 2013 in connection with the Initial Public Offering. Aside from Mr. Landreth and the CVR Refining LTIP, neither we nor our general partner anticipate setting the compensation for the named executive officers or adopting any compensation or benefits arrangements in the near future. Rather, it is anticipated that the executive officers of our general partner (other than Mr. Landreth) will continue to have their compensation set by CVR Energy and will participate in CVR Energy's benefit plans and programs (with the exception of the CVR Refining LTIP, pursuant to which they may receive awards in the future).
Based on an internal review by the compensation committee of our general partner of our material compensation programs and its understanding of the material compensation programs of CVR Energy, the compensation committee of our general partner has concluded that there are no plans that provide meaningful incentives for employees, including the named executive officers, to take risks that would be reasonably likely to have a material adverse effect on the Partnership.
As discussed above, 2017 compensation for Messrs. Lipinski and Lamp, Ms. Ball and Messrs. Walter and Power was set by CVR Energy, while the 2017 compensation for Mr. Landreth was set by CVR Refining. The remainder of the Compensation Discussion and Analysis is divided into two sections; the first focuses on CVR Refining's compensation programs and the second focuses on CVR Energy's compensation programs.
CVR Refining's Compensation Programs
The following discussion relates to the 2017 compensation of the named executive officer who was an employee of our general partner through December 31, 2017, Mr. Landreth. Accordingly, references to the named executive officers in this section shall refer solely to Mr. Landreth. In addition, all references to our compensation committee refer to the compensation committee of the board of directors of our general partner.
Compensation Objectives
CVR Refining's executive compensation objectives are threefold:
• | 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. |
CVR Refining takes these main objectives into consideration when creating its compensation programs, setting each element of compensation under those programs, and determining the proper mix of the various compensation elements.
Elements of Compensation Program
For 2017, the three primary components of CVR Refining's compensation program were base salary, an annual performance-based cash bonus and equity-based awards. While these three components are related, they are viewed as separate and analyzed as such. The named executive officer is also provided with benefits that are generally available to CVR Refining's salaried employees.
CVR Refining believes that equity-based compensation is the primary motivator in attracting and retaining executive officers. Salary and cash bonuses are viewed as secondary. However, the compensation committee views a competitive level of salary and cash bonus as critical to retaining talented individuals.
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CVR Refining has not established equity ownership requirements for its executive officers. The compensation committee believes that cash-settled equity-based awards provide executive officers with a more attractive compensation package and are less burdensome for the executive officers and CVR Refining to administer than equity-settled awards. The compensation committee believes that equity-based compensation in the form of awards of CVR Refining's common units would be less attractive and more burdensome. Additionally, equity-based compensation in the form of CVR Refining's common units would dilute the ownership interest of existing common unit holders.
The compensation committee has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and current compensation, between cash and non-cash compensation, or among different forms of compensation other than its belief that the most crucial component is equity-based compensation. The decision is strictly made on a subjective and individual basis after consideration of all relevant factors. The compensation committee believes that the most critical component of compensation to enhance long-term unitholder value and growth is the equity-based component and has generally targeted 40% to 60% of the compensation package to be equity-based for executive officers, other than the chief executive officer. This provides the incentive for executive officers to remain in the employ of CVR Refining and to promote a focused effort on growth and long-term success with long-term enhancement of unitholder value. The chief executive officer of CVR Refining, while not a member of the compensation committee, reviews information provided to CVR Refining by an independent compensation consultant, Longnecker & Associates ("Longnecker"), as well as other relevant market information and actively provides guidance and recommendations to the committee regarding the amount and form of the compensation of other executives and key employees.
Longnecker was engaged by CVR Refining to generally assess the level of compensation increases year over year and to assess new and proposed rules in the compensation area. The compensation committee utilized this information, along with other market survey and general industry survey information provided by CVR Refining to review and approve executive compensation levels. Although no specific target for total compensation is set, CVR Refining generally recommends compensation levels at or near the 50th percentile of the available market survey and general industry survey information.
Base Salary. Mr. Landreth does not have an employment agreement. Base salaries are set at a level intended to enable CVR Refining to hire and retain executives, to enhance the executive's motivation in a highly competitive and dynamic environment, and to reward individual and company performance. In determining base salary levels, the compensation committee takes into account the following factors: (i) CVR Refining's financial and operational performance for the year; (ii) the previous years' compensation level for each executive; (iii) market survey and general industry survey information for comparable public companies; and (iv) recommendations of the chief executive officer, based on individual responsibilities and performance, including each executive's commitment and ability to (a) strategically meet business challenges, (b) achieve financial results, (c) promote legal and ethical compliance, (d) lead their own business or business team for which they are responsible and (e) diligently and effectively respond to immediate needs of the volatile industry and business environment.
Rather than establishing compensation solely on a formula-driven basis, decisions by our compensation committee are made using an approach that considers several important factors in developing compensation levels. For example, the compensation committee considers whether individual base salaries reflect responsibility levels and are reasonable, competitive and fair. In addition, in setting base salaries, the compensation committee reviews published and other market survey and general industry survey information and considers the applicability of the salary data in view of the individual positions within CVR Refining.
Salaries are reviewed annually by the compensation committee with periodic informal reviews throughout the year. Adjustments, if any, are usually made effective January 1 of the year immediately following the review. The compensation committee most recently reviewed the level of base salary and cash bonus for Mr. Landreth in 2017 in conjunction with his responsibilities and expectations for 2018. They concluded their review in November 2017, and set the base salary for Mr. Landreth of $283,500 as of January 1, 2018. Mr. Landreth was promoted to executive vice president and chief commercial officer effective January 1, 2018 and due to his additional responsibilities, his base salary was adjusted to $430,000 effective January 1, 2018. Individual performance, market data and changes in the named executive officer's positions and levels of responsibility were considered. Among these three factors, slightly more weight was given to market data.
Annual Bonus. CVR Refining's annual bonus program is designed to meet each of its compensation objectives. Specifically, CVR Refining's annual bonus program rewards executives only for measured company performance, thereby aligning the executive's interest with those of its unitholders and encouraging executives to focus on targeted performance. Further, the program also provides executives with the opportunity to earn additional compensation, thereby making our total compensation package more competitive.
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Information about total cash compensation paid by members of CVR Refining's industry is used in determining both the level of bonus award and the ratio of salary to bonus, as the compensation committee believes that maintaining a level of bonus and a ratio of fixed salary to bonus (which may fluctuate) that is in line with those of our competitors is an important factor in attracting and retaining executives. The compensation committee also believes that a significant portion of an executive's compensation should be at risk, which means that a portion of the executive's overall compensation is not guaranteed and is determined based on individual and company performance. Executives have greater potential bonus awards as the authority and responsibility of an executive increases. Each of the named executive officers is eligible to receive an annual cash bonus with a target bonus equal to a specified percentage of the relevant executive's annual base salary. For 2017, the target bonus for David L. Landreth was 90%. This target percentage was the result of individual negotiations between the named executive officer and CVR Refining, and was in correlation with the market data and other general industry survey information provided by CVR Refining. Specific bonus measures were determined by the compensation committee, following discussions with CVR Refining's management.
Mr. Landreth had the opportunity to earn a bonus in respect of 2017 performance pursuant to the Amended and Restated CVR Energy Inc. Performance Incentive Plan dated April 22, 2016 (the "CVR Energy PIP"). The CVR Energy PIP has separate metrics specific to CVR Refining's financial, operational and safety measures, and Mr. Landreth’s annual bonus is evaluated based on these metrics and approved by our compensation committee. In addition, Mr. Power's annual bonus (at a target of 115%) is also evaluated based on these metrics due to a substantial amount of his time that is devoted to CVR Refining; provided his annual bonus is approved by the compensation committee of CVR Energy. The payment of annual bonuses for the 2017 performance year to the named executive officers was dependent upon the achievement of financial, operational and safety measures, which comprised 35%, 45% and 20% of the annual bonuses, respectively, for Messrs. Landreth and Power. Specific bonus measures were determined by the compensation committee based on its review of relevant market data and discussions with management, and were selected with the goals of optimizing operations, maintaining financial stability and providing a safe work environment intended to maximize CVR Refining's overall performance resulting in increased unitholder value. The compensation committee also approved the threshold, target and maximum performance goals with respect to each performance measure. No payment is made with respect to the measures unless the threshold of the relevant performance measure is achieved.
The 2017 financial measure was adjusted EBITDA for the refining business, which was derived from refining earnings before interest, taxes, depreciation and amortization, and adjusted for loss on extinguishment of debt, turnaround expenses, gain/loss on derivatives, first-in, first-out (FIFO) accounting impacts, asset impairment charges, non-controlling interest and board directed actions.
The 2017 operational measures included the following: petroleum reliability for the Coffeyville and Wynnewood refineries, measured by crude throughput barrels per day, as adjusted at the discretion of our compensation committee for third party events; and production for crude transportation, measured by gathered crude barrels per day.
The 2017 safety measures included the following: OSHA recordable injury statistics (based upon OSHA injuries and inclusive of petroleum and crude transportation); OSHA lost time injury statistics (based upon OSHA lost time injuries and inclusive of petroleum and crude transportation); EH&S severity statistics (based upon EH&S severity and inclusive of petroleum and crude transportation); air reportable releases (based upon EPA reportable quantity releases and inclusive of petroleum operations); air reportable release quantity (based upon EPA reportable quantity releases and inclusive of petroleum operations); tier 1 process safety events (based upon API process safety events and inclusive of petroleum operations); tier 2 process safety events (based upon API process safety events and inclusive of petroleum operations); reportable quantity spills for pipeline (based upon EPA reportable quantity releases inclusive of transportation operations); spills to waters of U.S. pipelines (based upon EPA spills to U.S. waters inclusive of transportation operations); reportable quantity spills for trucking (based upon EPA reportable quantity releases inclusive of transportation operations); spills to waters of U.S. trucking (based upon EPA spills to U.S. waters inclusive of transportation operations); trucking incidents for on-road operations (based upon on-road, fault of CRCT and inclusive of transportation operations); and severity of trucking incidents (based upon EH&S applied factors inclusive of transportation operations).
The table below reflects the: (i) financial, operational and safety measures used to determine the 2017 bonus for Messrs. Landreth and Power; (ii) threshold, target and maximum performance levels for each measure; (iii) actual results with respect to each measure; and (iv) portion of the 2017 bonus determined based on each such measure. Messrs. Landreth and Power could have received 50% for threshold levels, 100% for target levels, and 150% for maximum levels, respectively.
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2017 Performance Measure | 2017 Performance Goals Threshold/Target/Maximum | 2017 Actual Results | Portion of Target Bonus Allocable to Measure | |||
Consolidated adjusted EBITDA — Petroleum business | Threshold: $270.0 million Target: $300.0 million Maximum: $360.0 million | $401.1 million | 35% of bonus for Messrs. Landreth and Power | |||
Petroleum reliability measures (as adjusted) | Threshold: 178,200 bpd Target: 190,200 bpd Maximum: 200,700 bpd | 205,263 bpd | 35% of bonus for Mr. Landreth; 25% of bonus for Mr. Power | |||
Crude transportation production measure | Threshold: 72,000 bpd Target: 76,000 bpd Maximum: 80,000 bpd | 85,735 bpd | 10% of bonus for Mr. Landreth; 20% of bonus for Mr. Power | |||
Coffeyville Refinery Environmental Health & Safety Measures | Threshold: 5% of refining payout levels Target: 10% of refining payout levels Maximum: 15% of refining payout levels | 13.5% | 10% of bonus for Messrs. Landreth 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 | 11.0% | 10% of bonus for Mr. 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 | 5.5% | 5% of bonus for Mr. Power | |||
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 | 6.5% | 5% of bonus for Mr. Power | |||
As a result of these levels of performance, Mr. Landreth earned approximately 144.50% of his target annual bonus, and Mr. Power earned approximately 145.52% of his target annual bonus.
Equity-Based Incentive Awards
CVR Refining also uses equity-based incentives to reward long-term performance of its named executive officers. The issuance of equity-based incentives to named executive officers is intended to satisfy CVR Refining's compensation program objectives by generating significant future value for each named executive officer if CVR Refining's performance is outstanding and the value of CVR Refining's partners' capital increases for all of its unitholders. The compensation committee believes that its equity-based incentives promote long-term retention of executives.
CVR Refining established the CVR Refining LTIP in January 2013 in connection with the completion of its Initial Public Offering. The compensation committee may elect to make grants of restricted units, options, phantom units or other equity-based awards under the CVR Refining LTIP in its discretion or may recommend grants to the board of directors of our general partner for its approval, as determined by the committee in its discretion. In 2017, Mr. Landreth received phantom unit awards pursuant to the CVR Refining LTIP.
Perquisites. The total value of all perquisites and personal benefits provided by CVR Refining to each of its named executive officers in 2017 was less than $10,000.
CVR Energy's Compensation Programs
The following discussion relates to the 2017 compensation of the named executive officers who are employed by CVR Energy. Accordingly, references to the named executive officers in this section shall refer solely to Messrs. Lipinski and Lamp, Ms. Ball, Mr. Walter and Mr. Power. In addition, all references to the compensation committee refer to the compensation committee of the board of directors of CVR Energy.
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Compensation Objectives
CVR Energy's executive compensation objectives are threefold:
• | 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. |
CVR Energy takes these main objectives into consideration when creating its compensation programs, when setting each element of compensation under those programs, and when determining the proper mix of the various compensation elements.
Elements of Compensation Program
For 2017, the three primary components of CVR Energy's compensation program were base salary, an annual performance-based cash bonus and equity-based awards. While these three components are related, they are viewed as separate and analyzed as such. The named executive officers are also provided with benefits that are generally available to CVR Energy's salaried employees.
CVR Energy believes that equity-based compensation is the primary motivator in attracting and retaining executive officers. Salary and cash bonuses are viewed as secondary. However, the compensation committee views a competitive level of salary and cash bonus as critical to retaining talented individuals.
CVR Energy has not established equity ownership requirements for its executive officers. The compensation committee believes that cash-settled equity-based awards provide executive officers with a more attractive compensation package and are less burdensome for the executive officers and CVR Energy to administer than equity-settled awards. The compensation committee believes that equity-based compensation in the form of awards of CVR Energy's common stock would be less attractive and more burdensome. Additionally, equity-based compensation in the form of CVR Energy's common stock would dilute the ownership interest of existing stockholders.
The compensation committee has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and current compensation, between cash and non-cash compensation, or among different forms of compensation other than its belief that the most crucial component is equity-based compensation. The decision is strictly made on a subjective and individual basis after consideration of all relevant factors. The compensation committee believes that the most critical component of compensation to enhance long-term stockholder value and growth is the equity-based component and has generally targeted 40% to 60% of the compensation package to be equity-based for executive officers, other than the chief executive officer. This provides the incentive for executive officers to remain in the employ of CVR Energy and to promote a focused effort on growth and long-term success with long-term enhancement of stockholder value. The chief executive officer of CVR Energy, while not a member of the compensation committee, reviews information provided to CVR Energy by an independent compensation consultant, Longnecker, as well as other relevant market information and actively provides guidance and recommendations to the committee regarding the amount and form of the compensation of other executives and key employees.
Longnecker was engaged by CVR Energy to generally assess the level of compensation increases year over year and to assess new and proposed rules in the compensation area. The compensation committee utilized this information, along with other market survey and general industry survey information provided by CVR Energy to review and approve executive compensation levels. Although no specific target for total compensation is set, CVR Energy generally recommends compensation levels at or near the 50th percentile of the available market survey and general industry survey information.
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Base Salary. Messrs. Lipinski and Power each had an employment agreement with CVR Energy, which agreements expired December 31, 2017 in connection with their retirement, that set forth their respective initial base salary. Mr. Lamp has an employment agreement with CVR Energy that sets forth his initial base salary. Ms. Ball and Mr. Walter do not have employment agreements. Base salaries are set at a level intended to enable CVR Energy to hire and retain executives, to enhance the executive's motivation in a highly competitive and dynamic environment, and to reward individual and company performance. In determining base salary levels, the compensation committee takes into account the following factors: (i) CVR Energy's financial and operational performance for the year; (ii) the previous years' compensation level for each executive; (iii) market survey and general industry survey information for comparable public companies; and (iv) recommendations of the chief executive officer, based on individual responsibilities and performance, including each executive's commitment and ability to (a) strategically meet business challenges, (b) achieve financial results, (c) promote legal and ethical compliance, (d) lead their own business or business team for which they are responsible and (e) diligently and effectively respond to immediate needs of the volatile industry and business environment.
Rather than establishing compensation solely on a formula-driven basis, decisions by the compensation committee are made using an approach that considers several important factors in developing compensation levels. For example, the compensation committee considers whether individual base salaries reflect responsibility levels and are reasonable, competitive and fair. In addition, in setting base salaries, CVR Energy's compensation committee reviews published and other market survey and general industry survey information and considers the applicability of the salary data in view of the individual positions within CVR Energy.
Salaries are reviewed annually by the compensation committee with periodic informal reviews throughout the year. Adjustments, if any, are usually made effective January 1 of the year immediately following the review. The compensation committee most recently reviewed the level of base salary and cash bonus for each of the named executive officers in 2017 in conjunction with their responsibilities and expectations for 2018. Mr. Lamp's base salary of $1,000,000 was set in November 2017 in connection with the execution of his employment agreement. The compensation committee initially reviewed the base salaries of the remaining named executive officers in November 2017, and as of January 1, 2018 set base salaries for Ms. Ball at $440,000 and for Mr. Walter at $312,000. The compensation committee recently reviewed the base salaries for Ms. Ball and Mr. Walter and revised them to $500,000 and $380,000, respectively, effective February 2018. Individual performance, market data and changes in the named executive officers' positions and levels of responsibility were considered. Among these three factors, slightly more weight was given to market data.
Annual Bonus. CVR Energy's annual bonus program is designed to meet each of its compensation objectives. Specifically, CVR Energy's annual bonus programs rewards executives only for measured company performance, thereby aligning the executive's interest with those of its equity holders and encouraging executives to focus on targeted performance. Further, the program also provides executives with the opportunity to earn additional compensation, thereby making our total compensation package more competitive.
Information about total cash compensation paid by members of CVR Energy's industry is used in determining both the level of bonus award and the ratio of salary to bonus, as the compensation committee believes that maintaining a level of bonus and a ratio of fixed salary to bonus (which may fluctuate) that is in line with those of our competitors is an important factor in attracting and retaining executives. The compensation committee also believes that a significant portion of an executive's compensation should be at risk, which means that a portion of the executive's overall compensation is not guaranteed and is determined based on individual and company performance. Executives have greater potential bonus awards as the authority and responsibility of an executive increases. The named executive officers are eligible to receive an annual cash bonus with a target bonus equal to a specified percentage of the relevant executive's annual base salary. For 2017, the target bonuses for the named executive officers were: John J. Lipinski (250%), Susan M. Ball (120%), John R. Walter (110%) and Martin J. Power (115%). Mr. Lamp was not eligible for an annual bonus for 2017 under the terms of his employment agreement. These target percentages were the result of individual negotiations between the named executive officers and CVR Energy, and were in correlation with the market data and other general industry survey information provided by CVR Energy. Specific bonus measures were determined by the compensation committee, following discussions with CVR Energy management.
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Each named executive officer (other than Mr. Lamp) had the opportunity to earn bonuses in respect of 2017 pursuant to the CVR Energy PIP. The CVR Energy PIP has separate metrics specific to CVR Refining's financial, operational and safety measures, and Mr. Power's annual bonus is evaluated based on these metrics (and approved by our compensation committee) due to the substantial amount of their time that is devoted to CVR Refining. These metrics and the annual bonus earned by Mr. Power is described above in "Annual Bonus" under “CVR Refining’s Compensation Programs”. The payment of annual bonuses for the 2017 performance year was dependent upon the achievement of financial, operational and safety measures, which comprised 35%, 45% and 20% of the annual bonuses, respectively, for Messrs. Lipinski and Walter and Ms. Ball. Specific bonus measures were determined by the compensation committee based on its review of relevant market data and discussions with management, and were selected with the goals of optimizing operations, maintaining financial stability and providing a safe work environment intended to maximize CVR Energy's overall performance resulting in increased stockholder value. The compensation committee also approved the threshold, target and maximum performance goals with respect to each measure. No payment is made with respect to the measures unless the threshold of the relevant performance measure is achieved.
The 2017 financial measures were consolidated adjusted EBITDA for CVR Energy, which was derived from earnings before interest, taxes, depreciation and amortization, and adjusted for first-in, first-out (FIFO) accounting impacts, unrealized gains and losses on derivative transactions, turnaround expenses, loss on extinguishment of debt, asset impairment charges, non-controlling interest, and board-directed actions.
The 2017 operational measures include the following: petroleum reliability for the total Coffeyville and Wynnewood refineries, measured by crude throughput barrels per day, as adjusted at the discretion of our compensation committee for third party events; crude transportation production, measured by gathered barrels per day; and fertilizer reliability for the Coffeyville and East Dubuque fertilizer plants, measured by adjusted equivalent tons of UAN production.
The 2017 safety measures include the aggregated EH&S results for the petroleum segment pursuant to the CVR Energy PIP and the aggregated EH&S results pursuant to the CVR Partners PIP, which include the following: consolidated OSHA recordable injury statistics (based upon OSHA injuries and inclusive of petroleum and fertilizer); consolidated OSHA lost time injury statistics (based upon OSHA lost time injuries and inclusive of petroleum and fertilizer); consolidated EH&S severity statistics (based upon EH&S severity and inclusive of petroleum and fertilizer); consolidated air reportable releases (based upon EPA reportable quantity releases and inclusive of petroleum and fertilizer operations); consolidated air reportable release quantity (based upon EPA reportable quantity releases and inclusive of petroleum and fertilizer operations); consolidated tier 1 process safety events (based upon API process safety events of petroleum and fertilizer operations); and consolidated tier 2 process safety events (based upon API process safety events of petroleum and fertilizer operations).
The table below reflects the: (i) financial, operational and safety measures used to determine 2017 bonuses for the named executive officers; (ii) threshold, target and maximum performance levels for each measure; (iii) actual results with respect to each measure; and (iv) portion of the 2017 bonus that will be determined based on each such measure. The executives may receive 50% related to threshold levels, 100% for target levels, and 150% for maximum levels, respectively.
2017 Performance Measure | 2017 Performance Goals Threshold/Target/Maximum | 2017 Actual Results | Portion of Target Bonus Allocable to Measure | |||
Consolidated adjusted EBITDA for CVR Energy | Threshold: $353.0 million Target: $394.0 million Maximum: $477.0 million | $458.2 million | 35% of bonus for Messrs. Lipinski and Walter and Ms. Ball | |||
Petroleum Reliability Measures (as adjusted) | Threshold: 178,200 bpd Target: 190,200 bpd Maximum: 200,700 bpd | 205,263 bpd | 30% of bonus for Messrs. Lipinski and Walter and Ms. Ball | |||
Crude Transportation Production Measures | Threshold: 72,000 gathered bpd Target: 76,000 gathered bpd Maximum: 80,000 gathered bpd | 85,735 gathered bpd | 5% of bonus for Messrs. Lipinski and Walter and Ms. Ball | |||
Fertilizer Reliability Measures | Threshold: 1,920,000 tons Target: 1,980,000 tons Maximum: 2,090,000 tons | 2,050,658 tons | 10% of bonus for Messrs. Lipinski and Walter 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 | 13.5% | 10% of bonus for Messrs. Lipinski and Walter 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 | 5.5% | 5% of bonus for Messrs. Lipinski and Walter 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 | 5.2% | 5% of bonus for Messrs. Lipinski and Walter and Ms. Ball | |||
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As a result of these levels of performance, Messrs. Lipinski and Walter and Ms. Ball earned approximately 138.42% of their respective target bonuses.
Equity-Based Incentive Awards
CVR Energy also uses equity-based incentives to reward long-term performance of its named executive officers. The issuance of equity-based incentives to executive officers is intended to satisfy CVR Energy's compensation program objectives by generating significant future value for each named executive officer if CVR Energy's performance is outstanding and the value of CVR Energy's equity increases for all of its stockholders. The compensation committee believes that its equity-based incentives promote long-term retention of executives.
CVR Energy established a long term incentive plan in October 2007 (the "CVR Energy LTIP") in connection with its initial public offering. In addition, CVR Energy has historically issued incentive units outside of the CVR Energy LTIP, but based on the equity of CVR Refining and otherwise consistent with the terms of the CVR Energy LTIP. The compensation committee may elect to make grants of restricted stock, options, restricted stock units or other equity-based grants under the CVR Energy LTIP, or make grants of incentive units, in each case, in its discretion or may recommend grants to the Board for its approval, as determined by the committee in its discretion.
Perquisites. CVR Energy pays for the cost of supplemental life insurance for certain of its named executive officers. Except for the premiums associated with such supplemental life insurance, the total value of all perquisites and personal benefits provided to each of its named executive officers in 2017 was less than $10,000.
Other Forms of Compensation. Mr. Lamp has, and Mr. Lipinski previously had, provisions in their respective employment agreements with CVR Energy that provide for severance benefits in the event a termination of their employment under certain circumstances. These severance provisions are described below in " — Change-in-Control and Termination Payments" and were negotiated between the applicable named executive officers and CVR Energy.
Compensation Committee Report
The compensation committee of our general partner has reviewed and discussed the Compensation Discussion and Analysis with management. Based on this review and discussion, the compensation committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this Annual Report.
Compensation Committee
Andrew Langham (Chairman)
Jonathan Frates
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Summary Compensation Table
The following table sets forth the compensation paid to the named executive officers during the years ended December 31, 2017, 2016 and 2015 (except as otherwise designated below). In the case of named executive officers who are employed by CVR Energy, all compensation paid to such named executive officers by CVR Energy is reflected in the table, not only the portion of compensation attributable to services performed for our business.
Name and Principal Position | Year | Salary ($) | Bonus ($) (1) | Stock Awards ($)(2) | Non-Equity Incentive Plan Compensation ($)(3) | All Other Compensation ($)(4) | Total ($) | |||||||||||||
John J. Lipinski, | 2017 | 1,000,000 | — | 3,460,500 | 38,698 | 4,499,198 | ||||||||||||||
Chief Executive Officer and | 2016 | 1,000,000 | — | 5,898,750 | 36,949 | 6,935,699 | ||||||||||||||
President | 2015 | 1,000,000 | — | 7,187,500 | 32,214 | 8,219,714 | ||||||||||||||
David L. Lamp, | 2017 | 42,308 | 75,000 | — | 1,500,000 | — | 1,617,308 | |||||||||||||
Chief Executive Officer and | ||||||||||||||||||||
President | ||||||||||||||||||||
Susan M. Ball, | 2017 | 425,000 | 969,987 | 705,942 | 19,612 | 2,120,541 | ||||||||||||||
Chief Financial Officer and | 2016 | 425,000 | 945,009 | 489,345 | 19,082 | 1,878,436 | ||||||||||||||
Treasurer | 2015 | 415,000 | 945,003 | 673,338 | 18,703 | 2,052,044 | ||||||||||||||
John R. Walter | 2017 | 299,616 | 492,990 | 456,786 | 16,987 | 1,266,379 | ||||||||||||||
Senior Vice President, | 2016 | 290,000 | 450,005 | 297,497 | 16,517 | 1,054,019 | ||||||||||||||
General Counsel, and Secretary | 2015 | 275,000 | 431,018 | 405,625 | 16,330 | 1,127,973 | ||||||||||||||
David L. Landreth | 2017 | 272,500 | 495,999 | 354,386 | 24,894 | 1,147,779 | ||||||||||||||
Senior Vice President, | 2016 | 272,500 | 460,008 | 225,834 | 23,636 | 981,978 | ||||||||||||||
Economics and Planning | 2015 | 265,000 | 460,002 | 308,990 | 21,202 | 1,055,194 | ||||||||||||||
Martin J. Power, | 2017 | 330,000 | — | 552,248 | 19,657 | 901,905 | ||||||||||||||
Chief Commercial Officer | 2016 | 330,000 | 650,005 | 371,531 | 18,078 | 1,369,614 | ||||||||||||||
2015 | 325,000 | 650,012 | 510,705 | 18,078 | 1,503,795 | |||||||||||||||
______________________________________
(1) | The amount in this column for Mr. Lamp includes a $75,000 relocation bonus. |
(2) | For 2015, 2016 and 2017, the above table reflects the aggregate grant date fair value for incentive units granted to Ms. Ball and Messrs. Walter and Power by CVR Energy in December 2015, 2016 and 2017, and for phantom units granted to Mr. Landreth by CVR Refining in December 2015, 2016 and 2017, 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 incentive units pursuant to the services agreement. |
(3) | Amounts in this column for 2017, 2016 and 2015 reflect amounts earned pursuant to the CVR Energy PIP in respect of performance during those years, paid in 2018, 2017, and 2016 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. For Mr. Lamp, the amounts for 2017 reflects the aggregate grant date fair value for certain performance units granted in November 2017, of $1,500,000, that are valued based on performance factors that are tied to certain operational performance metrics. |
(4) | Amounts in this column for 2017 include the following: (a) a company contribution under the CVR Energy 401(k) plan for each named executive officer (other than Mr. Lamp) of $16,200; (b) $15,640 for Mr. Lipinski, $2,170 for Ms. Ball, $257 for Mr. Walter and $5,138 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, $1,242 for Ms. Ball, $530 for Mr. Walter, $3,457 for Mr. Power and $3,556 for Mr. Landreth in taxable value (inclusive of associated premiums) provided by CVR Energy on behalf of the executive officer with respect to its basic life insurance program. |
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As described in more detail in the Compensation Discussion and Analysis, during 2017 our named executive officers were employed by CVR Energy and dedicated only a portion of their time to our business in 2017, except for Mr. Landreth who is employed by our general partner and dedicated 100% of his time to the business. The following 2017 cash compensation paid to the named executive officers who are employed by CVR Energy was attributable to their service to our business, based on the percentage of time that each of them dedicated to our business during 2017:
Name | Salary ($) | Stock Awards ($) | Non-Equity Incentive Compensation ($) | Other ($) | ||||||||
John J. Lipinski | 500,000 | — | 1,730,250 | 19,349 | ||||||||
David L. Lamp | 21,154 | — | 750,000 | 37,500 | ||||||||
Susan M. Ball | 233,750 | 533,493 | 388,268 | 10,787 | ||||||||
John R. Walter | 122,842 | 202,126 | 187,282 | 6,965 | ||||||||
Martin J. Power | 313,500 | — | 524,636 | 18,675 | ||||||||
_______________________________________
Grants of Plan-Based Awards
The following table sets forth information regarding amounts that could have been earned under the CVR Energy PIP, CVR Energy LTIP and CVR Refining LTIP with respect to the 2017 year, as well as certain incentive unit awards made to our named executive officers.
Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | ||||||||||||||||||
Name | Grant Date | Threshold ($) | 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 | — | — | ||||||||||||
David L. Lamp | 11/01/17 | 1,050,000 | 1,500,000 | 1,650,000 | ||||||||||||||
Susan M. Ball | — | 255,000 | 510,000 | 765,000 | — | — | ||||||||||||
12/29/17 | — | — | — | 74,787 | 969,987 | |||||||||||||
Martin J. Power | — | 189,750 | 379,500 | 569,250 | — | — | ||||||||||||
John R. Walter | 165,000 | 330,000 | 495,000 | |||||||||||||||
12/29/17 | 38,010 | 492,990 | ||||||||||||||||
David L. Landreth | — | 122,625 | 245,250 | 367,875 | — | — | ||||||||||||
12/29/17 | — | — | — | 38,242 | 495,999 | |||||||||||||
_______________________________________
(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 2017 performance at the threshold, target and maximum levels with respect to each performance measure. The performance measures and related goals for 2017 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. Lamp, amounts also reflect amounts that could be earned under certain performance units issued in November 2017 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 Mr. Walter by CVR Energy during 2017, and a phantom unit award to Mr. Landreth under the CVR Refining LTIP during 2017, in each case, computed in accordance with FASB ASC Topic 718. |
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Employment Agreements
John J. Lipinski. CVR Energy most recently entered into an employment agreement with Mr. Lipinski, as chief executive officer, effective as of January 1, 2016. The agreement had a two-year term and expired December 31, 2017 in connection with Mr. Lipinski's retirement. Mr. Lipinski received an annual base salary of $1,000,000 effective as of January 1, 2017. Mr. Lipinski was also eligible to receive a performance-based annual cash bonus with a target payment equal to 250% of his annual base salary for 2017, to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy. In addition, Mr. Lipinski was entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. During the term of the agreement, Mr. Lipinski was eligible to receive annually (commencing December 31, 2015) on the anniversary of the agreement date a grant of performance units pursuant to the CVR Energy LTIP having an aggregate value of $3.5 million. The material terms of the performance units are described below. Mr. Lipinski was also eligible to receive an incentive payment of $5 million if (i) CVR Energy (or a subsidiary thereof) obtained an equity or management interest in a logistics master limited partnership (a "Logistics MLP") in a transaction approved by CVR Energy’s (or such subsidiary’s) Board of Directors, provided such Logistics MLP results from an initial public offering, spin transaction, acquisition or joint venture, and (ii) such Logistics MLP was trading on a national securities exchange on or prior to December 31, 2017. Payment of the incentive payment was conditioned upon (x) the foregoing performance objectives being achieved, and (y) Mr. Lipinski remaining employed with CVR Energy through December 31, 2017 (unless, if an employment termination occurs earlier than December 31, 2017, such termination (A) occurs after achievement of such performance objectives and (B) is carried out by CVR Energy without cause or by Mr. Lipinski for good reason (as such terms are defined in the employment agreement)). The employment agreement provides that any such incentive payment will be the obligation of the Logistics MLP and not of CVR Energy. The agreement required Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement and also included covenants relating to non-solicitation and non-competition that govern during his employment and thereafter for the period severance is paid and, if no severance is paid, for six months following termination of employment. In addition, Mr. Lipinski's agreement provided for certain severance payments that may be due following the termination of his employment under certain circumstances, which are described below under " — Change-in-Control and Termination Payments."
David L. Lamp. On November 1, 2017, CVR Energy entered into an employment agreement with Mr. Lamp, as chief executive officer, effective December 1, 2017. The agreement has a four-year term continuing through December 31, 2021, unless otherwise terminated by CVR Energy or Mr. Lamp. Mr. Lamp receives an annual base salary of $1,000,000 and is also eligible to receive a performance-based annual cash bonus with a target payment equal to 150% of his annual base salary, to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy. In addition, Mr. Lamp is entitled to participate in such health, insurance, retirement and other employee benefit plans an programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. During the term of the agreement, Mr. Lamp is eligible to receive annually (commencing on November 1, 2017) on the anniversary of the agreement date a grant of performance units pursuant to the CVR Energy LTIP having an aggregate value of $1.5 million. The material terms of the performance units are described below. Mr. Lamp is also eligible to receive an incentive payment of $10 million (the “Incentive Payment”) pursuant to an additional performance unit award under the CVR Energy LTIP. The Incentive Payment becomes payable if either the conditions set forth in the employment agreement or the conditions set forth in a separate Performance Unit Award Agreement (“PU Award Agreement”) (described below) are fulfilled. Pursuant to the employment agreement, the Incentive Payment becomes payable if on or prior to December 31, 2021, either (a) a transaction is consummated which constitutes a change in control (as defined in the employment agreement), or (b) the board approves a transaction which, if consummated, would constitute a change in control and such transaction is consummated on or prior to December 31, 2022. Payment of the Incentive Payment is conditioned upon Mr. Lamp remaining employed with CVR Energy through December 30, 2021 (unless terminated by CVR Energy without cause or by Mr. Lamp for good reason on or after the satisfaction of the foregoing conditions and prior to December 30, 2021). Subject to the foregoing conditions, the Incentive Payment will, if it becomes payable, be paid within 30 days following the consummation of the transaction constituting a change in control. For the avoidance of doubt, Mr. Lamp will not under any circumstance be entitled to receive more than one Incentive Payment and if he becomes entitled to the Incentive Payment under the terms of his employment agreement, Mr. Lamp will immediately forfeit any right to payments under the PU Award Agreement. The agreement required Mr. Lamp to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement and also included covenants relating to non-solicitation and non-competition that govern during his employment and thereafter for the period severance is paid and, if no severance is paid, for six months following termination of employment. In addition, Mr. Lamp's agreement provided for certain severance payments that may be due following the termination of his employment under certain circumstances, which are described below under " — Change-in-Control and Termination Payments."
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Martin J. Power. Effective December 1, 2014, CVR Energy entered into an employment agreement with Mr. Power. The agreement with Mr. Power had a term extending through December 31, 2017, and expired on such date in connection with his retirement. Mr. Power received an annual base salary of $330,000 effective January 1, 2017. He was also eligible to receive a performance-based annual cash bonus to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy (which was set at 115% for 2017). Mr. Power was also entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. The agreement required Mr. Power to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement, and also included covenants relating to non-solicitation and non-competition during his employment and for a period of one year and six months, respectively, following termination of employment. In addition, the employment agreement provided for certain severance payments that may be due following the termination of employment under certain circumstances, which are described below under " — Change-in-Control and Termination Payments."
Susan M. Ball, John R. Walter and David L. Landreth. Ms. Ball and Messrs. Walter and Landreth do not have employment agreements. Their current base salaries are as follows: Ms. Ball - $500,000; Mr. Walter - $380,000; and Mr. Landreth - $430,000. In addition, each such named executive officer is entitled to participate in such health, insurance, retirement and other employee benefit plans and programs as in effect from time to time on the same basis as other senior executives.
Outstanding Equity Awards at Fiscal Year End
The following table sets forth information concerning outstanding equity awards granted pursuant to the CVR Refining LTIP that were held by certain of the named executive officers as of December 31, 2017, as well as outstanding incentive unit awards made by CVR Energy and for which, the Partnership will share in the expense.
Stock Awards | ||||||||
Name | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($)(1) | ||||||
Susan M. Ball | 15,411 | (2 | ) | 269,538 | ||||
66,950 | (3 | ) | 1,170,956 | |||||
74,787 | (4 | ) | 1,237,725 | |||||
John R. Walter | 7,029 | (2 | ) | 122,937 | ||||
31,881 | (3 | ) | 557,599 | |||||
38,010 | (4 | ) | 629,066 | |||||
David L. Landreth | 7,501 | (5 | ) | 131,192 | ||||
32,590 | (6 | ) | 569,999 | |||||
38,242 | (7 | ) | 632,905 | |||||
_______________________________________
(1) | This column represents the number of unvested units outstanding on such date, multiplied by the closing price of the units on December 29, 2017, which: (i) for purposes of the incentive units described in footnote (2) and the phantom units described in footnote (5) below, was $17.49 (the closing price of $16.55 plus $0.94 in accrued distributions); (ii) for purposes of the incentive units described in footnote (3) and the phantom units described in footnote (6) below was $17.49 (the closing price of $16.55 plus $0.94 in accrued distributions); and (iii) for purposes of the incentive units described in footnote (4) and the phantom units described in footnote (7) below was $16.55. |
(2) | The incentive units reflected were issued on December 18, 2015 and are scheduled to vest on December 18, 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. |
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(3) | The incentive units reflected were issued on December 31, 2016 and are scheduled to vest in one-half annual increments on December 16, 2018 and 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. |
(4) | The incentive units reflected were issued on December 29, 2017 and are scheduled to vest in one-third annual increments on December 15 of 2018 through 2020, 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 phantom units reflected were issued on December 18, 2015 and are scheduled to vest on December 18, 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. |
(6) | The phantom units reflected were issued on December 31, 2016 and are scheduled to vest in one-half annual increments on December 16, 2018 and 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. |
(7) | The phantom units reflected were issued on December 29, 2017 and are scheduled to vest in one-third annual increments on December 15 of 2018 through 2020, 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 Vested During Fiscal Year 2017
This table reflects the portion of phantom units granted pursuant to the CVR Refining LTIP as well as incentive awards made by CVR Energy and for which, the Partnership will share in the expense, that became vested during 2017.
Equity Awards | |||||||
Named Executive Officer | Number of Shares or Units Acquired on Vesting (#) | Value Realized on Vesting ($) | |||||
Susan M. Ball | 17,474 | 311,561 | (1) | ||||
15,411 | 215,908 | (2) | |||||
33,476 | 468,999 | (3) | |||||
John R. Walter | 7,751 | 138,200 | (1) | ||||
7,029 | 98,476 | (2) | |||||
15,941 | 223,333 | (3) | |||||
David L. Landreth | 8,455 | 150,753 | (4) | ||||
7,502 | 105,103 | (5) | |||||
16,295 | 228,293 | (6) | |||||
Martin J. Power | 13,232 | 235,927 | (1) | ||||
10,600 | 148,506 | (2) | |||||
23,026 | 322,594 | (3) | |||||
(1) | For incentive units that became vested during fiscal year 2017, 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 $4.06 per unit. |
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(2) | For incentive units that became vested during fiscal year 2017, 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 $0.94 per unit. |
(3) | For incentive units that became vested during fiscal year 2017, 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, plus (ii) accrued distributions of $0.94 per unit. |
(4) | For phantom units that became vested during fiscal year 2017, 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 $4.06 per unit. |
(5) | For phantom units that became vested during fiscal year 2017, 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 $0.94 per unit. |
(6) | For phantom units that became vested during fiscal year 2017, 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 $0.94 per unit. |
Reimbursement of Expenses of Our General Partner
Our general partner and its affiliates are reimbursed for expenses incurred on our behalf under the services agreement. See "Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy and CVR Refining — "Services Agreement" for a description of our services agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business and allocable to us. These expenses also include costs incurred by CVR Energy or its affiliates in rendering corporate staff and support services to us pursuant to the services agreement, including a pro-rata portion of the compensation of CVR Energy's executive officers who provide management services to us based on the amount of time such executive officers devote to our business. For services provided during the year ending December 31, 2017, the total amount paid or payable to our general partner and its affiliates (including amounts paid to CVR Energy pursuant to the services agreement) was approximately $71.5 million.
Our partnership agreement provides that our general partner determines which of its affiliates' expenses are allocable to us and the services agreement provides that CVR Energy invoice us monthly for services provided thereunder. Our general partner may dispute the costs that CVR Energy charges us under the services agreement, but we are not entitled to a refund of any disputed cost unless it is determined not to be a reasonable cost incurred by CVR Energy in connection with services it provided.
Change-in-Control and Termination Payments
Under the terms of certain of the named executive officers' employment agreements with CVR Energy, they may be entitled to severance and other benefits from CVR Energy following the termination of their employment with CVR Energy. The amounts of potential post-employment payments and benefits in the narrative and table below with respect to Messrs. Lipinski, Lamp and Power assume the triggering event took place on December 31, 2017, are based on salaries as of December 31, 2017 and assume the payment of bonuses at 100% of target. Pursuant to the services agreement that we entered into with CVR Energy in connection with the Initial Public Offering, we are responsible for the payment of our proportionate share of the severance and other benefits costs following the termination of employment of the executive officers that are employed by CVR Energy.
John J. Lipinski. If Mr. Lipinski's employment was terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in his employment agreement), then in addition to any accrued amounts, including any base salary earned but unpaid through the date of termination, any earned but unpaid annual bonus for completed fiscal years, any unused accrued paid time off and any unreimbursed expenses ("Accrued Amounts"), Mr. Lipinski would have been entitled to receive as severance: (i) salary continuation for the lesser of six months and the remainder of the term of the employment agreement (such period, the "Lipinski Post-Employment Period"); and (ii) a pro-rata bonus for the year in which termination occurs based on actual results. In addition, if Mr. Lipinski's employment was terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in his employment agreement) within one year following a change in control (as defined in his employment
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agreement) or in specified circumstances prior to and in connection with a change in control, Mr. Lipinski would have been entitled to receive 1/6 of his target bonus for the year of termination for each month of the Lipinski Post-Employment Period.
If Mr. Lipinski's employment was terminated as a result of his disability, then in addition to any Accrued Amounts and any payments to be made to Mr. Lipinski under disability plan(s), Mr. Lipinski would have been entitled to disability payments during the Lipinski Post-Employment Period equal to the base rate of Mr. Lipinski's base salary as in effect immediately before his disability (the estimated total amount of this payment is set forth in the relevant table below) and a pro-rata bonus for the year in which termination occurs based on actual results. As a condition to receiving these severance payments and benefits, Mr. Lipinski would have been required to execute, deliver and not revoke a general release of claims and abide by restrictive covenants as detailed below. If Mr. Lipinski's employment was terminated at any time by reason of his death, then in addition to any Accrued Amounts, Mr. Lipinski's beneficiary (or his estate) would have been paid the base salary Mr. Lipinski would have received had he remained employed through the Lipinski Post-Employment Period, and a pro-rata bonus for the year in which termination occurs based on actual results. Notwithstanding the foregoing, CVR Energy may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lipinski's supplemental disability payments or the payments due to Mr. Lipinski's beneficiary or estate by reason of his death. Mr. Lipinski would be required to cooperate in obtaining such insurance. Mr. Lipinski does not receive any payments or benefits in the event of retirement.
If any payments or distributions due to Mr. Lipinski would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be "cut back" only if that reduction would be more beneficial to him on an after-tax basis than if there was no reduction. The estimated total amounts payable to Mr. Lipinski (or his beneficiary or estate in the event of death) in the event of termination of employment under the circumstances described above are set forth in the table below. Mr. Lipinski would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by him voluntarily without good reason. The agreement required Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement. The agreement also included covenants relating to non-solicitation and non-competition during Mr. Lipinski's employment term, and thereafter during the period he receives severance payments or supplemental disability payments, as applicable, or for six months following the end of the term (if no severance or disability payments are payable).
David L. Lamp. If Mr. Lamp's employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lamp for good reason (as these terms are defined in his employment agreement), then in addition to any Accrued Amounts, Mr. Lamp is entitled to receive as severance: (i) salary continuation for the lesser of six months and the remainder of the term of the employment agreement (such period, the "Lamp Post-Employment Period"); and (ii) a pro-rata bonus for the year in which termination occurs based on actual results. In addition, if Mr. Lamp's employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lamp for good reason (as these terms are defined in his employment agreement) within one year following a change in control (as defined in his employment agreement) or in specified circumstances prior to and in connection with a change in control, Mr. Lamp will receive the Incentive Payment within 30 days following the consummation of the change in control.
If Mr. Lamp's employment is terminated as a result of his disability, then in addition to any Accrued Amounts and any payments to be made to Mr. Lamp under disability plan(s), Mr. Lamp is entitled to disability payments during the Lamp Post-Employment Period equal to the base rate of Mr. Lamp's base salary as in effect immediately before his disability (the estimated total amount of this payment is set forth in the relevant table below) and a pro-rata bonus for the year in which termination occurs based on actual results. As a condition to receiving these severance payments and benefits, Mr. Lamp must execute, deliver and not revoke a general release of claims and abide by restrictive covenants as detailed below. If Mr. Lamp's employment is terminated at any time by reason of his death, then in addition to any Accrued Amounts, Mr. Lamp's beneficiary (or his estate) will be paid the base salary Mr. Lamp would have received had he remained employed through the Lamp Post-Employment Period, and a pro-rata bonus for the year in which termination occurs based on actual results. Notwithstanding the foregoing, CVR Energy may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lamp's supplemental disability payments or the payments due to Mr. Lamp's beneficiary or estate by reason of his death. Mr. Lamp would be required to cooperate in obtaining such insurance. Mr. Lamp does not receive any payments or benefits in the event of retirement.
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If any payments or distributions due to Mr. Lamp would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be "cut back" only if that reduction would be more beneficial to him on an after-tax basis than if there was no reduction. The estimated total amounts payable to Mr. Lamp (or his beneficiary or estate in the event of death) in the event of termination of employment under the circumstances described above are set forth in the table below. Mr. Lamp would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by him voluntarily without good reason. The agreement requires Mr. Lamp to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement. The agreement also includes covenants relating to non-solicitation and non-competition during Mr. Lamp's employment term, and thereafter during the period he receives severance payments or supplemental disability payments, as applicable, or for six months following the end of the term (if no severance or disability payments are payable).
Martin J. Power. If the employment of Mr. Power was terminated either by CVR Energy without cause and other than for disability or by Mr. Power for good reason (as such terms are defined in his employment agreement), then Mr. Power would have been entitled, in addition to any Accrued Amounts, to receive as severance (a) salary continuation for the lesser of six months or the remainder of the term of the agreement, (b) a pro-rata bonus for the year in which termination occurs based on actual results and (c) subject to his timely election, and the availability thereof, continuation coverage under our general partner's group health plan as provided under Part 6 of Title I of the Employment Retirement Income Security Act of 1974 (as amended) and Section 4980B of the Internal Revenue Code of 1986 (as amended) (collectively, “COBRA”) for the applicable continuation period under COBRA.
As a condition to receiving these severance payments and benefits, Mr. Power would have been required to (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreement provided that if any payments or distributions due to Mr. Power would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be cut back only if that reduction would be more beneficial to the executive officer on an after-tax basis than if there were no reduction. Mr. Power would solely be entitled to Accrued Amounts, if any, upon the termination of employment by our general partner for cause, or by Mr. Power voluntarily without good reason. The agreement required Mr. Power to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement. The agreement also included covenants relating to non-solicitation and non-competition during the employment term and for six months and one year, respectively, following the end of the term.
Susan M. Ball, John R. Walter and David L. Landreth. Ms. Ball and Messrs. Walter and Landreth do not have employment agreements and are not entitled to any severance and other benefits from CVR Energy or our general partner following the termination of their employment.
Cash Severance ($) | Benefit Continuation ($)(3) | ||||||||||||||||||||||||||||
Death | Disability | Retirement | Termination without Cause or with Good Reason | Death | Disability | Retirement | Termination without Cause or with Good Reason | ||||||||||||||||||||||
(1) | (2) | (1) | (2) | ||||||||||||||||||||||||||
John J. Lipinski(4) | 2,500,000 | 2,500,000 | — | 2,500,000 | 2,500,000 | — | — | — | — | — | |||||||||||||||||||
David L. Lamp | 500,000 | 500,000 | — | 500,000 | 10,500,000 | — | — | — | — | — | |||||||||||||||||||
Martin J. Power(5) | — | — | — | 379,500 | 379,500 | — | — | — | — | — | |||||||||||||||||||
_______________________________________
(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. |
(4) | The table above shows the payment of Mr. Lipinski's bonus at target under the described circumstances. Mr. Lipinski retired December 31, 2017 concurrent with the expiration of his employment agreement. Under the terms of his employment agreement following expiration, he received his actual earned bonus for 2017, as disclosed in the Summary Compensation Table of $3,460,500. |
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(5) | The table above shows the payment of Mr. Power's bonus at target under the described circumstances. Mr. Power retired December 31, 2017 concurrent with the expiration of his employment agreement. Under the terms of his employment agreement following expiration, he received his actual earned bonus for 2017, as disclosed in the Summary Compensation Table of $552,248. |
Each of our named executive officers of our general partner who is employed by CVR Energy (except for Mr. Lipinski) has been granted incentive units by CVR Energy.
In December 2015, 2016 and 2017 CVR Energy granted Ms. Ball and Mr. Walter, and in December 2015 and 2016 CVR Energy granted Mr. Power, awards consisting of incentive units and distribution equivalent rights. Each incentive unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (a) the average fair market value of one unit of the CVR Refining's common units for the ten trading days preceding vesting, plus (b) the per unit cash value of all distributions declared and paid by CVR Refining from the grant date to and including the vesting date. The awards are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments on each annual vesting date, subject to immediate vesting under certain circumstances. With respect to Ms. Ball (for the 2015 award agreement), the award becomes immediately vested in the event of any of the following: (i) such named executive officer's employment is terminated other than for cause within the one-year period following a change in control; (ii) such named executive officer resigns from employment for good reason within the one year period following a change in control; or (iii) such named executive officer's employment is terminated under certain circumstances prior to a change in control. If (x) Ms. Ball or Messrs. Walter or Power is terminated other than for cause, or (y) Ms. Ball (for the 2015 award agreement) or Mr. Power (for the 2015-2016 award agreements) resigns for good reason in the absence of a change in control, or (z) if their respective employment is terminated due to death or disability, then the portion of the award scheduled to vest in the year in which such event occurs becomes immediately vested and the remaining portion is forfeited. Upon his retirement on December 31, 2017, Mr. Power forfeited any unvested incentive units granted by CVR Energy.
In December 2016, CVR Energy granted Mr. Lipinski an award of 3,500 performance units. The award represents the right to receive a cash payment equal to $1,000 multiplied by the applicable performance factor. The performance factor is determined based on the level of attainment of the applicable performance objective, set forth as a percentage, which may range from 0-110%. Seventy-five percent of the performance units attributable to the award are subject to a performance objective relating to the average barrels per day crude throughput during the performance cycle, and 25% of the performance units attributable to the award are subject to a performance objective relating to the average gathered crude barrels per day during the performance cycle. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and therefore are considered reasonably possible of being achieved. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2018. The award is subject to transfer restrictions and carries a performance cycle ending on December 31, 2017. In the event of Mr. Lipinski’s termination of employment prior to the applicable payment date by reason of Mr. Lipinski’s death or disability, all performance units with respect to which a payment date has not yet occurred will remain outstanding, and amounts due to Mr. Lipinski, if any, with respect to such performance units will be paid in the ordinary course as if his employment had not terminated based on actual results. In the event prior to the applicable payment date Mr. Lipinski's employment is terminated by CVR Energy other than for cause or by reason of Mr. Lipinski’s resignation for good reason, a pro rata portion of the performance units with respect to which a payment date has not yet occurred will remain outstanding, and amounts due to Mr. Lipinski, if any, with respect to such performance units will be paid in the ordinary course as if his employment had not terminated based on actual results. In the event that Mr. Lipinski’s employment terminates for any other reason prior to the dates set forth above, all performance units with respect to which a payment date has not yet occurred will be forfeited immediately.
In November 2017, CVR Energy granted Mr. Lamp an award of 1,500 performance units. The award represents the right to receive a cash payment equal to $1,000 multiplied by the applicable performance factor. The performance factor is determined based on the level of attainment of the applicable performance objective, and both the performance factor and performance objective(s) will be determined by CVR Energy's compensation committee. The amount paid pursuant to the award, if any, will be paid following the end of the performance cycle for the award, but no later than March 6, 2019. The award is subject to transfer restrictions and carries a performance cycle commencing January 1, 2018 and ending on December 31, 2018. In the event of Mr. Lamp's termination of employment prior to the applicable payment date by reason of Mr. Lamp's death or disability, all performance units with respect to which a payment date has not yet occurred will remain outstanding, and amounts due to Mr. Lamp, if any, with respect to such performance units will be paid in the ordinary course as if his employment had not terminated based on actual results. In the event prior to the applicable payment date Mr. Lamp's employment is terminated by CVR Energy other than for cause or by reason of Mr. Lamp's resignation for good reason, a pro rata portion of the performance units with respect to which a payment date has not yet occurred will remain outstanding, and
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amounts due to Mr. Lamp, if any, with respect to such performance units will be paid in the ordinary course as if his employment had not terminated based on actual results. In the event that Mr. Lamp's employment terminates for any other reason prior to the dates set forth above, all performance units with respect to which a payment date has not yet occurred will be forfeited immediately.
In November 2017, CVR Energy also entered into the PU Award Agreement in which Mr. Lamp was granted performance units with a cash value equal to the Incentive Payment. In addition to the change in control trigger described above, the award will vest and the Incentive Payment will become payable if the average closing price of CVR Energy’s common stock on the New York Stock Exchange over the 30-day trading period from January 4, 2022 to February 15, 2022 is equal to or greater than $60 per share. The award will be immediately forfeited and terminated if the foregoing vesting condition is not satisfied, or if at any time, on or prior to December 31, 2021, Mr. Lamp’s employment with CVR Energy is terminated for any or no reason, a change in control occurs, or the board approves a transaction, which, if consummated, would constitute a change in control. For the avoidance of doubt, Mr. Lamp will not under any circumstance be entitled to receive more than one Incentive Payment and if he becomes entitled to the Incentive Payment under the terms of the employment agreement, Mr. Lamp will immediately forfeit any right to payments under the PU Award Agreement.
The following table reflects the value of accelerated vesting of the unvested incentive units held by the named executive officers assuming the triggering event took place on December 31, 2017. For purposes of the December 2015 incentive unit award, the value is based on the 10-day average closing price of CVR Refining common units for the 10 trading days preceding December 31, 2017, or $14.96 per unit plus accrued distributions of $0.94 per unit. The table does not take into consideration the value of the performance units held by Mr. Lipinski (which is the only award held by Mr. Lipinski) since such performance units would not accelerate, but instead pay out in the ordinary course as if his employment had not terminated. The table also does not take into consideration the value of the performance units held by Mr. Lamp, since the performance cycle does not commence until January 1, 2018. Messrs. Walter and Power do not have any awards from CVR Energy that qualify for acceleration in the event of their termination as of December 31, 2017. Upon his retirement on December 31, 2017, Mr. Power forfeited any unvested incentive units granted by CVR Energy.
Value of Accelerated Vesting of Incentive Unit Awards
Death ($) | Disability ($) | Retirement ($) | Termination without Cause or with Good Reason ($) | |||||||||||
(1) | (2) | |||||||||||||
Susan M. Ball | — | — | — | — | 245,035 | |||||||||
_______________________________________
(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. |
Mr. Landreth was awarded phantom units and distribution equivalent rights pursuant to the CVR Refining LTIP in December 2015, 2016 and 2017. Each phantom unit and distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one unit of the CVR Refining's common units in accordance with the award agreement, plus (ii) the per unit cash value of all distributions declared and paid by the CVR Refining from the grant date to and including the vesting date. The award is subject to transfer restrictions and vesting requirements that lapse in one-third annual increments on each annual vesting date. If Mr. Landreth is terminated other than for cause, or if his employment is terminated due to death or disability, then the portion of the awards scheduled to vest in the year in which such event occurs becomes immediately vested and the remaining portion is forfeited.
Mr. Landreth does not have any awards from CVR Refining that qualify for acceleration in the event of his termination as of December 31, 2017.
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Pay Ratio
Pursuant to a mandate of the Dodd-Frank Wall Street Reform and Consumer Protection Act, the SEC adopted a rule requiring annual disclosure of the ratio of the total annual compensation of the Partnership's Principal Executive Officer ("PEO") to the median employee's annual total compensation. For 2017, we calculated this ratio using Mr. Lipinski as our PEO. Mr. Lipinski served as Chief Executive Officer and President and a director of our general partner until his retirement on December 31, 2017. Set forth below for 2017 is a comparison of (i) the median of the annual total compensation of all our employees and our consolidated subsidiaries (except our PEO) and (ii) the annual total compensation of our PEO (as adjusted to reflect the compensation attributable to his service to the Partnership). The median of the annual total compensation and the pay ratio described below are reasonable estimates calculated by the Partnership in a manner consistent with Item 402(u) of Regulation S-K.
We estimate that the median of the annual total compensation of all our employees and our consolidated subsidiaries (except our PEO) was $108,925 for 2017. The annual total compensation of Mr. Lipinski, our PEO for 2017, as reported in the Summary Compensation Table included in this Item 11, was $2,249,599 for 2017 (as adjusted to reflect the compensation attributable to his service to the Partnership).
Based on this information, we estimate that the ratio of the annual total compensation of our PEO to the median of the annual total compensation of all employees was 21 to 1 for 2017.
To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our PEO, we used the following methodology and made the following material assumptions, adjustments, and estimates:
1. For 2017, we calculated this ratio using Mr. Lipinski as our PEO. Mr. Lipinski served as Chief Executive Officer and President and a director of our general partner until his retirement on December 31, 2017. Mr. Lamp succeeded Mr. Lipinski and was appointed as co-Chief Executive Officer and President of our general partner on December 1, 2017 and joined the board of directors of our general partner effective January 1, 2018. We calculated the pay ratio for 2017 using Mr. Lipinski as our PEO, rather than Mr. Lamp, because Mr. Lipinski served in this capacity for the entirety of 2017 while Mr. Lamp served in this capacity for only one month.
2. We determined that, as of December 31, 2017, the employee population of the Partnership and its consolidated subsidiaries consisted of 959 individuals.
3. To identify the "median employee" from the employee population, we compared the amount of annual total compensation of such employees for 2017 determined in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, which consisted of salary, bonus, non-equity incentive plan compensation and other compensation. We "annualized" the compensation of our full-time and part-time permanent employees as of December 31, 2017 to adjust for the portion of the year that the employee did not work, if applicable. We did not make any cost-of-living adjustments in identifying the "median employee."
4. Once we identified our median employee, we included the elements of such employee's compensation for 2017 determined in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $108,925. With respect to the annual total compensation of our PEO, we used the amount reported in the "Total" column of our 2017 Summary Compensation Table included in this Item 11, which was calculated in accordance with the same requirements of Item 402(c)(2)(x) of Regulation S-K, as adjusted to reflect the portion of such amount attributable to our PEO's service to the Partnership as further described in the table immediately following our 2017 Summary Compensation Table.
Director Compensation
Officers, employees and directors of CVR Energy or its affiliates who serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Independent directors who are not officers, employees or directors of CVR Energy or its affiliates receive compensation for attending meetings of our general partner's board of directors and committees thereof. For 2017, independent directors receive an annual director fee of $75,000, paid quarterly, and meeting fees of $1,000 per meeting. In addition, independent directors also receive an additional annual retainer of $5,000 for serving as the chairman of any board committee, an additional annual retainer of $1,000 for serving on a board committee and are reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors (and committees thereof) of our general partner and for other director-related education expenses. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
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The following table sets forth the compensation earned by or paid to each independent director of our general partner for the year ended December 31, 2017.
Name | Fees Earned or Paid in Cash (1)($) | Unit Awards ($) | Total Compensation ($) | |||
Glenn R. Zander | 85,000 | — | 85,000 | |||
Kenneth Shea | 77,000 | — | 77,000 | |||
Jon R. Whitney | 82,000 | — | 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 2017. |
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The following table presents information regarding beneficial ownership of our common units as of February 20, 2018 by:
• | 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. |
Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all units beneficially owned, subject to community property laws where applicable. Except as otherwise indicated, the business address for each of our beneficial owners is 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479.
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 | * | |||
David L. Lamp | — | — | |||
Susan M. Ball | 8,000 | * | |||
John R. Walter | 1,000 | * | |||
David L. Landreth | 11,000 | * | |||
Martin J. Power(5) | — | — | |||
Carl C. Icahn(6) | 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)(7) | 103,102,764 | 69.9 | % | ||
_______________________________________
* | Less than 1% |
(1) | Based on 147,600,000 common units outstanding as of February 20, 2018. |
(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, David L. Lamp, Stephen Mongillo, Louis J. Pastor and James M. Strock. |
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(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. Mr. Lipinski retired December 31, 2017. The information reported for Mr Lipinski is based on information available to the Partnership and may not reflect his current beneficial ownership. |
(5) | Mr. Power retired December 31, 2017. The information reported for Mr. Power is based on information available to the Partnership and may not reflect his current beneficial ownership. |
(6) | 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"). |
According to the filing, the principal business address of each of (i) CVR Refining Holdings, CRLLC, CRRM, CRRM Holdings and CVR Energy is 2277 Plaza Drive, Suite 500, Sugar Land, TX 77479, (ii) IEP Energy, Energy Holding, AEP, Building, Icahn Enterprises Holdings, Icahn Enterprises GP and Beckton is White Plains Plaza, 445 Hamilton Avenue — Suite 1210, White Plains, NY 10601, and (iii) Mr. Icahn is c/o Icahn Associates Holding LLC, 767 Fifth Avenue, 47th Floor, New York, NY 10153.
According to the filing, CVR Refining Holdings has sole voting power and sole dispositive power with regard to 97,303,764 common units, and may be deemed to have shared voting power and shared dispositive power with regard to 12,000 common units owned of record by CVR Refining Holdings Sub, LLC ("CVRR Holdings Sub"). Each of CRLLC, CRRM, CRRM Holdings, CVR Energy, IEP Energy, Energy Holding, AEP, Building, Icahn Enterprises Holdings, Icahn Enterprises GP, Beckton and Mr. Icahn may be deemed to have shared voting power and shared dispositive power with regard to such common units. AEP has sole voting power and sole dispositive power with regard to 2,000,000 common units. Each of Building, Icahn Enterprises Holdings, Icahn Enterprises GP, Beckton and Mr. Icahn may be deemed to have shared voting power and shared dispositive power with regard to such common units. Icahn Enterprises Holdings has sole voting power and sole dispositive power with regard to 3,750,000 common units. Each of Icahn Enterprises GP, Beckton and Mr. Icahn may be deemed to have shared voting power and shared dispositive power with regard to such common units.
According to the filing, each of CRLLC, CRRM, CRRM Holdings and CVR Energy, by virtue of their relationships to each of CVR Refining Holdings and CVRR Holdings Sub, may be deemed to indirectly beneficially own (as that term is defined in Rule 13d-3 under the Exchange Act) the common units which each of CVR Refining Holdings and CVRR Holdings Sub directly beneficially owns. Each of CRLLC, CRRM, CRRM Holdings and CVR Energy disclaims beneficial ownership of such common units for all other purposes. Each of IEP Energy, Energy Holding, AEP, Building, Icahn Enterprises Holdings, Icahn Enterprises GP, Beckton and Mr. Icahn, by virtue of their relationships to each of CVR Refining Holdings, CVRR Holdings Sub and Icahn Enterprises Holdings, may be deemed to indirectly beneficially own (as that term is defined in Rule 13d-3 under the Exchange Act) the common units which each of CVR Refining Holdings, CVRR Holdings Sub and Icahn Enterprises Holdings directly beneficially owns. Each of IEP Energy, Energy Holding, AEP, Building, Icahn Enterprises Holdings, Icahn Enterprises GP, Beckton and Mr. Icahn disclaims beneficial ownership of such common units for all other purposes.
(7) | 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 8,000 common units owned by Ms. Ball, the 1,000 common units owned by Mr. Walter, the 11,000 common units owned by Mr. Landreth and the 4,000 common units owned by Janice T. DeVelasco, (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. The number does not include common units held by Messrs. Lipinski or Power as they were not serving directors or as executive officers of the Partnership as of the date of this filing. |
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The following table sets forth, as of February 20, 2018, the number of shares of common stock of CVR Energy beneficially owned by each of the named executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
Shares Beneficially Owned | ||||||
Name of Beneficial Owner | Number | Percent(1) | ||||
John J. Lipinski(2) | — | — | ||||
David L. Lamp | — | — | ||||
Susan M. Ball | — | — | ||||
John R. Walter | — | — | ||||
David L. Landreth | — | — | ||||
Martin J. Power(3) | — | — | ||||
Carl C. Icahn(4) | 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 20, 2018. |
(2) | Mr. Lipinski retired December 31, 2017. The information reported for Mr Lipinski is based on information available to the Partnership and may not reflect his current beneficial ownership. |
(3) | Mr. Power retired December 31, 2017. The information reported for Mr. Power is based on information available to the Partnership and may not reflect his current beneficial ownership. |
(4) | 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. |
Equity Compensation Plans
In connection with the Initial Public Offering, on January 16, 2013, the board of directors of our general partner adopted the CVR Refining LTIP. Individuals who are eligible to receive awards under the CVR Refining LTIP include employees, officers, consultants and directors of CVR Refining and the general partner and their respective subsidiaries and parents. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights, each in respect of common units. A maximum of 11,070,000 common units are issuable under the CVR Refining LTIP.
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Equity Compensation Plan Information
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, 2017, 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. |
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Item 13. Certain Relationships and Related Transactions, and Director Independence
CVR Energy indirectly owns (i) 97,315,764 common units, representing approximately 66% of our outstanding common units and (ii) our general partner with its non-economic general partner interest in us that does not entitle it to receive distributions. In addition, an affiliate of Icahn Enterprises L.P. ("IEP"), the majority stockholder of CVR Energy, owns 5,750,000 of our common units, representing approximately 3.9% of our outstanding common units.
Distributions and Payments to CVR Energy and its Affiliates
We make cash distributions to our unitholders, including CVR Refining Holdings, as the direct and indirect holder of 97,315,764 common units, and affiliates of IEP, the holder of 5,750,000 common units. For the year ended December 31, 2017, we paid $138.7 million in quarterly distributions to our unitholders. See Part II, Item 8, Note 9 ("Partners’ Capital and Partnership Distributions") of this Report for further discussion.
Agreements with CVR Energy and CVR Partners
CVR Refining and its subsidiaries are party to, or otherwise subject to certain agreements with CVR Energy and its subsidiaries (including CVR Partners and its subsidiary, Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF"), that govern the business relations among each party. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties. The agreements are described as in effect at December 31, 2017, unless otherwise noted.
Intercompany Credit Facility
In connection with the Initial Public Offering, on January 23, 2013, Refining LLC entered into a new $150.0 million intercompany credit facility with CRLLC as the lender to be used to fund growth capital expenditures, which was subsequently expanded to $250.0 million on October 29, 2014. As discussed in Part II, Item 8, Note 8 ("Long-Term Debt"), the Partnership reviewed the needs of the intercompany credit facility and decided to lower the borrowing capacity back to the original level of $150.0 million effective December 1, 2017. As of December 31, 2017, we had no borrowings outstanding under the facility. See Part II, Item 7 of this Report, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Intercompany Credit Facility."
Coke Supply Agreement
Since October 2007, through our wholly-owned subsidiary CRRM, we are party to a pet coke supply agreement with CRNF, pursuant to which we supply CRNF with pet coke. This agreement provides that CRRM must deliver to CRNF during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100% of the pet coke produced at CRRM's Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CRNF is also obligated to purchase this annual required amount. If CRRM produces more than 41,667 tons of pet coke during a calendar month, CRNF will have the option to purchase the excess at the purchase price provided for in the agreement. If CRNF declines to exercise its option, CRRM may sell the excess to a third party.
The price that CRRM receives pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received by CRNF for urea ammonium nitrate ("UAN") (the "UAN-based price") or a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN that excludes transportation cost ("netback price") of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.
CRNF will pay any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. CRNF is entitled to offset any amount payable for the pet coke against any amount CRRM owes under the feedstock and shared services agreement, which is described below. If CRNF fails to pay an invoice on time, it must pay interest on the outstanding amount payable at a rate of three percent above the prime rate.
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The terms of the pet coke supply agreement provide benefits to both parties. The cost of the pet coke CRRM supplies to CRNF in most cases will be lower than the price it otherwise would pay to third parties. The cost to CRNF will be lower both because the actual price paid will be lower and because it will pay significantly reduced transportation costs (the pet coke is supplied by our adjacent facility and therefore does not involve freight or tariff costs). In addition, because the cost CRNF pays will be formulaically related to the price received for UAN (subject to a UAN based price floor and ceiling), CRNF will enjoy lower pet coke costs during periods of lower revenues regardless of the prevailing pet coke market.
In return for CRRM receiving a potentially lower price for pet coke in periods when the pet coke price is impacted by lower UAN prices, we enjoy the following benefits associated with the disposition of a low value by-product of the refining process: avoiding the capital cost and operating expenses associated with handling pet coke; enjoying flexibility in our crude slate and operations as a result of not being required to meet a specific pet coke quality; and avoiding the administration, credit risk and marketing fees associated with selling pet coke.
The agreement has an initial term of 20 years, ending in 2027, which will be automatically extended for successive five-year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of the parties or if a party breaches the agreement and does not cure within applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of CRNF's operations at its Coffeyville nitrogen fertilizer plant or at CRRM's Coffeyville refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party's lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements.
The agreement contains an obligation for each party to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain affiliates.
Our pet coke sales price per ton sold averaged $6.14 for the year ended December 31, 2017. Our total sales to CVR Partners were approximately $2.0 million for the year ended December 31, 2017. Receivables of approximately $0.1 million related to the coke supply agreement were included in accounts receivable on the Consolidated Balance Sheets as of December 31, 2017.
Feedstock and Shared Services Agreement
CRNF is party to a feedstock and shared services agreement with CRNF, under which the two parties provide feedstock and other services to one another. The feedstocks and services are utilized in the respective production processes of our Coffeyville refinery and CRNF's Coffeyville nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas. The agreement was amended and restated effective January 1, 2017.
CRNF transfers hydrogen to CRRM pursuant to the feedstock and shared services agreement. CRNF is not required to sell hydrogen to CRRM if such hydrogen is required for operation of CRNF's fertilizer plant, if such sale would adversely affect the Nitrogen Fertilizer Partnership's classification as a partnership for federal income tax purposes, or if such sale would not be in CRNF's best interest. The feedstock agreement provides hydrogen supply and pricing terms for sales of hydrogen by CRNF. The price we pay for purchases of hydrogen from CRNF is based on ammonia prices for sales of hydrogen up to a designated amount. For purchases of hydrogen in excess of that amount, the price reverts to a UAN pricing structure to make CRNF whole, as if it had produced UAN for sale. For the year ended December 31, 2017, we recorded approximately $0.4 million in cost of materials and other for net monthly purchases of hydrogen from CRNF. The monthly hydrogen purchases are cash settled net on a monthly basis with hydrogen sales, pursuant to the hydrogen purchase and sale agreement below.
The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. Net expenses reimbursed in direct operating expenses (exclusive of depreciation and amortization) during the year ended December 31, 2017 was approximately $0.2 million related to high-pressure steam.
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CRNF is also obligated to make available to CRRM any nitrogen produced by the Linde air separation plant that is not required for the operation of CRNF's nitrogen fertilizer plant, as determined by CRNF in a commercially reasonable manner. The price for the nitrogen is based on a cost of $0.035 cents per kilowatt hour, as adjusted to reflect changes in the CRNF electric bill. There were no payments associated with nitrogen for the year ended December 31, 2017.
The agreement also provides that both parties must deliver instrument air to one another in some circumstances. CRNF must make instrument air available for purchase at a minimum flow rate, to the extent produced by its Linde air separation plant and available to CRNF. The price for such instrument air is $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in the CRNF electric bill. To the extent that instrument air is not available from the Linde air separation plant but is available from CRRM, we are required to make instrument air available to CRNF for purchase at a price of $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in our electric bill. There was no reimbursed direct operating expense or paid amounts for the year ended December 31, 2017.
CRNF is obligated to provide oxygen produced by its Linde air separation plant and made available to it to the extent that such oxygen is not required for operation of its nitrogen fertilizer plant. The oxygen is required to meet certain specifications. Approximately $0.1 million was reimbursed to CRNF for the purchase of oxygen for the year ended December 31, 2017 and was included as an increase to direct operating expenses (exclusive of depreciation and amortization).
Prior to November 1, 2017, the feedstock and shared services agreement provided a mechanism pursuant to which CRNF transferred a tail gas stream to CRRM. The net amount of direct operating expenses generated from the purchase of tail gas from CRNF were nominal for the the year ended December 31, 2017. In April 2011, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF paid CRRM the cost of installing the pipe and provided an additional 15% to cover the cost of capital, which was due from CRNF to CRRM over four years.
Effective November 1, 2017, the feedstock and shared services agreement was amended to provide a mechanism to transfer a natural gas stream from CRRM to CRNF, and CRNF will no longer transfer tail gas to CRRM. The pipe previously used for the transfer of tail gas was altered to exclusively allow for the transportation of natural gas. CRRM will nominate and purchase natural gas transportation and natural gas supplies for CRNF. CRNF will reimburse CRRM for the commodity cost of the natural gas and will pay a nominal fee for transportation and maintenance.
CRNF also occasionally provides finished product tank capacity to CRRM under the agreement. There was no reimbursed direct operating expense for the use of tank capacity for the year ended December 31, 2017.
The agreement also addresses the allocation of various other feedstocks, services and related costs between the parties. Sour water, water for use in fire emergencies, tank storage, costs associated with security services, and costs associated with the removal of excess sulfur are all allocated between the two parties by the terms of the agreement. The agreement also requires CRNF to reimburse CRRM for utility costs related to a sulfur processing agreement between us and Tessenderlo Kerley, Inc. ("Tessenderlo Kerley"). CRNF has a similar agreement with Tessenderlo Kerley. Otherwise, costs relating to both parties' existing agreements with Tessenderlo Kerley are allocated equally between us except in certain circumstances.
The parties may temporarily suspend the provision of feedstocks or services pursuant to the terms of the agreement if repairs or maintenance are necessary on applicable facilities. Additionally, the agreement imposes minimum insurance requirements on the parties and their affiliates.
At December 31, 2017 , payables of approximately $0.2 million were included in accounts payable on the Consolidated Balance Sheets associated with amounts yet to be paid related to components of the feedstock and shared services agreement, other than amounts associated with hydrogen purchases and tail gas discussed above. At December 31, 2017, receivables of approximately $1.0 million were included in prepaid expenses and other current assets on the Consolidated Balance Sheets associated with receivables related to components of the feedstock and shared services agreement.
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The agreement has an initial term of 20 years, ending in 2031, which will be automatically extended for successive five-year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at CRNF's Coffeyville nitrogen fertilizer plant or CRRM's Coffeyville refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding, or otherwise becomes insolvent. Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party's lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.
Hydrogen Purchase and Sales Agreement
CRRM and CRNF entered into a hydrogen purchase and sale agreement effective January 1, 2017, pursuant to which, CRRM agrees to sell and deliver a committed hydrogen volume of 90,000 mscf per month, and CRNF agrees to purchase and receive the committed volume. The committed volume pricing is based on a monthly fixed fee (based on the fixed and capital charges associated with producing the committed volume) and a monthly variable fee (based on the natural gas price associated with hydrogen actually received). In the event CRNF fails to take delivery of the full committed volume in a month, CRNF remains obligated to pay CRRM for a monthly fixed fee and also to pay a monthly variable fee based upon the actual hydrogen volume received, if any. In the event CRRM fails to deliver any portion of the committed volume for the applicable month for any reason other than planned repairs and maintenance, CRNF will be entitled to a pro-rata reduction of the monthly fixed fee. CRNF also has the option to purchase excess volume of up to 60,000 mscf per month, or more upon mutual agreement, from CRRM, if available for purchase.
A portion of the monthly variable fee, as defined in the terms of the agreement, is determined according to the natural gas costs incurred by CRRM in operation of the hydrogen plant, which will reflect market-driven changes in the natural gas prices. In addition, certain fixed fees will be adjusted on an annual basis according to the changes in a cost index, as defined in the terms of the agreement.
CRRM is not required to sell hydrogen to CRNF if such sale would adversely affect CVR Refining’s classification as a partnership for federal income tax purposes, and is not required to sell hydrogen to CRNF in excess of the committed volume if such volumes are needed for CRRM’s operations.
The agreement has an initial term of 20 years and will be automatically extended following the initial term for additional successive five-year renewal term unless either party gives 180 days written notice. Certain fees under the agreement are subject to modification after this initial term. The agreement contains customary terms related to indemnification, as well as termination for breach, by mutual consent, or due to insolvency or cessation of operations.
For the year ended December 31, 2017, the gross sales of hydrogen to CRNF were approximately $4.2 million. The monthly hydrogen sales are cash settled net with hydrogen purchases pursuant to the feedstock and shared services agreement. At December 31, 2017, current recoveries, net of any amounts due to CRNF under the feedstock and shared services agreement for hydrogen, of approximately $0.3 million were included in accounts receivable on the Consolidated Balance Sheets associated with net hydrogen sales to CRNF.
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Raw Water and Facilities Sharing Agreement
CRRM entered into a raw water and facilities sharing agreement with CRNF in October 2007 which (i) provides for the allocation of raw water resources between CRRM's Coffeyville refinery and CRNF's Coffeyville nitrogen fertilizer plant and (ii) provides for the management of the water intake system (consisting primarily of a water intake structure, water pumps, meters and a short run of piping between the intake structure and the origin of the separate pipes that transport the water to each facility) which draws raw water from the Verdigris River for the parties' facilities. This agreement provides that a water management team consisting of one representative from each party to the agreement will manage the Verdigris River water intake system. The water intake system is owned and operated by CRRM. The agreement provides each party has an undivided one-half interest in the water rights which will allow the water to be removed from the Verdigris River for use at CRRM's Coffeyville refinery and CRNF's nitrogen fertilizer plant.
The agreement provides that CRRM's Coffeyville refinery and CRNF's Coffeyville nitrogen fertilizer plant are entitled to receive sufficient amounts of water from the Verdigris River each day to enable them to conduct their businesses at their appropriate operational levels. However, if the amount of water available from the Verdigris River is insufficient to satisfy the operational requirements of both facilities, then such water shall be allocated between the two facilities on a prorated basis. This prorated basis will be determined by calculating the percentage of water used by each facility over the two calendar years prior to the shortage, making appropriate adjustments for any operational outages involving either of the two facilities.
Costs associated with operation of the water intake system and administration of water rights are also allocated on a prorated basis, calculated by us based on the percentage of water used by each facility during the calendar year in which such costs are incurred. However, in certain circumstances, such as where one party bears direct responsibility for the modification or repair of the water pumps, one party will bear all costs associated with such activity. Additionally, CRNF must reimburse CRRM for electricity required to operate the water pumps on a prorated basis that is calculated monthly.
Either party can terminate the agreement by giving the other party at least three years' prior written notice. Between the time that notice is given and the termination date, CRRM is required to cooperate with CRNF to allow it to build its own water intake system on the Verdigris River to be used for supplying water to CRNF's Coffeyville nitrogen fertilizer plant. CRRM is required to grant easements and access over its property so that CRNF can construct and utilize such new water intake system, provided that no such easements or access over our property shall have a material adverse effect on our business or operations at the Coffeyville refinery. CRNF will bear all costs and expenses for such construction if it is the party that terminated the original water sharing agreement. If CRRM terminates the original water sharing agreement, CRNF may either install a new water intake system at its own expense, or require CRRM to sell the existing water intake system to CRNF for a price equal to the depreciated book value of the water intake system as of the date of transfer.
Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party's lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the Coffeyville refinery or the Coffeyville nitrogen fertilizer plant, as applicable, in each case subject to applicable consent requirements. The parties may obtain injunctive relief to enforce their rights under the agreement. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.
The term of the agreement is perpetual unless (1) the agreement is terminated by either party upon three years' prior written notice in the manner described above or (2) the agreement is otherwise terminated by the mutual written consent of the parties.
Cross-Easement Agreement
CRRM and CRNF entered into a cross-easement agreement in October 2007 and an amended and restated cross-easement agreement in April 2011. The purpose of the agreement is to enable both parties to access and utilize each other's land in certain circumstances in order to operate their respective businesses. The agreement grants easements for the benefit of both parties and establishes easements for operational facilities, pipelines, equipment, access and water rights, among other easements. The intent of the agreement is to structure easements that provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party's property.
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The agreement provides that facilities located on each party's property will generally be owned and maintained by the party owning such property; provided, however, that in certain specified cases where a facility that benefits one party is located on the other party's property, the benefited party will have the right to use, and will be responsible for operating and maintaining, the subject facility.
The easements granted under the agreement are non-exclusive to the extent that future grants of easements do not interfere with easements granted under the agreement. The duration of the easements granted under the agreement will vary, and some will be perpetual. Easements pertaining to certain facilities that are required to carry out the terms of CRNF's other agreements with CRRM will terminate upon the termination of such related agreements.
The agreement contains an obligation to indemnify, defend and hold harmless the other party against liability arising from negligence or willful misconduct by the indemnifying party. The agreement also requires the parties to carry minimum amounts of employer's liability insurance, commercial general liability insurance, and other types of insurance. If either party transfers its fee simple ownership interest in the real property governed by the agreement, the new owner of the real property will be deemed to have assumed all of the obligations of the transferring party under the agreement, except that the transferring party will retain liability for all obligations under the agreement which arose prior to the date of transfer.
Terminal and Operating Lease Agreement
On May 4, 2012, CRNF entered into a lease and operating agreement with Coffeyville Resources Terminal, LLC ("CRT"), under which it leases the premises located at Phillipsburg, Kansas to be utilized as a UAN terminal. The initial term of the agreement will expire in May 2032, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days prior written notice. In addition, this agreement will automatically renew for successive five-year terms, provided that CRNF may terminate the agreement during any renewal term with at least 180 days written notice. CRNF will pay CRT $1.00 per year for rent, $4.00 per ton of UAN placed into the terminal and $4.00 per ton of UAN taken out of the terminal. For the year ended December 31, 2017, CRT recognized approximately $0.1 million of income related to the terminal and operating lease agreement.
Lease Agreement
CRNF is party to a lease agreement with CRRM in October 2007 under which CRNF leases certain office and laboratory space. The initial term of the lease was extended an additional year and will expire in October 2018, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days' prior written notice. In addition, CRNF has the option to renew the lease agreement for up to four additional one-year periods by providing CRRM with notice of renewal at least 60 days prior to the expiration of the then-existing term. For the year ended December 31, 2017, income related to CRNF's use of the office and laboratory space totaled approximately $0.1 million. There were no amounts due with respect to the lease agreement as of December 31, 2017.
Environmental Agreement
CRRM and CRNF entered into an environmental agreement in October 2007 that provides for certain indemnification and access rights in connection with environmental matters affecting CRRM's Coffeyville refinery and CRNF's Coffeyville nitrogen fertilizer plant. A supplement to the agreement was entered into in February 2008 in connection with the execution of a related comprehensive pet coke management plan and the transfer by CRRM to CRNF of certain property related to the agreement. The parties also agreed to supplement the agreement in July 2008 in order to amend and restate the comprehensive pet coke management plan.
To the extent that one party's property experiences environmental contamination due to the activities of the other party and the contamination is known at the time the agreement was entered into, the contaminating party is required to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for expenses incurred in connection with implementing such measures.
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To the extent that liability arises from environmental contamination that is caused by CRRM but is also commingled with environmental contamination caused by CRNF, CRRM may elect in our sole discretion and at our own cost and expense to perform government-mandated environmental activities relating to such liability, subject to certain conditions and provided that we will not waive any rights to indemnification or compensation otherwise provided for in the agreement. The agreement also addresses situations in which a party's responsibility to implement such government-mandated environmental activities as described above may be hindered by the property-owning party's creation of capital improvements on the property. If a contaminating party bears such responsibility but the property-owning party desires to implement a planned and approved capital improvement project on its property, the parties must meet and attempt to develop a soil management plan together. If the parties are unable to agree on a soil management plan 30 days after receiving notice, the property-owning party may proceed with its own commercially reasonable soil management plan. The contaminating party is responsible for the costs of disposing of hazardous materials pursuant to such plan.
If the property-owning party needs to do work that is not a planned and approved capital improvement project but is necessary to protect the environment, health, or the integrity of the property, other procedures will be implemented. If the contaminating party still bears responsibility to implement government-mandated environmental activities relating to the property and the property-owning party discovers contamination caused by the other party during work on the capital improvement project, the property-owning party will give the contaminating party prompt notice after discovery of the contamination and will allow the contaminating party to inspect the property. If the contaminating party accepts responsibility for the contamination, it may proceed with government-mandated environmental activities relating to the contamination and it will be responsible for the costs of disposing of hazardous materials relating to the contamination. If the contaminating party does not accept responsibility for such contamination or fails to diligently proceed with government-mandated environmental activities related to the contamination, then the contaminating party must indemnify and reimburse the property-owning party upon the property-owning party's demand for costs and expenses incurred by the property-owning party in proceeding with such government-mandated environmental activities.
Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party's lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the Coffeyville refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement has a term of at least 20 years or for so long as the feedstock and shared services agreement is in force, whichever is longer. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain of its affiliates.
If one party causes such contamination or release on the other party's property, the latter party must notify the contaminating party, and the contaminating party must take steps to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for the costs associated with doing such work.
The agreement also grants each party reasonable access to the other party's property for the purpose of carrying out obligations under the agreement. However, both parties must keep certain information relating to the environmental conditions on the properties confidential. Furthermore, both parties are prohibited from investigating soil or groundwater conditions except as required for government-mandated environmental activities, in responding to an accidental or sudden contamination of certain hazardous materials, or in connection with implementation of CRNF's comprehensive pet coke management plan.
A comprehensive pet coke management plan that was subsequently entered into pursuant to the agreement establishes procedures for the management of pet coke and the identification of significant pet coke-related contamination. Also, the parties agreed to indemnify and defend one another and each other's affiliates against liabilities arising under the pet coke management plan or relating to a failure to comply with or implement the pet coke management plan.
Services Agreement with CVR Energy
In connection with the Initial Public Offering, as of December 31, 2012, we entered into a services agreement with CVR Energy. Under this agreement, we and our general partner has engaged CVR Energy to provide us with certain services, including the following, among others:
• | 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; |
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• | 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. |
As payment for services provided under the agreement, we, our general partner, or our subsidiaries, must pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees who provide us services under the agreement on a full-time basis, but excluding certain share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees who provide us services under the agreement on a part-time basis, but excluding certain share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for us; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges.
We and our general partner are not required to pay any compensation, salaries, bonuses or benefits to any of CVR Energy's employees who provide services to us or our general partner on a full-time or part-time basis; CVR Energy continues to pay their compensation. However, personnel performing the actual day-to-day business and operations at the petroleum refinery or operating level are employed directly by us and our subsidiaries, and we or our subsidiaries bear all personnel costs for these employees.
Either CVR Energy or our general partner is allowed to temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days' notice. CVR Energy also has the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of its affiliates or any other person or entity, though such delegation does not relieve CVR Energy from its obligations under the agreement. CVR Energy or our general partner may terminate the agreement upon at least 180 days' notice, but not more than one year's notice. Furthermore, our general partner may terminate the agreement immediately if CVR Energy becomes bankrupt, or dissolves or commences liquidation or winding-up procedures.
In order to facilitate the carrying out of services under the agreement, we, on the one hand, and CVR Energy and its affiliates, on the other, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another's intellectual property under certain circumstances.
The agreement also contains an indemnity provision whereby we, our general partner, and our subsidiaries, as indemnifying parties, agree to indemnify CVR Energy and its affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by CVR Energy or other misconduct on its part, as provided in the agreement. The agreement contains a provision stating that CVR Energy is an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by CVR Energy, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from CVR Energy or certain affiliates, except in cases of gross negligence, willful misconduct, bad faith, reckless disregard in performance of services under the agreement, or fraudulent or dishonest acts.
Net amounts incurred under the services agreement for the year ended December 31, 2017 were approximately $61.8 million and were included in direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization). At December 31, 2017, payables and liabilities of $14.0 million were included in accounts payable, personnel accruals and accrued expenses and other current liabilities on the Consolidated Balance Sheets with respect to amounts billed in accordance with the services agreement.
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Trademark License Agreement
We are party to a Trademark License Agreement with CVR Energy pursuant to which CVR Energy has granted us a non-exclusive, non-transferrable license to use the Coffeyville Resources and CVR Refining trademarks in connection with our business. We agree to use the marks only in the form and manner and with appropriate legends as prescribed from time to time by CVR Energy, and agree that the nature and quality of the business that uses the marks will conform to standards currently applied by CVR Energy. Either party may terminate the license with 60 days' prior notice.
Registration Rights Agreement
In connection with the Initial Public Offering, on January 23, 2013, we entered into a registration rights agreement with affiliates of IEP, CVR Refining Holdings, and CVR Refining Holdings Sub, LLC, a wholly-owned subsidiary of CVR Refining Holdings, pursuant to which we may be required to register the sale of the common units they hold. Under the registration rights agreement, affiliates of IEP, CVR Refining Holdings and CVR Refining Holdings Sub, LLC have the right to request that we register the sale of common units held by them on their behalf on six occasions, including requiring us to make available shelf registration statements permitting sales of common units into the market from time to time over an extended period, and may require us to undertake a public or private offering and use the proceeds (net of underwriting or placement agency discounts, fees and commissions, as applicable) to redeem an equal number of common units from them. In addition, affiliates of IEP, CVR Refining Holdings and CVR Refining Holdings Sub, LLC and their permitted transferees have the ability to exercise certain piggyback registration rights with respect to their securities if we elect to register any of our equity interests. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of our common units held by affiliates of IEP, CVR Refining Holdings and CVR Refining Holdings Sub, LLC and any permitted transferee are entitled to these registration rights.
Agreements with Affiliates of IEP
Insight Portfolio Group
Insight Portfolio Group LLC ("Insight Portfolio Group") is an entity formed by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013, CVR Energy acquired a minority equity interest in Insight Portfolio Group. We participate in Insight Portfolio Group's buying group through our relationship with CVR Energy. We may purchase a variety of goods and services as members of the buying group at prices and on terms that we believe would be more favorable than those which would be achieved on a stand-alone basis.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its owners (including CRLLC and CVR Energy), on the one hand, and us and our public unitholders, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage us in a manner that it believes is not adverse to our interest. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.
Whenever a conflict arises between our general partner and its owners, on the one hand, and us and our public unitholders, on the other, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by us and all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is: approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; or approved by the holders of a majority of the outstanding units, excluding any units owned by our general partner or any of its affiliates.
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Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of the board of our general partner or from the holders of a majority of the outstanding units as described above. If our general partner does not seek approval from the conflicts committee or from holders of units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption and proving that such decision was not in good faith. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be "in good faith" unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interest of the partnership. See Part III, Item 10 of this report, "Directors, Executive Officers and Corporate Governance — Management of CVR Refining, LP" for information about the conflicts committee of our general partner's board of directors.
Related Party Transaction Policy
The board of directors of our general partner has adopted a Related Party Transaction Policy, which is designed to monitor and ensure the proper review, approval, ratification and disclosure of related party transactions involving us. This policy applies to any transaction, arrangement or relationship (or any series of similar or related transactions, arrangements or relationships) in which we are a participant and the amount involved exceeds $120,000 and in which any related party had or will have a direct or indirect material interest. At the discretion of the board, a proposed related party transaction may generally be reviewed by the board in its entirety or by a "conflicts committee" meeting the definitional requirements for such a committee under our partnership agreement. After appropriate review, the board or the conflicts committee may approve or ratify a related party transaction if such transaction is consistent with the Related Party Transaction Policy and is on terms that, taken as a whole, are no less favorable to us than could be obtained in an arm's-length transaction with an unrelated third party, unless the board or the conflicts committee otherwise determines that the transaction is not in our best interests. Related party transactions involving compensation will be approved by the board in its entirety or by the compensation committee of the board in lieu of the conflicts committee.
Director Independence
The NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner. The board of directors of our general partner currently consists of nine directors, three of whom the board has affirmatively determined are independent in accordance with the rules of the NYSE.
For discussion of the independence of the board of directors of our general partner, please see Part III, Item 10 of this report, "Directors, Executive Officers and Corporate Governance — Management of CVR Refining, LP."
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Item 14. Principal Accounting Fees and Services
Grant Thornton LLP ("Grant Thornton") has served as the Partnership's independent public registered accounting firm since August of 2013. The audit committee has not selected the independent registered public accounting firm for the fiscal year ending December 31, 2018.
The charter of the audit committee of the board of directors of our general partner, which is available on our website at www.cvrrefining.com, requires the audit committee to pre-approve all audit services and non-audit services (other than de minimis non-audit services as defined by the Sarbanes-Oxley Act of 2002) to be provided by our independent registered public accounting firm. The audit committee has adopted a pre-approval policy with respect to services that may be performed by the independent auditors. The Partnership's audit committee pre-approved all fees incurred in fiscal year 2017.
The following table presents fees billed for professional services and other services in the following categories and amounts by Grant Thornton for the fiscal years ended December 31, 2017 and 2016:
Fiscal | Fiscal | ||||||
Year 2017 | Year 2016 | ||||||
Audit fees(1) | $ | 1,003,400 | $ | 1,289,100 | |||
Audit-related fees(2) | 12,400 | 15,000 | |||||
Tax fees | — | — | |||||
All other fees | — | — | |||||
Total | $ | 1,015,800 | $ | 1,304,100 | |||
(1) | Represents the aggregate fees for professional services rendered for the audit of the Partnership's financial statements for fiscal years ended December 31, 2017 and 2016, the audit of the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2017 and 2016 and consultations on financial accounting and reporting matters arising during the course of the audit for fiscal years 2017 and 2016. 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. |
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
See "Index to Consolidated Financial Statements" Contained in Part II, Item 8 of this Report.
(a)(2) Financial Statement Schedules
All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission (the "SEC") are not required under the related instructions or are inapplicable and therefore have been omitted.
(a)(3) Exhibits
Exhibit Number | Exhibit Title |
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156
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101* | The following financial information for CVR Refining LP's Annual Report on Form 10-K for the year ended December 31, 2017, 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. | |
PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporate by reference agreements as exhibits to the reports which we file with or furnish to the SEC. The agreements are filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Partnership or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Partnership's public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Partnership or its business or operations on the date hereof.
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Item 16. Form 10-K Summary
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
CVR Refining, LP | ||
By: | CVR Refining GP, LLC, its general partner | |
By: | /s/ DAVID L. LAMP | |
Name: David L. Lamp Title: President and Chief Executive Officer | ||
Date: February 23, 2018
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report had been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated.
Signature | Title | Date |
/s/ DAVID L. LAMP | President and Chief Executive Officer and Director (Principal Executive Officer) | February 23, 2018 |
David L. Lamp | ||
/s/ SUSAN M. BALL | Executive Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) | February 23, 2018 |
Susan M. Ball | ||
Director | February 23, 2018 | |
Carl C. Icahn | ||
/s/ SUNGHWAN CHO | Director | February 23, 2018 |
SungHwan Cho | ||
/s/ JONATHAN FRATES | Director | February 23, 2018 |
Jonathan Frates | ||
/s/ ANDREW LANGHAM | Director | February 23, 2018 |
Andrew Langham | ||
/s/ LOUIS J. PASTOR | Director | February 23, 2018 |
Louis J. Pastor | ||
/s/ KENNETH SHEA | Director | February 23, 2018 |
Kenneth Shea | ||
/s/ JON R. WHITNEY | Director | February 23, 2018 |
Jon R. Whitney | ||
/s/ GLENN R. ZANDER | Director | February 23, 2018 |
Glenn R. Zander | ||
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