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, 2014 | |
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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o |
(Do not check if a smaller reporting company) | |||
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, 2014 (the last business day of the registrant’s second fiscal quarter) was $1,075,610,972. 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, 2014 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 17, 2015 |
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, 2014 (this "Report").
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.
backwardation market — Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. The opposite of contango market.
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 365 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.
contango market — Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation market.
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.
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.
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.
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.
general partner — CVR Refining GP, LLC, our general partner, which is an indirect wholly-owned subsidiary of CVR Energy.
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 NCRA's refinery in McPherson, KS.
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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.
Initial Public Offering — The initial public offering of 27,600,000 common units representing limited partner interests ("common units") of CVR Refining, LP, which closed on January 23, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional common units).
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.
Magellan — Magellan Midstream Partners L.P., a publicly traded company whose business is the transportation, storage and distribution of refined petroleum products.
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.
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.
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
Second Underwritten Offering — The second underwritten offering of 7,475,000 common units of CVR Refining, LP, which closed on June 30, 2014 (which includes the underwriters' subsequently-exercised option to purchase additional common units).
sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
spot market — A market in which commodities are bought and sold for cash and delivered immediately.
sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
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.
Underwritten Offering —The underwritten offering of 13,209,236 common units of CVR Refining, LP, which closed
on May 20, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional common units).
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.
WEC — Gary-Williams Energy Corporation, subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood Energy Company, LLC.
WRC — Wynnewood Refining Company, LLC, the owner of the Wynnewood, Oklahoma refinery and related assets with a rated capacity of 70,000 bpcd.
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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.
Wynnewood Acquisition — The acquisition by CVR Energy of all the outstanding shares of WEC and its subsidiaries, which owned the Wynnewood, Oklahoma refinery with a rated capacity of 70,000 bpcd and 2.0 million barrels of storage tanks, on December 15, 2011. As of January 2013, WRC became a wholly-owned subsidiary of CVR Refining, LLC. It was previously a wholly-owned subsidiary of WEC.
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 the underserved 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 oils (within its rated capacity of 70,000 bpcd). The combined crude capacity represents approximately 22% of the region's refining capacity. In addition, we also control and operate supporting logistics assets including approximately 336 miles of owned and leased pipelines, approximately 150 owned crude oil transports, a network of strategically located crude oil gathering tank farms, over 6.0 million barrels of owned and leased crude oil storage capacity and approximately 4.5 million barrels of combined refinery related 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, 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, 2014, the crude oil consumed at the refineries was price advantaged to WTI.
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 has increased to 13.3 and our Wynnewood refinery's complexity is now 12.6. We have incurred total costs of approximately $44.0 million, excluding capitalized interest, on a hydrocracker project, which was completed in the fourth quarter 2014. The hydrocracker project will increase the conversion capability and the ultra-low sulfur diesel ("ULSD") yield of the Wynnewood refinery. 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, 2014, our Coffeyville refinery's product yield included gasoline (49%), diesel fuel (primarily ultra-low sulfur diesel) (43%), 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 (49%), diesel fuel (primarily ultra-low sulfur diesel) (36%), asphalt (7%), jet fuel (4%) and other products (4%) (slurry, sulfur and gas oil, and specialty products such as propylene and solvents).
Our logistics businesses have grown substantially since 2005. We have grown our crude oil gathering system capacity from 7,000 bpd in 2005 to approximately 60,000 bpd currently. The gathering system allows us to gather crude oil that is purchased from independent crude oil producers in Kansas, Nebraska, Oklahoma, Missouri and Texas. During 2014, we gathered approximately 59,000 bpd of price-advantaged crudes from our gathering area. The system has field offices in Bartlesville and Pauls Valley, Oklahoma and Plainville, Winfield and Iola, Kansas. 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 and Bakken crudes to our refineries. By the third quarter of 2015, our contracted capacity will expand by approximately 6,700 bpd through new capacity on the Pony Express and White Cliffs pipelines, which will provide us with additional supplies of Bakken and Niobrara crudes to our refineries.
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 1.4 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
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Wynnewood refinery and (iv) approximately 1.0 million barrels of crude oil storage capacity in Cushing, Oklahoma. We also lease additional crude oil storage capacity of approximately 2.8 million barrels in Cushing and approximately 0.1 million barrels at our Wynnewood refinery. The Cushing storage supports both our Wynnewood and Coffeyville refineries.
For the fiscal years ended December 31, 2014, 2013 and 2012, we generated net sales of $8.8 billion, $8.7 billion and $8.3 billion, respectively, and operating income of $207.2 million, $603.0 million and $993.9 million, respectively.
Our History
Our Coffeyville refining business was operated as a small component of Farmland Industries, Inc. ("Farmland") until March 3, 2004, the date on which Coffeyville Resources, LLC ("CRLLC") completed the acquisition of these assets and the adjacent nitrogen fertilizer plant now operated by CVR Partners, LP ("CVR Partners") through a bankruptcy court auction.
On June 24, 2005, our Coffeyville refinery and related businesses (as well as the adjacent nitrogen fertilizer plant now operated by CVR Partners), were acquired by Coffeyville Acquisition LLC ("CALLC").
On October 26, 2007, CVR Energy completed its initial public offering and its common stock was listed on the NYSE under the symbol "CVI." CVR Energy was formed as a wholly-owned subsidiary of CALLC in September 2006 in order to complete the initial public offering of the businesses acquired by CALLC. At the time of its initial public offering, CVR Energy operated our business and indirectly owned all of the limited partner interests in CVR Partners. In April 2011, CVR Partners completed its initial public offering. CVR Partners' common units were listed on the NYSE under the symbol "UAN." As of December 31, 2014, CVR Energy indirectly owns the general partner and approximately 53% of the common units of CVR Partners.
On December 15, 2011, CRLLC acquired all of the issued and outstanding shares of WEC. The assets acquired included a 70,000 bpcd rated capacity refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of storage tanks.
In May 2012, an affiliate of Icahn Enterprises L.P. ("IEP") acquired a majority of CVR Energy's common stock. As of December 31, 2014, IEP and its affiliates owned approximately 82% of CVR Energy's outstanding common stock.
We were formed by CVR Energy in September 2012 in order to own and operate petroleum and auxiliary businesses as a limited partnership. In preparation of the Initial Public Offering, CRLLC contributed its wholly-owned subsidiaries and logistics assets to CVR Refining, LLC ("Refining LLC") in October 2012, and CVR Refining Holdings, LLC ("CVR Refining Holdings"), a subsidiary of CRLLC and an indirect wholly-owned subsidiary of CVR Energy, contributed Refining LLC to us on December 31, 2012.
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 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." In connection with the Initial Public Offering, we paid approximately $32.5 million in underwriting fees and incurred approximately $3.9 million of other offering costs.
We have two types of partnership interests outstanding:
• | common units representing limited partner interests, a portion of which we sold in the Initial Public Offering and which are listed on the NYSE; and |
• | a general partner interest, which is not entitled to any distributions, and which is held by our general partner. |
Subsequent to 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 (this includes common units held by an affiliate of IEP, representing approximately 3% of all outstanding limited partner interests) and CVR Refining Holdings held common units approximating 81% of all outstanding limited partner interests.
On May 20, 2013, we completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a
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CVR Energy subsidiary, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, we sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the “Transactions.” In connection with the Transactions, we paid approximately $12.2 million in underwriting fees and approximately $0.4 million in offering costs.
We utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings. We did not receive any of the proceeds from the sale of common units by a CVR Energy subsidiary to AEPC.
Following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of all outstanding limited partner interests (including common units held by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximating 71% of all outstanding limited partner interests.
On June 30, 2014, we completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. We paid approximately $5.3 million in underwriting fees and approximately $0.5 million in offering costs. We utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings. Subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.
On July 24, 2014, we sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their option to purchase additional common units. We utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.
Subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2014, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% 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, LLC, which holds a non-economic general partner interest.
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Organizational Structure and Related Ownership
The following chart illustrates our organizational structure and the organizational structure of the Partnership 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 and various Canadian medium and heavy sours, and it has recently introduced North Dakota Bakken and other similarly sourced crudes into its crude slate. 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 pipeline. We have continued to increase the number of barrels of crude oil supplied through our crude oil gathering system in 2014 and it now has the capacity of supplying approximately 60,000 bpd of crude oil to our refineries. For the year ended December 31, 2014, the gathering system supplied approximately 37% of the Coffeyville refinery's crude oil demand and approximately 21% of the Wynnewood refinery's 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, Oklahoma by various pipelines, including the Keystone and Spearhead pipelines, and subsequently to our Broome Station facility via the Plains pipeline. By the third quarter of 2015, our contracted capacity is expected to grow to include the Pony Express and White Cliffs pipelines. 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 by three separate pipelines, and received into storage tanks at terminals located at or near the refinery.
For the year ended December 31, 2014, our Coffeyville refinery's crude oil supply blend was comprised of approximately 86% light sweet crude oil, 13% heavy sour crude oil and 1% light/medium sour crude oil. For the year ended December 31, 2014, our Wynnewood refinery's crude oil supply blend was comprised of approximately 99% sweet crude oil and approximately 1% light/medium sour 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 ("LPG") fractionation and storage capabilities as well as the commercial markets available at Conway.
Crude Oil Supply Agreement
In August 2012, we entered into a Crude Oil Supply Agreement (the "Vitol Agreement") with Vitol Inc. ("Vitol"). Under the Vitol Agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement had an initial term commencing August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, 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 the Initial Term or any Renewal Term. The Vitol Agreement was extended for a one-year Renewal Term through December 31, 2015.
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, 2014, our Coffeyville refinery processed approximately 119,700 bpd and 9,000 bpd of crude oil and feedstocks and blendstocks,
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respectively. These throughput rates for 2014 reflect the effect of the shutdown in the third quarter of 2014 as a result of the isomerization unit fire. Our Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil into products such as gasoline, diesel, kerosene, propane, butane, sulfur, heavy oil and petroleum coke.
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. 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) into products such as gasoline, jet fuel, kerosene, propane, butane, propylene, sulfur, solvents, heavy oil and asphalt. During the year ended December 31, 2014, our Wynnewood refinery processed approximately 76,800 bpd and 2,200 bpd of crude oil and feedstocks and blendstocks, respectively. These throughput rates for 2014 reflect the effect of the 16-day fluid catalytic cracking unit ("FCCU") outage in the fourth quarter 2014.
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 directly to customers located in close geographic proximity to the refinery and to customers at throughput terminals on the refined products distribution systems of Magellan and NuStar. Coffeyville also makes bulk sales (sales into third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. The outbound Enterprise Pipeline Red Line provides Coffeyville with access to the NuStar Refined Products Pipeline system. This allows gasoline and ULSD product sales from Kansas up into North Dakota.
The Wynnewood refinery ships its finished product via pipeline, railcar, and truck. It focuses its efforts in the southern portion of the Magellan system which covers all of Oklahoma, parts of Arkansas as well as eastern Missouri, and all other Magellan terminals. The pipeline system is also able to flow in the opposite direction, providing access to Texas markets as well as some adjoining states with pipeline connections. Wynnewood also sells jet fuel to the U.S. Department of Defense via its segregated truck rack and can offer asphalts, solvents and other specialty products via both truck and rail.
Customers
Customers for our refined 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 a by-product of its refining operations, petroleum coke, to an affiliate, CVR Partners, pursuant to a multi-year agreement. For the year ended December 31, 2014, our two largest customers accounted for approximately 13% and 9% of our net sales while approximately 48% of our net sales were made to our ten largest customers.
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, NCRA, Valero 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; |
• | requirements for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and liability for off-site waste disposal locations; and |
• | 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. The ultimate impact on our business of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.
The principal environmental risks associated with our businesses are outlined below.
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 amounts to comply and/or permit our facilities to produce products that meet applicable requirements.
The regulation of air emissions under the federal Clean Air Act requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at 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
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Source Performance Standards ("NSPS") and New Source Review/Prevention of Significant Deterioration ("NSR"). We have incurred, and expect to continue to have to make substantial capital expenditures to attain or maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future.
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 will be material.
On August 14, 2012, the EPA sent both the Wynnewood and Coffeyville refineries letters regarding the EPA's 2012 enforcement alert entitled EPA Enforcement Targets Flaring Efficiency Violations signaling the agency's intention to begin a national enforcement program to conduct compliance evaluations and take enforcement actions against petroleum refining companies that operate flares that are not in compliance with standards articulated in the Enforcement Alert. The Enforcement Alert identified new standards that refiners are required to meet for flaring combustion efficiency. The EPA has already commenced enforcement against several refining companies and we understand that other settlement negotiations are underway. Because the EPA has not specifically told us that our operations are not in compliance, we cannot say with certainty whether or when we may become an enforcement target under this initiative.
In March 2004, Coffeyville Resources Refining & Marketing, LLC ("CRRM") and Coffeyville Resources Terminal, LLC ("CRT"), two of our subsidiaries, 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 install controls to reduce emissions of SO2, nitrogen oxides and particulate matter from its 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, which replaces the 2004 Consent Decree, as amended (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under the Resource Conservation and Recovery Act ("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 gives 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 NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees requiring the payment of civil penalties and the installation of air pollution control equipment and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into "global settlements" pertaining to all "marquee" issues. Under the Second Consent Decree, CRRM was required to pay a civil penalty of approximately $0.7 million and is required to 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. The remaining costs of complying with the Second Consent Decree are expected to be approximately $44.0 million. Additional incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a several year timeframe.
Wynnewood Refining Company, LLC ("WRC") entered into a Consent Order with the Oklahoma Department of Environmental Quality ("ODEQ") in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses certain historic Clean Air Act compliance issues related to the operations of the refinery by the prior owner. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be $3.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.
From time to time, ODEQ conducts air inspections of the Wynnewood refinery and pursues enforcement related to any alleged non-compliance with the Clean Air Act seeking civil penalties and injunctive relief, which may necessitate the installation of controls. In January 2014, ODEQ issued a full compliance evaluation ("FCE") report covering the period from December 2010 to June 2013, which covered periods of the previous owner's ownership and operation and, in some cases,
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continued into CVR Refining's ownership of the Wynnewood refinery. In addition, on April 11, 2014, WRC received a partial compliance evaluation ("PCE") report from ODEQ alleging violations of the Clean Air Act. ODEQ conducted a follow-up inspection on June 30, 2014. WRC has responded to both the FCE and PCE. The costs of any enforcement that may arise as a result of the FCE or PCE cannot be predicted at this time. However, based on its experience related to Clean Air Act enforcement and control requirements, CVR Refining does not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material.
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 ("OPA") (in addition to other matters described below, (see " — Environmental Remediation"). DOJ's CWA and OPA claims related to a flood and oil spill at the refinery that occurred on June 30/July 1, 2007. CRRM reached an agreement with the DOJ to resolve its claims under the CWA and the 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, the majority of which have already been completed.
The parties also reached an agreement to settle DOJ's claims related to alleged non-compliance with RMP. The agreement was memorialized in a separate consent decree that was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively (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. In 2014, CRRM completed several audits required by the RMP Consent Decree, which were related to compliance with RMP requirements.
Our Coffeyville refinery's Clean Air Act Title V operating permit has expired, and has not yet been re-issued. Our Coffeyville refinery submitted an application for renewal and currently operates under a permit shield, which authorizes permittees who timely submit their renewal application, to continue operations until the permit is re-issued. The permit renewal process has begun, and capital costs or expenses, if any, related to changes to these permits are not known yet, but are not expected to be material.
The Federal Clean Water Act
The federal Clean Water Act 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 federal Clean Water Act's permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load ("TMDL") 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 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 additional water during low-flow conditions, but these conditions could change over time if water becomes scarce.
The Wynnewood refinery's CWA permit ("OPDES permit") has expired. The refinery currently operates under a permit shield, which authorizes permittees who timely submit their renewal application to continue discharging under an expired permit until the permitting authority re-issues the permit. Capital costs or expenses related to changes to this permit, if any, are not expected to be material.
WRC has entered into a series of CWA consent orders with ODEQ. The latest consent order (the "CWA Consent Order"), which superseded other consent orders, became effective in September 2011. The CWA Consent Order addressed alleged non-compliance by WRC with its OPDES permit limits. The CWA Consent Order required WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery's wastewater treatment plant capacity is sufficient. WRC completed its obligations under the CWA Consent Order, and ODEQ notified WRC that the CWA Consent Order is closed.
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 substances and extremely hazardous substances. Our refineries periodically have excess emission events from flaring and other
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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 must be in compliance with the more stringent emission standards by January 1, 2017; however, compliance with the rule is extended until January 1, 2020 for approved small volume refineries and small refiners. The Wynnewood refinery has submitted an application to EPA requesting "small volume refinery" status. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.
Mobile Source Air Toxic II Emissions. In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires the reduction of benzene in gasoline by 2011. The MSAT II projects for CRRM and WRC were completed within the compliance deadline of November 1, 2014. The projects were completed at a total cost of approximately $47.6 million and $88.3 million, excluding capitalized interest, by CRRM and WRC, respectively.
Renewable Fuel Standards. In 2007, the EPA promulgated 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 renewable identification numbers ("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. motor fuel market, there may be a decrease in demand for petroleum products. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 of the prior year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinery was subject to the RFS for the first time. However, because the cost of purchasing RINs had been extremely volatile and had significantly increased, the Wynnewood refinery petitioned the EPA as a "small refinery" for hardship relief from the RFS requirements in 2013 based on the "disproportionate economic hardship" of the rule on the Wynnewood refinery. The EPA denied the petition in a letter dated September 5, 2014.
During 2013 the cost of RINs was extremely volatile as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 proposed percentage standards were published; however, RIN prices remained volatile and increased subsequently in 2014. In May 2014, the EPA lowered the 2013 cellulosic biofuel standard to 0.0005%, and, in June 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to September 30, 2014. In August 2014, the EPA further extended the compliance demonstration deadline for the 2013 RFS to 30 days following publication of the final 2014 annual renewable fuel percentage standards. In November 2014, the EPA announced it would not finalize the 2014 annual renewable fuel percentage standards before the end of 2014, thereby extending the compliance deadline for the 2013 RFS as well.
The future cost of RINs for the business going forward is difficult to estimate, particularly until such time that the 2014 renewable fuel percentage standards are finalized and the 2015 renewable fuel percentage standards are announced. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, 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, all of which can vary significantly from quarter to quarter.
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Greenhouse Gas Emissions
Various regulatory and legislative measures to address greenhouse gas ("GHG") emissions (including carbon dioxide ("CO2"), methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 "endangerment finding" that GHG emissions pose a threat to public health and welfare, the EPA has begun to regulate GHG emissions under the authority granted to it under the federal 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 NSR and Title V programs of the federal Clean Air Act. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing major source undergoes a major modification, the facilities are required to undergo NSR review and to evaluate and install air pollution controls to reduce GHG emissions. A major modification resulting in a significant increase in GHG emissions at the refineries may require the installation of air pollution controls as part of the permitting process.
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. Although the EPA has proposed standards for electric utilities, it has not yet proposed NSPS standards to regulate GHG emissions from petroleum refineries. 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 proposed sector risk rule would place additional emission control requirements on storage tanks, flares, and coking units at petroleum refineries. Therefore, we expect that the EPA will not be issuing NSPS standards to regulate GHG from the refineries at this time but that it may do so in the future.
During a State of the Union address in January 2014 and again in January 2015, President Obama indicated that the United States should take action to address climate change. 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 CO2 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 implementing the trading scheme before it becomes effective, and it is unclear whether Kansas intends to do so.
Alternatively, the EPA may take further steps to regulate GHG emissions. 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.
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.
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
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findings and would be pursuing enforcement. WRC and ODEQ currently are engaged in settlement discussions related to a civil penalty and injunctive relief. The costs of any related enforcement action cannot be predicted at this time. However, based on our experiences related to RCRA enforcement, we do not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material.
Waste Management. There are two closed hazardous waste units at the Coffeyville refinery and eight other hazardous waste 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. The 2004 Consent Decree that CRRM signed with the EPA and KDHE 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 require investigation or remediation projects. 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. Remediation at both sites, if necessary, will be based on the results of the investigations. 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, ODEQ has required further investigations of groundwater conditions. Remediation, if necessary, will be based upon the results of further investigation.
The anticipated investigation and remediation costs through 2018 were estimated, as of December 31, 2014, to be as follows:
Facility | Site Investigation Costs | Capital Costs | Total Operation & Maintenance Costs Through 2018 | Total Estimated Costs Through 2018 | |||||||||||
(in millions) | |||||||||||||||
Coffeyville Refinery | $ | 0.6 | $ | — | $ | 0.7 | $ | 1.3 | |||||||
Phillipsburg Terminal | 0.6 | — | 1.3 | 1.9 | |||||||||||
Wynnewood Refinery | 0.2 | — | 1.1 | 1.3 | |||||||||||
Total Estimated Costs | $ | 1.4 | $ | — | $ | 3.1 | $ | 4.5 | |||||||
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 2015, we will spend approximately $6.3 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 $1.3 million in 2014 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 $4.5 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of $0.2 million for estimated costs to close regulated hazardous waste management units at the Coffeyville refinery. Additional self-funded financial assurance of approximately $4.8 million and $2.4 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 $4.5 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 $0.3 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.
Environmental Remediation
Under the CERCLA, 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
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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, the 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.
In connection with the discharge of crude oil on July 1, 2007, CRRM reached an agreement with the DOJ to resolve its claims under the CWA and the OPA. The agreement is memorialized in the 2013 Consent Decree. See " — The Federal Clean Air Act" above.
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. We cannot assure you 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.
Environmental Insurance
We are covered by CVR Energy's site pollution legal liability insurance policy with an aggregate limit of $50.0 million per pollution condition, subject to a self-insured retention of $1.0 million. The policy includes business interruption coverage, subject to a 5-day waiting period deductible. This insurance expires on March 1, 2015 and is expected to be renewed without any material changes in terms. The policy insures any location owned, leased, rented or operated by CVR Refining, including the Coffeyville refinery and the Wynnewood refinery. 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 maintained by CVR Energy having an aggregate and occurrence limit of $150.0 million, subject to a self-insured retention of $2.0 million. This insurance provides coverage due to named perils for claims involving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. The casualty insurance policies, including umbrella and excess policies, expire on March 1, 2015 and are expected to be renewed or replaced by insurance policies containing equivalent sudden and accidental pollution coverage with no reduction in limits.
The site pollution legal liability policy and the pollution coverage provided in the casualty insurance policies contains 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.
The Wynnewood refinery has been the subject of a number of OSHA inspections since 2006. As a result of these inspections, the Wynnewood refinery entered into four OSHA settlement agreements in 2008, pursuant to which it has agreed to undertake certain studies, conduct abatement activities, and revise and enhance certain OSHA compliance programs. The remaining costs associated with implementing these studies, abatement activities and program revisions are not expected to exceed $1.0 million.
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.
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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 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 and combined financial statements. On September 25, 2013, WRC agreed to pay a small civil penalty to settle, rather than defend claims alleged by the EPA under the Clean Air Act's general duty clause related to the boiler incident. In addition to the above, the spouses of the two employees fatally injured have filed a civil lawsuit against WRC, CVR Refining and CVR Energy in Fort Bend County, Texas. The civil suit is in discovery, and the companies will vigorously defend the suit. It is currently too early to assess a potential outcome in the matter.
Process Safety Management. We maintain a process safety management ("PSM") program. This program is designed to address all aspects of the OSHA guidelines for developing and maintaining a comprehensive PSM program. We will continue to audit our programs and consider improvements in our management systems and equipment.
Emergency Planning and Response. We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in our facilities. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.
Employees
As of December 31, 2014, we employed 982 people. 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, 2014, the Coffeyville refinery employed 662 of our employees, about 51% of whom were covered by a collective bargaining agreement. These employees are affiliated with five unions of the Metal Trades Council of the AFL-CIO ("Metal Trade Unions") and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC ("United Steelworkers"). We are a party to a collective bargaining agreement with the Metal Trade Unions covering union members who work directly at the Coffeyville refinery. The agreement expires in March 2019. In addition, a collective bargaining agreement with the United Steelworkers, which covers CVR Refining's unionized employees who work in crude transportation and related operations, expires in March 2017 and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date.
As of December 31, 2014, the Wynnewood refinery employed 320 people, about 59% of whom were represented by the International Union of Operating Engineers. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2017.
We also rely on the services of employees of CVR Energy in the operation of our business pursuant to a services agreement among us, CVR Energy and our general partner. For more information on this services agreement, see Part III, Item 13 of this report "Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy and CVR Partners — Services Agreement with CVR Energy."
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, are available free of charge through our website under "Investor Relations," as soon as reasonably practicable after the electronic filing of these reports is made with the Securities and Exchange Commission (the "SEC"). In addition, our Corporate Governance Guidelines, Codes of Ethics 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. Our SEC filings, including exhibits filed therewith, are also available at the SEC's website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC's public reference room at 100 F Street, NE, Room 1580, Washington, DC 20549. You may obtain information on the operation of the SEC's public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, DC 20549.
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Trademarks, Trade Names and Service Marks
This Report may include our and our affiliates' trademarks, including the CVR Energy logo, Coffeyville Resources, the Coffeyville Resources logo, the CVR Partners, LP logo and the CVR Refining, LP logo, each of which is registered or for which we are applying for federal registration with the United States Patent and Trademark Office. This Report may also contain trademarks, service marks, copyrights and trade names of other companies.
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 future 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 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 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. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined products, there is normally a time lag in the realization of the similar increase or decrease in prices for refined products. 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 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. Declines 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.
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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.
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. Additionally, in late 2014, market factors resulted in a rapid downward price adjustment in the oil and gas industry. The resultant spike in volatility continuing in 2015 has caused major adjustments in oil debt markets as well as announced and expected cuts in 2015 budgets in both North American shale and Canadian projects. The refining industry is directly impacted by these events and has seen a downward movement in refining margins as a result. A significant and/or prolonged deterioration in market conditions would have a material adverse effect on our results of operations and ability to pay distributions to our unitholders.
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 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 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 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 unitholders.
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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; |
• | 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 plants, 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. These events were as follows:
• | June 2007: Coffeyville refinery; flood |
• | December 2010: Coffeyville refinery; FCCU fire |
• | December 2010: Wynnewood refinery; hydrocracker unit fire |
• | September 2012: Wynnewood refinery; boiler explosion |
• | July/August 2013: Coffeyville refinery; FCCU outage |
• | July 2014: Coffeyville refinery; isomerization unit fire |
Currently, we are insured under CVR Energy's casualty, environmental, property and business interruption insurance policies. The property and business interruption coverage has a combined policy limit of $1.0 billion. The property and business interruption insurance policies contain limits and sub-limits which insure all our assets as well as CVR Partners' assets. There is potential for a common occurrence to impact both the nitrogen fertilizer plant operated by CVR Partners and the Coffeyville refinery in which case the insurance limitations would apply to all damages combined. Under this insurance program, there is a $10.0 million property damage retention for all properties. For business interruption losses, the insurance program has a 45-day waiting period retention for any one occurrence. In addition, the insurance policies contain a schedule of sub-limits which apply to certain specific perils or areas of coverage. Sub-limits which may be of importance depending on the nature and extent of a particular insured occurrence are: flood, earthquake, contingent business interruption insuring key suppliers, pipelines and customers, debris removal, decontamination, demolition and increased cost of construction due to law and ordinance, and others. Such conditions, limits and sub-limits 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 due to 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
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us and the 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, 2015, 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 would be negatively impacted due to increased inventory and the negative impact of market volatility. There is no assurance that we will be able to renew or extend the Vitol Agreement beyond December 31, 2015.
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, Oklahoma, Missouri, Nebraska and Texas, we also purchased additional crude oil to be refined into liquid fuels in 2014. In 2014, our Coffeyville refinery purchased approximately 75,000 to 80,000 bpd of crude oil while our Wynnewood refinery purchased approximately 55,000 to 60,000 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. Our Coffeyville refinery obtained a portion of its non-gathered crude oil, approximately 22% in 2014, from foreign sources, and our Wynnewood refinery obtained approximately 1% of its non-gathered crude oil from foreign sources as well. The majority of these foreign sourced crude oil barrels were derived from Canada. The actual amount of foreign 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 foreign suppliers. Disruption of production in any of these regions for any reason could have a material impact on other regions and our business and 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.
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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 Renewable Fuels Standard mandates, our business, financial condition and results of operations could be materially adversely affected.
Pursuant to the Energy Independence and Security Act of 2007, the EPA has promulgated the Renewable Fuel Standard, or RFS, which requires refiners to either blend "renewable fuels," such as ethanol, into their petroleum fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels refineries like ours are obligated to blend into their finished petroleum products is adjusted annually. We currently purchase RINs for some fuel categories on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. Existing laws or regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum products may increase. In the future, we may be required to purchase additional RINs on the open market and waiver credits from the EPA in order to comply with the RFS. During 2013, the price of RINs was extremely volatile as the EPA’s proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 percentage standards were published; however RIN prices remained volatile and increased subsequently in 2014. In May 2014, the EPA lowered the 2013 cellulosic biofuel standard to 0.0005%, and, in June 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to September 30, 2014. In August 2014, the EPA further extended the compliance demonstration deadline for the 2013 RFS to 30 days following publication of the final 2014 annual renewable fuel percentage standards. In November 2014, the EPA announced that it would not finalize the 2014 annual renewable fuel percentage standards before the end of 2014, thereby extending the compliance deadline for the 2013 RFS as well.
We cannot predict the future prices of RINs or waiver credits, particularly until such time that the 2014 renewable fuel percentage standards are finalized and the 2015 renewable fuel percentage standards are announced. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, 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, all of which can vary significantly from quarter to quarter. However, the costs to obtain the necessary number of RINs and waiver credits could likely be material. 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 earning and materially adversely affecting our ability to make distributions. 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 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 any 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
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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 level of indebtedness may increase and reduce our financial flexibility.
As of the date of this Report, we had (i) $500.0 million aggregate principal amount of 6.5% senior notes due 2022 ("2022 Notes") outstanding, (ii) availability under the Amended and Restated ABL Credit Facility of $372.4 million, with letters of credit outstanding of approximately $27.6 million and (iii) $31.5 million borrowed under an intercompany credit facility, with availability under the intercompany credit facility of $218.5 million. In the future, we may incur additional significant indebtedness in order to make future acquisitions, expand our business or develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:
• | a significant portion of our cash flows could be used to service our indebtedness, reducing available cash and our ability to make distributions on our common units; |
• | a high level of debt would increase our vulnerability to general adverse economic and industry conditions; |
• | the covenants contained in our debt agreements will limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments; |
• | a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged, and therefore may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; |
• | our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; |
• | a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings under the Amended and Restated ABL Credit Facility; and |
• | a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, debt service requirements, acquisitions, general corporate or other purposes. |
In addition, borrowings under our Amended and Restated ABL Credit Facility, our intercompany credit facility and other credit facilities we may enter into in the future will bear interest at variable rates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect our ability to make distributions to common unitholders.
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 debt obligations 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. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt.
In addition, the bank borrowing base under the Amended and Restated ABL Credit Facility will be subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial condition and, as a result, our ability to make distributions to common unitholders.
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Covenants in our debt instruments could limit our ability to incur additional indebtedness and engage in certain transactions, which could adversely affect our liquidity and our ability to pursue our business strategies.
The indenture governing our notes and the Amended and Restated ABL Credit Facility contain a number of restrictive covenants that will impose significant operating and financial restrictions on us and our subsidiaries and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, among other things, to:
• | incur, assume or guarantee additional debt or issue redeemable or preferred units; |
• | make distributions or prepay, redeem, or repurchase certain debt; |
• | enter into agreements that restrict distributions from restricted subsidiaries; |
• | incur liens; |
• | sell or otherwise dispose of assets, including capital stock of subsidiaries; |
• | enter into transactions with affiliates; and |
• | merge, consolidate or sell substantially all of our assets. |
In particular, the indenture governing our notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture contains covenants limiting our 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, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. In addition, the Amended and Restated ABL Credit Facility requires us to maintain a minimum excess availability under the facility as a condition to the payment of distributions to our unitholders. Any new indebtedness could have similar or greater restrictions.
A breach of the covenants under the foregoing debt instruments could result in an event of default. Upon a default, unless waived, the lenders under our Amended and Restated ABL Credit Facility would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against us or our subsidiaries' assets, and force us and our subsidiaries into bankruptcy or liquidation, subject to intercreditor agreements. The holders of the 2022 Notes could accelerate all amounts due thereunder and also force us into bankruptcy and liquidation. In addition, any defaults could trigger cross defaults under other or future credit agreements or indentures. 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. As a result of these restrictions, we may be limited in how we conduct our business, unable to raise additional debt or equity financing to operate during general economic or business downturns or unable to compete effectively or to take advantage of new business opportunities.
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 |
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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 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. |
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 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 derivatives 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
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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 unitholders.
Our due diligence associated with acquisitions 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 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 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; |
• | 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 |
• | nonperformance 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. For example, we incurred approximately $88.8 million associated with the 2011/2012 turnaround completed at the Coffeyville refinery and we incurred approximately $102.5 million associated with the turnaround for the Wynnewood refinery, which we completed in December 2012. These costs do not result in increases in unit capacities, but rather are focused on trying to maintain safe, reliable operations. The first phase of the Coffeyville refinery’s next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. During the outage at our Coffeyville refinery as a result of the isomerization unit fire in the third quarter 2014, we accelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million in turnaround expenses. During the FCCU outage at our Wynnewood refinery in the fourth quarter of 2014, we accelerated certain planned 2016 turnaround activities and incurred approximately $1.3 million in turnaround expenses. Based on engineering and safety analysis of the equipment and as a result of other work performed, we are currently considering moving the next scheduled turnaround at our Wynnewood refinery to the first quarter of 2017.
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.
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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 processes, 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."
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 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, and some portions of the Wynnewood refinery have not yet been investigated to determine whether corrective action is necessary. 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.
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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. For example, the Wynnewood refinery's OPDES permit has expired and is in the renewal process. At this time, the Wynnewood refinery is operating under expired permit terms and conditions (called a permit shield) until the state regulatory agency renews the permit. The renewal permit may contain different terms and conditions that would require unplanned or unanticipated costs.
Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition and cash flows.
Various regulatory and legislative measures to address GHG emissions (including CO2, methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 "endangerment finding" that GHG emissions pose a threat to public health and welfare, the EPA has begun to regulate 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 NSR and Title V programs of the federal Clean Air Act. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing major source undergoes a major modification, facilities are required to undergo NSR review and to evaluate and install air pollution controls to reduce GHG emissions. A major modification resulting in a significant increase in GHG emissions at either of our refineries may require the installation of air pollution controls as part of the permitting process.
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. Although the EPA has proposed standards for electric utilities, it has not yet proposed NSPS standards to regulate GHG emissions from the petroleum refineries. 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 proposed sector risk rule would place additional emission control requirements on storage tanks, flares, and coking units at petroleum refineries. Therefore, we expect that the EPA will not be issuing NSPS to regulate GHG from the refineries at this time but that it may do so in the future.
During a State of the Union address in January 2014 and again in January 2015, President Obama indicated that the United States should take action to address climate change. 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 CO2 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 implementing the trading scheme before it becomes effective, and it is unclear whether Kansas intends to do so.
Alternatively, the EPA may take further steps to regulate GHG emissions. 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
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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.
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.
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 unitholders.
Both the Coffeyville and the Wynnewood refineries have a significant concentration of customers. Our five largest customers represented 35% of our net sales for the year ended December 31, 2014. One significant customer accounted for more than 10% of our net sales. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with any of 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 unitholders.
Our plans to expand the gathering assets making up part of our supporting logistics businesses, 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 operations. If we are able to successfully increase the effectiveness of our supporting logistics businesses, including our crude oil gathering operations, 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 our gathering operations 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 operations. The
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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 operations 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 the U.S. Department of Transportation 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 environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder 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.
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; |
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• | 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 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 unitholders. 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.
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, 2014, approximately 51% of the employees at the Coffeyville refinery and 59% of the employees at the Wynnewood refinery 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 United Steelworkers (which covers unionized employees who work in crude transportation and related operations) expires in March 2017, 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 2017. 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.
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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 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 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 unitholders.
We rely primarily on the executive officers of CVR Energy to manage most 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, business operations, 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.
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 Icahn Enterprises, which may be contrary to our interests. In addition, |
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our general partner is allowed to take into account the interests of parties other than us or our unitholders, such as its owners or CVR Energy, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.
• | 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:
• | 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 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. |
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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 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 Icahn Enterprises, as the indirect owners of our general partner, may not be consistent with those of our public 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 95% 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 unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. If our general partner and its affiliates reduce their ownership percentage to below 70% of the outstanding units, the ownership threshold to exercise the call right will be permanently reduced to 80%. As a result, our 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 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.
Our 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 unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. 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 unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, even if our 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 4% 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 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 unitholders.
Prior to making any distribution on our outstanding 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.
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Unitholders may have liability to repay distributions.
In the event that: (i) we make distributions to our 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 unitholder knows at the time of the distribution of such circumstances, such 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 unitholder knows at the time of such circumstances, then such 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.
Our general partner's interest in us and the control of our general partner may be transferred to a third party without 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 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 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, business operations, 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
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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 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 unitholders.
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 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 unitholders immediately prior to the issuance will decrease; |
• | the amount of cash distributions on each unit will decrease; |
• | the ratio of our taxable income to distributions may increase; |
• | the relative voting strength of each previously outstanding 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 the Initial Public Offering, we entered into a registration rights agreement with Icahn Enterprises, 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 affiliates 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. |
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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, 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.
Tax Risks
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our 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 U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. Current law requires us to derive at least 90% of our annual gross income from specific activities to continue to be treated as a partnership, rather than as a corporation, for U.S. federal income tax purposes. We may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement.
Although we do not believe, based upon our current operations, that we will be treated as a corporation for U.S. federal income tax purposes, a change in our business 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 entity level taxation. We may in the future enter into new activities or businesses. If our legal counsel were to be unable to opine that gross income from any such activity or business will count toward satisfaction of the 90% gross income, or qualifying income, requirement to be treated as a partnership for U.S. federal income tax purposes, we could seek a ruling, if available, from the IRS that gross income we earn from any such activity or business will be qualifying income. There can be no assurance, however, that the IRS would issue a favorable ruling under such circumstances. If we did not receive a favorable ruling, we could choose to engage in the activity or business through a corporate subsidiary, which would subject the income related to such activity or business to entity-level taxation. Except to the extent that we in the future request a ruling regarding the qualifying nature of our income from a particular activity or business, we do not intend to request a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.
If we were treated as a corporation for U.S. federal income tax purposes, or if we were otherwise subject to entity-level taxation, we would pay U.S. federal income tax on all of our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
The tax treatment of publicly-traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly 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. Current law may change to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. The current administration and members of Congress from time to time have considered substantive changes to the existing U.S. federal income tax laws that would adversely affect the tax treatment of publicly traded partnerships. One such 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. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could cause a substantial reduction in the value of our common units.
Several states currently subject partnerships to entity-level taxation. Specifically, we are subject to the Texas franchise tax. Such taxes reduce our cash available for distribution to our unitholders. Other states are evaluating proposals to subject
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partnerships to entity-level taxation through the imposition of income, franchise or other forms of taxation. Imposition of these or similar taxes by any other state in which we do business will further reduce our cash available for distribution to our unitholders and could cause a substantial reduction in the value of our common units. We are unable to predict whether any of these or other proposals will ultimately be enacted.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be materially and adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
Except to the extent that we, in the future, request a ruling regarding the qualifying nature of our income, we have not and do not intend to request a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS's positions may ultimately be sustained. 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. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
A unitholder's share of our income is taxable for U.S. federal income tax purposes even if the unitholder does not receive any cash distributions from us.
Our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute. A unitholder's allocable share of our taxable income is taxable to the unitholder, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes on the unitholder's share of our taxable income, even if no cash distributions are received from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.
We will be considered to have technically terminated as a partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same common unit will be counted only once. Our sponsor directly and indirectly owns more than 50% of the total interests in our capital and profits. Therefore, a transfer by our sponsor of all or a portion of its interests in us could result in a termination of us as a partnership for U.S. federal income tax purposes. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than one year of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. Our technical termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, after our termination we would be treated as a new partnership for U.S. federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby a publicly traded partnership that has technically terminated may request special relief that, if granted, would permit the partnership to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if our unitholders sell common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.
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Tax-exempt entities and non-U.S. persons 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), and non-U.S. persons 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. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your 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 actual common units 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 depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations promulgated under the Internal Revenue Code, referred to as "Treasury Regulations." A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could cause a substantial reduction in the value of our common units or result in audit adjustments to our unitholders' tax returns.
We prorate our items of income, gain, loss and deduction, for U.S. federal income tax purposes, 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 unitholders.
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 use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued requiring a change, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders. Counsel has not rendered an opinion to us with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.
A 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 as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income 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 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 as having disposed of the loaned common units. In that case, the unitholder may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and the 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 unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
Our unitholders will likely be subject to state and local taxes and 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, unitholders are likely to be subject to other taxes, including 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 or control property now or in the future, even if they do not live in any of those jurisdictions. We currently own assets and/or conduct business in the states of Arkansas, Iowa, Kansas, Missouri, Nebraska, Oklahoma, Texas
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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. 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, 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 the responsibility of each unitholder to file all U.S. federal, state, local, and non-U.S. tax returns. Our counsel has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in our common units.
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Item 1B. Unresolved Staff Comments
None.
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) | 20 | Own | Crude oil storage | |||
Montgomery County, KS (Broome Station) | 20 | Own | Crude oil storage | |||
Cowley County, KS (Hooser Station) | 80 | 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 needs.
As of December 31, 2014, we own crude oil storage capacity of approximately (i) 1.4 million barrels supporting the gathering system and Coffeyville refinery, (ii) 0.9 million barrels at the Wynnewood refinery and (iii) 1.0 million barrels in Cushing, Oklahoma. We also lease additional crude oil storage capacity of approximately 2.8 million barrels in Cushing and 0.1 million barrels at the Wynnewood refinery. In addition to crude oil storage, we own approximately 4.5 million barrels of combined refinery related storage capacity.
We have entered into 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 and Combined Financial Statements as set forth in Part II, Item 8 of this Report. In accordance with 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
None.
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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:
2014 | High | Low | |||||
First Quarter | $ | 23.80 | $ | 20.16 | |||
Second Quarter | 28.55 | 22.09 | |||||
Third Quarter | 26.58 | 22.17 | |||||
Fourth Quarter | 25.15 | 16.33 | |||||
2013 | High | Low | |||||
First Quarter | $ | 35.98 | $ | 24.50 | |||
Second Quarter | 34.99 | 26.44 | |||||
Third Quarter | 30.69 | 24.04 | |||||
Fourth Quarter | 26.39 | 20.80 | |||||
Holders of Record
As of February 17, 2015, there were 11 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
Our general partner's current policy is to distribute all of the available cash we generate each quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter and will generally equal Adjusted EBITDA reduced for (i) cash needed for debt service, (ii) reserves for environmental and maintenance capital expenditures, (iii) reserves for future major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. Further, it is our intent, subject to market conditions, to finance growth capital externally, and not to reserve cash for unspecified potential future needs.
Because our policy will be 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.
Our ability to make distributions is limited by our Amended and Restated ABL Credit Facility and the 2022 Notes. See Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources" for a discussion of those limitations.
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The following is a summary of cash distributions paid to our unitholders during the years ended December 31, 2014 and 2013 for the respective quarters to which the distributions relate:
December 31, 2013 | March 31, 2014 | June 30, 2014 | September 30, 2014 | Total Cash Distributions Paid in 2014 | |||||||||||||||
(in millions, except per unit data) | |||||||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates | $ | 49.8 | $ | 108.6 | $ | 99.2 | $ | 55.8 | $ | 313.4 | |||||||||
Amounts paid to non-affiliates | 16.6 | 36.1 | 42.5 | 23.9 | 119.1 | ||||||||||||||
Total amount paid | $ | 66.4 | $ | 144.7 | $ | 141.7 | $ | 79.7 | $ | 432.5 | |||||||||
Per common unit | $ | 0.45 | $ | 0.98 | $ | 0.96 | $ | 0.54 | $ | 2.93 | |||||||||
Common units outstanding | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||||||
March 31, 2013 (1) | June 30, 2013 | September 30, 2013 | Total Cash Distributions Paid in 2013 | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates | $ | 195.9 | $ | 149.6 | $ | 33.2 | $ | 378.7 | |||||||
Amounts paid to non-affiliates | 37.3 | 49.7 | 11.1 | 98.0 | |||||||||||
Total amount paid | $ | 233.2 | $ | 199.3 | $ | 44.3 | $ | 476.7 | |||||||
Per common unit | $ | 1.58 | $ | 1.35 | $ | 0.30 | $ | 3.23 | |||||||
Common units outstanding | 147.6 | 147.6 | 147.6 | ||||||||||||
(1) | The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Initial Public Offering). |
On February 18, 2015, the board of directors of the Partnership's general partner declared a cash distribution for the fourth quarter of 2014 to the Partnership's unitholders of $0.37 per common unit, or $54.6 million in aggregate. The cash distribution will be paid on March 9, 2015 to unitholders of record at the close of business on March 2, 2015. Total cash distributions paid and to be paid based upon available cash for 2014 were $2.85 per common unit.
Unit Performance Graph
The following graph sets forth the cumulative return on our common units between January 17, 2013 and December 31, 2014, as compared to the cumulative return of the Russell 2000 Index and an industry peer group consisting of Alon USA Energy, Inc., Delek US Holdings, Inc., HollyFrontier Corporation, Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. The graph assumes an investment of $100 on January 17, 2013 based on the closing unit price in our common units, the Russell 2000 Index and the industry peer group, and assumes the reinvestment of distributions where applicable. The closing market price for our common units on December 31, 2014 was $16.80. The unit price performance shown on the graph is not intended to forecast and does not necessarily indicate future price performance.
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COMPARISON OF CUMULATIVE TOTAL RETURN
BETWEEN JANUARY 17, 2013 AND DECEMBER 31, 2014
among CVR Refining, LP, Russell 2000 Index and a peer group
This performance graph shall not be deemed "filed" for purposes of Section 18 of the Exchange Act, or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.
Jan '13 | Mar '13 | Jun '13 | Sep '13 | Dec '13 | Mar '14 | Jun '14 | Sep '14 | Dec '14 | ||||||||||||||||||
CVR Refining, LP | 100.00 | 138.50 | 125.70 | 109.40 | 100.60 | 105.70 | 117.65 | 113.85 | 84.00 | |||||||||||||||||
Russell 2000 Index | 100.00 | 106.87 | 109.78 | 120.60 | 130.69 | 131.75 | 133.99 | 123.73 | 135.30 | |||||||||||||||||
Peer Group | 100.00 | 120.45 | 98.15 | 88.06 | 125.78 | 117.54 | 115.11 | 121.97 | 121.15 | |||||||||||||||||
Purchases of Equity Securities by the Issuer
We did not repurchase any of our common units during the fiscal quarter ended December 31, 2014.
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Item 6. Selected Financial Data
You should read the selected historical consolidated and combined financial data presented below in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated and combined financial statements and the related notes included elsewhere in this Report.
The selected consolidated and combined financial information presented below under the caption "Statements of Operations Data" for the years ended December 31, 2014, 2013 and 2012 and the selected consolidated financial information presented below under the caption "Balance Sheet Data" as of December 31, 2014 and 2013 has been derived from our audited consolidated and combined financial statements included elsewhere in this Report. Grant Thornton LLP, our independent registered public accounting firm, audited our consolidated financial statements for the years ended December 31, 2014 and 2013, and KPMG LLP, our predecessor accounting firm, audited our consolidated and combined financial statements for the year ended December 31, 2012. The combined financial information presented below under the caption "Statements of Operations Data" for the years ended December 31, 2011 and 2010 and the consolidated and combined financial information at December 31, 2012 and the combined financial statement information at December 31, 2011 and 2010 presented below under the caption "Balance Sheet Data" is derived from our audited consolidated and combined financial statements that are not included in this Report.
Year Ended December 31, | |||||||||||||||||||
2014 | 2013 | 2012 | 2011(1) | 2010 | |||||||||||||||
(in millions, except per unit data) | |||||||||||||||||||
Statements of Operations Data | |||||||||||||||||||
Net sales | $ | 8,829.7 | $ | 8,683.5 | $ | 8,281.7 | $ | 4,752.8 | $ | 3,905.6 | |||||||||
Cost of product sold(2) | 8,013.4 | 7,526.7 | 6,667.5 | 3,927.6 | 3,539.8 | ||||||||||||||
Direct operating expenses(2) | 416.0 | 361.7 | 426.5 | 247.7 | 153.1 | ||||||||||||||
Selling, general and administrative expenses(2) | 70.6 | 77.8 | 86.2 | 51.0 | 43.1 | ||||||||||||||
Depreciation and amortization | 122.5 | 114.3 | 107.6 | 69.8 | 66.4 | ||||||||||||||
Operating income | 207.2 | 603.0 | 993.9 | 456.7 | 103.2 | ||||||||||||||
Interest expense and other financing costs | (34.2 | ) | (44.1 | ) | (76.2 | ) | (53.0 | ) | (49.7 | ) | |||||||||
Interest income | 0.3 | 0.4 | — | — | 2.1 | ||||||||||||||
Gain (loss) on derivatives, net | 185.6 | 57.1 | (285.6 | ) | 78.1 | (1.5 | ) | ||||||||||||
Loss on extinguishment of debt | — | (26.1 | ) | (37.5 | ) | (2.1 | ) | (16.6 | ) | ||||||||||
Other income (expense), net | (0.2 | ) | 0.1 | 0.7 | 0.6 | 0.7 | |||||||||||||
Income before income tax expense | 358.7 | 590.4 | 595.3 | 480.3 | 38.2 | ||||||||||||||
Income tax expense | — | — | — | — | — | ||||||||||||||
Net income | $ | 358.7 | $ | 590.4 | $ | 595.3 | $ | 480.3 | $ | 38.2 | |||||||||
Available cash for distribution(3) | $ | 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(4) | $ | 2.43 | $ | 3.47 | |||||||||||||||
Net income per common unit – diluted(4) | $ | 2.43 | $ | 3.47 | |||||||||||||||
Weighted average common units outstanding: | |||||||||||||||||||
Basic | 147.6 | 147.6 | |||||||||||||||||
Diluted | 147.6 | 147.6 | |||||||||||||||||
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Year Ended December 31, | |||||||||||||||||||
2014 | 2013 | 2012 | 2011(1) | 2010 | |||||||||||||||
(in millions) | |||||||||||||||||||
Balance Sheet Data | |||||||||||||||||||
Cash and cash equivalents | $ | 370.2 | $ | 279.8 | $ | 153.1 | $ | 2.7 | $ | 2.3 | |||||||||
Working capital | 504.5 | 656.9 | 382.7 | 384.7 | 138.7 | ||||||||||||||
Total assets | 2,417.8 | 2,533.3 | 2,258.5 | 2,262.4 | 1,072.8 | ||||||||||||||
Total debt, including current portion | 581.4 | 582.7 | 773.2 | 729.9 | 469.0 | ||||||||||||||
Total partners' capital/divisional equity | 1,450.1 | 1,522.1 | 980.8 | 1,018.6 | 418.8 | ||||||||||||||
Cash Flow Data | |||||||||||||||||||
Net cash flow provided by (used in): | |||||||||||||||||||
Operating activities | 715.8 | 601.0 | 917.3 | 352.7 | 167.0 | ||||||||||||||
Investing activities | (191.2 | ) | (204.4 | ) | (119.8 | ) | (655.9 | ) | (21.1 | ) | |||||||||
Financing activities(5) | (434.2 | ) | (269.9 | ) | (647.1 | ) | 303.6 | (146.3 | ) | ||||||||||
Net cash flow | $ | 90.4 | $ | 126.7 | $ | 150.4 | $ | 0.4 | $ | (0.4 | ) | ||||||||
Capital expenditures for property, plant and equipment | $ | 191.3 | $ | 204.5 | $ | 120.2 | $ | 68.8 | $ | 21.2 | |||||||||
(1) | We acquired WEC on December 15, 2011 and its results of operations are included from the date of acquisition. This transaction impacts the comparability of Selected Financial Data. |
(2) | Amounts are shown exclusive of depreciation and amortization. |
(3) | 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 future major scheduled turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Available cash for distribution is not a recognized term under GAAP. Available cash should not be considered in isolation or as an alternative to net income or operating income, as a measure of operating performance. In addition, available cash for distribution is not presented as, and should not be considered an alternative to cash flows from operations or as a measure of liquidity. Available cash as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure. For the year ended December 31, 2013, available cash for distribution is calculated for the period beginning at the closing of our Initial Public Offering (January 23, 2013 through December 31, 2013). |
(4) | We have omitted net income per unit for the years ended December 31, 2012 through 2010 because we operated under a different capital structure prior to the closing of the Initial Public Offering, and, as a result, the per unit data would not be meaningful to investors. Per unit data for the year ended December 31, 2013 is calculated since the closing of the Initial Public Offering on January 23, 2013. |
(5) | Prior to December 31, 2012, Coffeyville Resources, LLC ("CRLLC") provided cash as necessary to support our operations and retained excess cash generated by our operations. Historical cash received, or paid by, CRLLC on our behalf has been recorded as net contributions from, or net distributions to, parent, respectively, as a component of divisional equity in our historical combined financial statements, and as a financing activity in our Consolidated and Combined Statements of Cash Flows. Net contributions from (distributions to) parent included in cash flows from financing activities were $(651.6) million, $110.6 million and $(116.3) million for the years ended December 31, 2012, 2011 and 2010, respectively. |
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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 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 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 consequences from accidents, fire, severe weather, floods, or other natural disasters, or other operating hazards resulting in unscheduled downtime; |
• | our continued ability to secure gasoline and diesel 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; |
• | 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; and |
• | changes in our treatment as a partnership for U.S. income tax purposes. |
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.
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Overview and Executive Summary
We are an independent downstream energy limited partnership with refining and related logistics assets that operates in the underserved Group 3 of the PADD II region of the United States. Our business includes a complex full coking medium-sour crude oil refinery in Coffeyville, Kansas with a rated capacity of 115,000 bpcd and a complex crude oil refinery in Wynnewood, Oklahoma with a rated capacity of 70,000 bpcd capable of processing 20,000 bpcd of light sour crude oil (within its rated capacity of 70,000 bpcd). In addition, our supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 60,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a 170,000 bpd pipeline system (supported by approximately 336 miles of owned and leased pipelines) that transports crude oil to our Coffeyville refinery from our Broome Station facility located near Caney, Kansas, (3) over 6.0 million barrels of owned and leased crude oil storage, (4) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and located at throughput terminals on Magellan and NuStar refined petroleum products distribution systems and (5) approximately 4.5 million barrels of combined refinery related storage capacity.
Our Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Our Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations and Canada. In addition to rack sales (sales which are made at terminals into third-party tanker trucks), we make bulk sales (sales through third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar.
Crude oil is supplied to our Coffeyville refinery through our gathering system and by a pipeline owned by Plains that runs from Cushing to our Broome Station facility. We maintain capacity on the Keystone and Spearhead pipelines from Canada to Cushing, and by the third quarter of 2015, we will maintain contracted capacity on the Pony Express and White Cliffs pipelines both originating in Colorado and extending to Cushing. We also maintain leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. Our Coffeyville refinery blend consists of a combination of crude oil grades, including domestic grades and various Canadian medium and heavy sours. Crude oil is supplied to our Wynnewood refinery through three third-party pipelines operated by Sunoco Pipeline, Excel Pipeline and Blueknight Pipeline and historically has mainly been sourced from Texas and Oklahoma. Our Wynnewood refinery is capable of processing a variety of crudes, including WTS, WTI, sweet and sour Canadian and other U.S. domestically produced crude oils. We have incurred total costs of approximately $44.0 million, excluding capitalized interest, on a hydrocracker project, which was completed in the fourth quarter 2014. The hydrocracker project will increase the conversion capability and the ULSD yield of the Wynnewood refinery. The access to a variety of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for 2014 was $0.54 per barrel compared to $2.57 per barrel in 2013 and $2.26 per barrel in 2012.
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. In preparation of the Initial Public Offering, CRLLC contributed its wholly-owned subsidiaries and logistics assets described above to CVR Refining, LLC ("Refining LLC") in October 2012, and CVR Refining Holdings, LLC ("CVR Refining Holdings"), a subsidiary of CRLLC and an indirect wholly-owned subsidiary of CVR Energy, contributed Refining LLC to us on December 31, 2012.
CVR Energy Transaction Agreement
On April 18, 2012, prior to our formation by CVR Energy as discussed above, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with an affiliate of Icahn Enterprises L.P. ("IEP"). Pursuant to the Transaction Agreement, IEP's affiliate offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment ("CCP") right for each share which represented the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy was executed on or before August 18, 2013 and such transaction closed. As no sale of CVR Energy was executed by the date outlined in the Transaction Agreement, the CCPs expired on August 19, 2013.
In May 2012, IEP's affiliate acquired a majority of the common stock of CVR Energy through the Offer. As of December 31, 2014, IEP and its affiliates owned approximately 82% of CVR Energy’s outstanding common stock.
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Our Initial Public Offering
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 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." 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.
The net proceeds to us from the Initial Public Offering were approximately $653.6 million, after deducting underwriting discounts and commissions and offering expenses. Approximately $253.0 million of the net proceeds were used to redeem all of the outstanding Second Lien Notes, $160.0 million was used to fund certain maintenance and environmental capital expenditures through 2014, $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery in the fourth quarter of 2012, $85.1 million was distributed to CRLLC and the remaining proceeds were used for general corporate purposes. Prior to the closing of the Initial Public Offering, we distributed approximately $150.0 million of cash on hand to CRLLC.
Our Underwritten Offering
On May 20, 2013, we completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a CVR Energy subsidiary, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, we sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the "Transactions."
We utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings. We did not receive any of the proceeds from the sale of common units by a CVR Energy subsidiary to AEPC.
Following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of all outstanding limited partner interests (including common units held by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 71% of all outstanding limited partner interests.
Our Second Underwritten Offering
On June 30, 2014, we completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. We paid approximately $5.3 million in underwriting fees and approximately $0.5 million in offering costs. We utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings. Subsequent to the closing of the Second Underwritten Offering and through July 23, 2014, public security holders held approximately 33% of all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.
On July 24, 2014, we sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their option to purchase additional common units. We utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.
Subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2014, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% 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, LLC, which holds a non-economic general partner interest.
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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 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 home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. The petroleum business is also subject to the EPA's Renewable Fuel Standard ("RFS"), which requires it to either blend "renewable fuels" in with its transportation fuels or purchase renewable fuel credits, known as renewable identification numbers ("RINs"), in lieu of blending.
The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinery was subject to the RFS for the first time.
During 2013, the cost of RINs was extremely volatile as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 proposed percentage standards were published; however, RIN prices remained volatile and increased subsequently in 2014. In May 2014, the EPA lowered the 2013 cellulosic biofuel standard to 0.0005%, and, in June 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to September 30, 2014. In August 2014, the EPA further extended the compliance demonstration deadline for the 2013 RFS to 30 days following publication of the final 2014 annual renewable fuel percentage standards. In November 2014, the EPA announced that it would not finalize the 2014 annual renewable fuel percentage standards before the end of 2014, thereby extending the compliance deadline for 2013 RFS as well.
The cost of RINs for the years ended December 31, 2014, 2013 and 2012 was approximately $127.2 million, $180.5 million and $21.0 million, respectively. The future cost of RINs for our business is difficult to estimate, particularly until such time that the 2014 renewable fuel percentage standards are finalized and the 2015 renewable fuel percentage standards are announced. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, 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, all of which can vary significantly from quarter to quarter. Based upon recent market prices of RINs and current estimates related to the other variable factors, we estimate that the total cost of RINs will be approximately $95.0 million to $170.0 million for the year ending December 31, 2015.
If sufficient RINs are unavailable for purchase at times when we seek to purchase RINs, or if we have to pay a significantly higher price for RINs or if we are subject to penalties as a result of delays in its ability to timely deliver RINs to the EPA, our business, financial condition and results of operations could be materially adversely affected. Many petroleum refiners blend renewable fuel into their transportation fuels and do not have to pass on the costs of compliance through the
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purchase of RINs to their customers. Therefore, it may be significantly harder for us to pass on the costs of compliance with RFS to our customers.
In order to assess our operating performance, we compare our net sales, less cost of product sold (exclusive of depreciation and amortization), 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 is 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 refinery 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 refinery 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 refinery 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.
We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces, resulting in prices that reflect the logistics cost for Gulf Coast refineries to ship into our region. The result of this logistical advantage and 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 that 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 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. Additionally, in late 2014, market factors resulted in a rapid downward price adjustment in the oil and gas industry. The resultant spike in volatility continuing in 2015 has caused major adjustments in oil debt markets as well as announced and expected cuts in 2015 budgets in both North American shale and Canadian projects. The refining industry is directly impacted by these events and has seen a downward movement in refining margins as a result.
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, 2014, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $10.3 million.
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. This 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.
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
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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. Our Coffeyville refinery completed the first phase of a two-phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012 and the first phase of its next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. During the outage at our Coffeyville refinery in the third quarter of 2014 as discussed further below, we accelerated certain planned 2015 turnaround activities and incurred approximately $5.5 million in turnaround expenses for the year ended December 31, 2014. We completed a turnaround at our Wynnewood refinery in December 2012. During the outage at our Wynnewood refinery in the fourth quarter of 2014 as discussed further below, we accelerated certain planned 2016 turnaround activities and incurred approximately $1.3 million in turnaround expenses for the year ended December 31, 2014. Based on engineering and safety analysis of the equipment and as a result of other work performed, we are currently considering moving the next scheduled turnaround at our Wynnewood refinery to the first quarter of 2017.
During the third quarter of 2013, the fluid catalytic cracking unit ("FCCU") at our Coffeyville refinery was offline for approximately 55 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at our Coffeyville refinery was significantly reduced during the third quarter of 2013. Additionally, we incurred approximately $21.1 million in costs to repair the FCCU for the year ended December 31, 2013. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
On July 29, 2014, our Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employee who was fatally injured. 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. The refinery returned to operations in mid-August, with all units except the isomerization unit in operation by August 23, 2014. The isomerization unit started operating on October 12, 2014. This interruption adversely impacted production of refined products 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.
We are covered by property damage insurance policies which have an associated deductible of $5.0 million for the Coffeyville refinery. We anticipate amounts in excess of the $5.0 million deductible related to the isomerization unit fire incident will be recoverable under the property insurance policies. As of December 31, 2014, we recorded an insurance receivable related to the incident of approximately $1.3 million, which is included in prepaid expenses and other current assets in the Consolidated Balance Sheets. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization). We also maintain workers' compensation insurance with a $0.5 million per accident deductible.
During the fourth quarter of 2014, the FCCU at our Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at our Wynnewood refinery was significantly reduced during the fourth quarter of 2014. Additionally, we incurred approximately $8.5 million in costs to repair the FCCU for the year ended December 31, 2014. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
Agreements with Affiliates
In connection with the initial public offering of CVR Energy and the transfer of the nitrogen fertilizer business to CVR Partners in October 2007, CVR Energy and its subsidiaries entered into a number of 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 CVR Partners' initial public offering, CVR Energy, directly or through its subsidiaries, amended and restated certain of the intercompany agreements and entered into several new agreements with CVR Partners. In connection with our Initial Public Offering, 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
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operational facilities, pipelines, equipment, access, and water rights; and (vi) 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.
In connection with the Initial Public Offering, we entered into a number of agreements with CVR Energy, including (i) a $150.0 million intercompany credit facility between CRLLC and us, which was subsequently expanded to $250.0 million on October 29, 2014 and (ii) a services agreement, pursuant to which we are managed by CVR Energy.
Crude Oil Supply Agreement
On August 31, 2012, CRRM and Vitol Inc. ("Vitol") entered into an Amended and Restated Crude Oil Supply Agreement (the "Vitol Agreement"). Under the Vitol Agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement had an initial term (the "Initial Term") commencing on August 31, 2012 and extending through December 31, 2014. Following the Initial Term, 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 the Initial Term or any Renewal Term. The Vitol Agreement was extended for a one-year Renewal Term through December 31, 2015.
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, | ||||||||||||
2014 | 2013 | 2012 | ||||||||||
(in millions) | ||||||||||||
Loss on extinguishment of debt(a) | $ | — | $ | 26.1 | $ | 37.5 | ||||||
Expenses associated with the acquisition of Gary-Williams(b) | — | — | 11.0 | |||||||||
Share-based compensation(c) | 8.0 | 11.6 | 18.5 | |||||||||
(Gain) loss on derivatives, net | (185.6 | ) | (57.1 | ) | 285.6 | |||||||
Major scheduled turnaround expenses(d) | 6.8 | — | 123.7 | |||||||||
_______________________________________
(a) Represents (1) for 2013, the write-off of previously deferred financing costs, unamortized original issue discount and the premium paid related to the extinguishment of the second lien senior secured notes (the "Second Lien Notes") and (2) for 2012, the write-off of previously deferred financing costs, unamortized premium/discount and premiums paid upon the extinguishment of the first lien senior secured notes (the "First Lien Notes" and together with the Second Lien Notes, the "Old Notes"), which contributed approximately $33.4 million of the loss on extinguishment of debt, and the write-off of a portion of previously deferred financing costs associated with the prior ABL credit facility, which was replaced with an Amended and Restated ABL Credit Facility and contributed approximately $4.1 million of the loss on extinguishment of debt.
(b) As a result of the acquisition of the Wynnewood refinery in December 2011, we incurred integration expenses during the year ended December 31, 2012. We did not incur such expenses for the years ended December 31, 2014 or 2013 as the operations were fully integrated.
(c) Represents impact of share-based compensation awards.
(d) Represents expense associated with major scheduled turnaround activities performed at our Coffeyville refinery ($5.5 million in 2014 and $21.2 million in 2012) and our Wynnewood refinery ($1.3 million in 2014 and $102.5 million in 2012).
Distributions to CVR Refining Unitholders
The current policy of the board of directors of our general partner is to distribute all of the available cash we generate each quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of
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such quarter and will generally equal Adjusted EBITDA reduced for cash needed for debt service, reserves for environmental and maintenance capital expenditures, reserves for future major scheduled turnaround expenses and, to the extent applicable, reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Actual distributions are set by the board of directors of our general partner. The board of directors of our general partner may modify the cash distribution policy at any time, and the partnership agreement does not require us to make distributions at all.
The following is a summary of cash distributions paid to our unitholders during the years ended December 31, 2014 and 2013 for the respective quarters to which the distributions relate:
December 31, 2013 | March 31, 2014 | June 30, 2014 | September 30, 2014 | Total Cash Distributions Paid in 2014 | |||||||||||||||
(in millions, except per unit data) | |||||||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates | $ | 49.8 | $ | 108.6 | $ | 99.2 | $ | 55.8 | $ | 313.4 | |||||||||
Amounts paid to non-affiliates | 16.6 | 36.1 | 42.5 | 23.9 | 119.1 | ||||||||||||||
Total amount paid | $ | 66.4 | $ | 144.7 | $ | 141.7 | $ | 79.7 | $ | 432.5 | |||||||||
Per common unit | $ | 0.45 | $ | 0.98 | $ | 0.96 | $ | 0.54 | $ | 2.93 | |||||||||
Common units outstanding | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||||||
March 31, 2013 (1) | June 30, 2013 | September 30, 2013 | Total Cash Distributions Paid in 2013 | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates | $ | 195.9 | $ | 149.6 | $ | 33.2 | $ | 378.7 | |||||||
Amounts paid to non-affiliates | 37.3 | 49.7 | 11.1 | 98.0 | |||||||||||
Total amount paid | $ | 233.2 | $ | 199.3 | $ | 44.3 | $ | 476.7 | |||||||
Per common unit | $ | 1.58 | $ | 1.35 | $ | 0.30 | $ | 3.23 | |||||||
Common units outstanding | 147.6 | 147.6 | 147.6 | ||||||||||||
(1) | The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Initial Public Offering). |
On February 18, 2015, the board of directors of the Partnership's general partner declared a cash distribution for the fourth quarter of 2014 to the Partnership's unitholders of $0.37 per common unit, or $54.6 million in aggregate. The cash distribution will be paid on March 9, 2015 to unitholders of record at the close of business on March 2, 2015. Total cash distributions paid and to be paid based upon available cash for 2014 were $2.85 per common unit.
Publicly Traded Partnership Expenses
Our general and administrative expenses have increased or will increase in part due to the costs of our operating as a publicly traded company, including costs associated with SEC reporting requirements (including annual and quarterly reports to unitholders), tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses, which also include increased personnel costs, approximate $5.0 million per year, excluding the costs associated with the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing in 2013. Our historical consolidated and combined financial statements for periods ended prior to January 23, 2013 do not reflect the impact of these expenses, which affects the comparability of our post-IPO results with our financial statements from periods prior to the completion of our IPO.
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Results of Operations
The period to period comparisons of our results of operations have been prepared using the historical periods included in our consolidated and combined financial statements. The combined financial statements prior to CRLLC's contribution of the petroleum business to us on December 31, 2012 are based on the historical operations of the petroleum refining and related logistics business of CVR Energy, including the operations of both the Coffeyville and Wynnewood refineries. 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, 2014, 2013 and 2012.
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 Our 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 product sold. Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization).
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Consolidated Statements of Operations Data | |||||||||||
Net sales | $ | 8,829.7 | $ | 8,683.5 | $ | 8,281.7 | |||||
Cost of product sold(1) | 8,013.4 | 7,526.7 | 6,667.5 | ||||||||
Direct operating expenses(1)(2) | 409.2 | 361.7 | 302.8 | ||||||||
Major scheduled turnaround expenses | 6.8 | — | 123.7 | ||||||||
Selling, general and administrative expenses(1) | 70.6 | 77.8 | 86.2 | ||||||||
Depreciation and amortization | 122.5 | 114.3 | 107.6 | ||||||||
Operating income | 207.2 | 603.0 | 993.9 | ||||||||
Interest expense and other financing costs | (34.2 | ) | (44.1 | ) | (76.2 | ) | |||||
Interest income | 0.3 | 0.4 | — | ||||||||
Gain (loss) on derivatives, net | 185.6 | 57.1 | (285.6 | ) | |||||||
Loss on extinguishment of debt | — | (26.1 | ) | (37.5 | ) | ||||||
Other income (expense), net | (0.2 | ) | 0.1 | 0.7 | |||||||
Income before income tax expense | 358.7 | 590.4 | 595.3 | ||||||||
Income tax expense | — | — | — | ||||||||
Net income | $ | 358.7 | $ | 590.4 | $ | 595.3 | |||||
Gross profit(3) | $ | 277.8 | $ | 680.8 | $ | 1,080.1 | |||||
Refining margin(4) | $ | 816.3 | $ | 1,156.8 | $ | 1,614.2 | |||||
Adjusted EBITDA(5) | $ | 621.6 | $ | 712.0 | $ | 1,176.2 | |||||
Available cash for distribution(6) | $ | 421.5 | $ | 546.0 | |||||||
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Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars per barrel) | |||||||||||
Key Operating Statistics | |||||||||||
Per crude oil throughput barrel: | |||||||||||
Refining margin(4) | $ | 11.38 | $ | 16.90 | $ | 26.04 | |||||
Gross profit(3) | $ | 3.87 | $ | 9.94 | $ | 17.42 | |||||
Direct operating expenses and major scheduled turnaround expenses(1)(2) | $ | 5.80 | $ | 5.28 | $ | 6.88 | |||||
Direct operating expenses and major scheduled turnaround expenses per barrel sold(1)(7) | $ | 5.44 | $ | 5.00 | $ | 6.38 | |||||
Barrels sold (barrels per day)(7) | 209,669 | 198,142 | 182,701 | ||||||||
Year Ended December 31, | |||||||||||||||||
2014 | 2013 | 2012 | |||||||||||||||
% | % | % | |||||||||||||||
Refining Throughput and Production Data (bpd) | |||||||||||||||||
Throughput: | |||||||||||||||||
Sweet | 179,059 | 86.2 | 149,147 | 75.4 | 130,414 | 72.4 | |||||||||||
Medium | 2,022 | 1.0 | 19,151 | 9.7 | 21,334 | 11.8 | |||||||||||
Heavy sour | 15,464 | 7.4 | 19,270 | 9.8 | 17,608 | 9.8 | |||||||||||
Total crude oil throughput | 196,545 | 94.6 | 187,568 | 94.9 | 169,356 | 94.0 | |||||||||||
All other feedstocks and blendstocks | 11,284 | 5.4 | 10,121 | 5.1 | 10,791 | 6.0 | |||||||||||
Total throughput | 207,829 | 100.0 | 197,689 | 100.0 | 180,147 | 100.0 | |||||||||||
Production: | |||||||||||||||||
Gasoline | 102,275 | 48.9 | 94,561 | 47.7 | 89,787 | 49.9 | |||||||||||
Distillate | 87,639 | 41.9 | 82,089 | 41.4 | 72,804 | 40.6 | |||||||||||
Other (excluding internally produced fuel) | 19,149 | 9.2 | 21,617 | 10.9 | 17,262 | 9.5 | |||||||||||
Total refining production (excluding internally produced fuel) | 209,063 | 100.0 | 198,267 | 100.0 | 179,853 | 100.0 | |||||||||||
Product price (dollars per gallon): | |||||||||||||||||
Gasoline | $ | 2.53 | $ | 2.72 | $ | 2.86 | |||||||||||
Distillate | 2.81 | 3.02 | 3.08 | ||||||||||||||
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Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
Market Indicators (dollars per barrel) | |||||||||||
West Texas Intermediate (WTI) NYMEX | $ | 92.91 | $ | 98.05 | $ | 94.15 | |||||
Crude Oil Differentials: | |||||||||||
WTI less WTS (light/medium sour) | 5.95 | 2.64 | 5.40 | ||||||||
WTI less WCS (heavy sour) | 18.48 | 24.58 | 22.53 | ||||||||
NYMEX Crack Spreads: | |||||||||||
Gasoline | 17.29 | 21.44 | 28.55 | ||||||||
Heating Oil | 23.59 | 27.60 | 32.94 | ||||||||
NYMEX 2-1-1 Crack Spread | 20.44 | 24.52 | 30.75 | ||||||||
PADD II Group 3 Product Basis: | |||||||||||
Gasoline | (4.45 | ) | (4.54 | ) | (3.11 | ) | |||||
Ultra Low Sulfur Diesel | 0.75 | 0.58 | 2.17 | ||||||||
PADD II Group 3 Product Crack Spread: | |||||||||||
Gasoline | 12.84 | 16.90 | 25.45 | ||||||||
Ultra Low Sulfur Diesel | 24.34 | 28.18 | 35.11 | ||||||||
PADD II Group 3 2-1-1 | 18.59 | 22.54 | 30.28 | ||||||||
(1) | Our cost of product sold, direct operating expenses and selling, general and administrative expenses for the years ended December 31, 2014, 2013 and 2012 are shown exclusive of depreciation and amortization, which is comprised of the following components: |
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Depreciation and amortization excluded from cost of product sold | $ | 5.9 | $ | 4.8 | $ | 3.6 | |||||
Depreciation and amortization excluded from direct operating expenses | 115.0 | 109.1 | 103.5 | ||||||||
Depreciation and amortization excluded from selling, general and administrative expenses | 1.6 | 0.4 | 0.5 | ||||||||
Total depreciation and amortization | $ | 122.5 | $ | 114.3 | $ | 107.6 | |||||
(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 is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and amortization), major scheduled turnaround expenses and depreciation and amortization. Each of the components used in this calculation are taken directly from our Consolidated and Combined 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 product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that management believes is important to investors in evaluating the performance of our refineries as a general indication of the amount above our cost of product sold at which we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from our Consolidated and Combined 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 |
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refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance.
(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 impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v) (gain) loss on derivatives, net, (vi) current period settlements on derivative contracts and (vii) expenses associated with the acquisition of Gary-Williams. We present Adjusted EBITDA because it is the starting point for our 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. Management believes 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. Below is a reconciliation of net income (loss) to EBITDA and EBITDA to Adjusted EBITDA for the three months ended December 31, 2014 and the years ended December 31, 2014, 2013 and 2012: |
Three Months Ended December 31, | Year Ended December 31, | ||||||||||||||
2014 | 2014 | 2013 | 2012 | ||||||||||||
(in millions) | |||||||||||||||
(unaudited) | |||||||||||||||
Net income (loss) | $ | (108.5 | ) | $ | 358.7 | $ | 590.4 | $ | 595.3 | ||||||
Add: | |||||||||||||||
Interest expense and other financing costs, net of interest income | 9.6 | 33.9 | 43.7 | 76.2 | |||||||||||
Income tax expense | — | — | — | — | |||||||||||
Depreciation and amortization | 32.6 | 122.5 | 114.3 | 107.6 | |||||||||||
EBITDA | (66.3 | ) | 515.1 | 748.4 | 779.1 | ||||||||||
Add: | |||||||||||||||
FIFO impacts (favorable), unfavorable(a) | 154.6 | 160.8 | (21.3 | ) | 58.4 | ||||||||||
Share-based compensation, non-cash | 0.5 | 2.3 | 9.5 | 18.5 | |||||||||||
Loss on extinguishment of debt | — | — | 26.1 | 37.5 | |||||||||||
Major scheduled turnaround expenses(b) | 1.3 | 6.8 | — | 123.7 | |||||||||||
(Gain) loss on derivatives, net | (14.5 | ) | (185.6 | ) | (57.1 | ) | 285.6 | ||||||||
Current period settlements on derivative contracts(c) | 29.0 | 122.2 | 6.4 | (137.6 | ) | ||||||||||
Expenses associated with the acquisition of Gary-Williams | — | — | — | 11.0 | |||||||||||
Adjusted EBITDA | $ | 104.6 | $ | 621.6 | $ | 712.0 | $ | 1,176.2 | |||||||
(a) | FIFO is our basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. |
(b) | Represents expense associated with certain major scheduled turnaround activities performed at our Coffeyville refinery ($5.5 million in 2014 and $21.2 million in 2012) and Wynnewood refinery ($1.3 million in 2014 and $102.5 million in 2012). |
(c) | Represents the portion of gain (loss) on derivatives, net related to contracts that matured during the respective periods and settled with counterparties. There are no premiums paid or received at the inception of the derivative contracts and upon settlement, there is no cost recovery associated with these contracts. |
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(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 future major scheduled turnaround expenses and, to the extent applicable, (iv) reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner. Available cash for distribution is not a recognized term under GAAP. Available cash for distribution should not be considered in isolation or as an alternative to net income (loss) or operating income (loss), as a measure of operating performance. In addition, available cash for distribution is not presented as, and should not be considered an alternative to cash flows from operations or as a measure of liquidity. Available cash for distribution as reported by the Partnership may not be comparable to similarly titled measures of other entities, thereby limiting its usefulness as a comparative measure. Below is a table reconciling the available cash for distribution for the three months ended December 31, 2014: |
Three Months Ended December 31, 2014 | ||||
(in millions, except per unit data) | ||||
Reconciliation of Adjusted EBITDA to Available cash for distribution | ||||
Adjusted EBITDA | $ | 104.6 | ||
Adjustments: | ||||
Less: | ||||
Cash needs for debt service | (10.0 | ) | ||
Reserves for environmental and maintenance capital expenditures | (31.2 | ) | ||
Reserves for future turnarounds | (8.7 | ) | ||
Available cash for distribution | $ | 54.7 | ||
Available cash for distribution, per unit | $ | 0.37 | ||
Common units outstanding (in thousands) | 147,600 | |||
(7) Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric.
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Coffeyville Refinery Financial Results | |||||||||||
Net sales | $ | 5,755.5 | $ | 5,370.8 | $ | 5,692.4 | |||||
Cost of product sold (exclusive of depreciation and amortization) | 5,254.9 | 4,648.6 | 4,566.0 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 223.6 | 219.4 | 189.1 | ||||||||
Major scheduled turnaround expenses | 5.5 | — | 21.2 | ||||||||
Depreciation and amortization | 73.6 | 70.8 | 69.6 | ||||||||
Gross profit | $ | 197.9 | $ | 432.0 | $ | 846.5 | |||||
Plus: | |||||||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | 229.1 | 219.4 | 210.3 | ||||||||
Depreciation and amortization | 73.6 | 70.8 | 69.6 | ||||||||
Refining margin | $ | 500.6 | $ | 722.2 | $ | 1,126.4 | |||||
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Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars per barrel) | |||||||||||
Coffeyville Refinery Key Operating Statistics | |||||||||||
Per crude oil throughput barrel: | |||||||||||
Refining margin | $ | 11.46 | $ | 17.90 | $ | 26.81 | |||||
Gross profit | $ | 4.53 | $ | 10.71 | $ | 20.15 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 5.24 | $ | 5.44 | $ | 5.01 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 4.73 | $ | 5.00 | $ | 4.66 | |||||
Barrels sold (barrels per day) | 132,791 | 120,166 | 123,418 | ||||||||
Year Ended December 31, | ||||||||||||||
2014 | 2013 | 2012 | ||||||||||||
% | % | % | ||||||||||||
Coffeyville Refinery Throughput and Production Data (bpd) | ||||||||||||||
Throughput: | ||||||||||||||
Sweet | 103,018 | 80.0 | 90,818 | 77.1 | 91,580 | 74.3 | ||||||||
Medium | 1,222 | 1.0 | 453 | 0.4 | 5,601 | 4.6 | ||||||||
Heavy sour | 15,464 | 12.0 | 19,270 | 16.3 | 17,608 | 14.3 | ||||||||
Total crude oil throughput | 119,704 | 93.0 | 110,541 | 93.8 | 114,789 | 93.2 | ||||||||
All other feedstocks and blendstocks | 9,047 | 7.0 | 7,253 | 6.2 | 8,412 | 6.8 | ||||||||
Total throughput | 128,751 | 100.0 | 117,794 | 100.0 | 123,201 | 100.0 | ||||||||
Production: | ||||||||||||||
Gasoline | 64,002 | 48.6 | 56,262 | 46.8 | 61,998 | 49.6 | ||||||||
Distillate | 56,381 | 42.8 | 50,353 | 41.9 | 52,429 | 41.9 | ||||||||
Other (excluding internally produced fuel) | 11,314 | 8.6 | 13,499 | 11.3 | 10,629 | 8.5 | ||||||||
Total refining production (excluding internally produced fuel) | 131,697 | 100.0 | 120,114 | 100.0 | 125,056 | 100.0 | ||||||||
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Wynnewood Refinery Financial Results | |||||||||||
Net sales | $ | 3,069.8 | $ | 3,308.4 | $ | 2,587.6 | |||||
Cost of product sold (exclusive of depreciation and amortization) | 2,758.1 | 2,877.5 | 2,101.4 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 185.5 | 142.4 | 113.7 | ||||||||
Major scheduled turnaround expenses | 1.3 | — | 102.5 | ||||||||
Depreciation and amortization | 41.8 | 38.6 | 34.5 | ||||||||
Gross profit | $ | 83.1 | $ | 249.9 | $ | 235.5 | |||||
Plus: | |||||||||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | 186.8 | 142.4 | 216.2 | ||||||||
Depreciation and amortization | 41.8 | 38.6 | 34.5 | ||||||||
Refining margin | $ | 311.7 | $ | 430.9 | $ | 486.2 | |||||
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Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(dollars per barrel) | |||||||||||
Wynnewood Refinery Key Operating Statistics | |||||||||||
Per crude oil throughput barrel: | |||||||||||
Refining margin | $ | 11.11 | $ | 15.33 | $ | 24.34 | |||||
Gross profit | $ | 2.96 | $ | 8.89 | $ | 11.79 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) | $ | 6.66 | $ | 5.06 | $ | 10.83 | |||||
Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold | $ | 6.66 | $ | 5.00 | $ | 9.96 | |||||
Barrels sold (barrels per day) | 76,878 | 77,976 | 59,282 | ||||||||
Year Ended December 31, | ||||||||||||||
2014 | 2013 | 2012 | ||||||||||||
% | % | % | ||||||||||||
Wynnewood Refinery Throughput and Production Data (bpd) | ||||||||||||||
Throughput: | ||||||||||||||
Sweet | 76,041 | 96.2 | 58,329 | 73.0 | 38,834 | 68.2 | ||||||||
Medium | 800 | 1.0 | 18,698 | 23.4 | 15,733 | 27.6 | ||||||||
Heavy sour | — | — | — | — | — | — | ||||||||
Total crude oil throughput | 76,841 | 97.2 | 77,027 | 96.4 | 54,567 | 95.8 | ||||||||
All other feedstocks and blendstocks | 2,237 | 2.8 | 2,868 | 3.6 | 2,379 | 4.2 | ||||||||
Total throughput | 79,078 | 100.0 | 79,895 | 100.0 | 56,946 | 100.0 | ||||||||
Production: | ||||||||||||||
Gasoline | 38,273 | 49.5 | 38,299 | 49.0 | 27,789 | 50.6 | ||||||||
Distillate | 31,258 | 40.4 | 31,736 | 40.6 | 20,375 | 37.2 | ||||||||
Other (excluding internally produced fuel) | 7,835 | 10.1 | 8,118 | 10.4 | 6,633 | 12.2 | ||||||||
Total refining production (excluding internally produced fuel) | 77,366 | 100.0 | 78,153 | 100.0 | 54,797 | 100.0 | ||||||||
Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Net Sales. Net sales were $8,829.7 million for the year ended December 31, 2014, compared to $8,683.5 million for the year ended December 31, 2013. The increase of $146.2 million was primarily the result of higher overall sales volumes largely offset by lower sales prices for gasoline and distillates. Overall sales volume increased 8.4% for the year ended December 31, 2014 compared to the year ended December 31, 2013. Current year sales volumes were impacted by reduced crude oil throughput and production as a result of our Coffeyville refinery shutdown following the isomerization unit fire during the third quarter of 2014 and the FCCU outage at our Wynnewood refinery during the fourth quarter of 2014. Sales volumes for 2013 were impacted by downtime associated with the FCCU outage at our Coffeyville refinery in the third quarter of 2013. Our average sales price per gallon for the year ended December 31, 2014 for gasoline of $2.53 and distillate of $2.81 each decreased by approximately 7.0% as compared to the year ended December 31, 2013.
Year Ended December 31, 2014 | Year Ended December 31, 2013 | Total Variance | ||||||||||||||||||||||||||||||||||
Volume(1) | $ per barrel | Sales $(2) | Volume(1) | $ per barrel | Sales $(2) | Volume(1) | Sales $(2) | Price Variance | Volume Variance | |||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||
Gasoline | 40.3 | $ | 106.21 | $ | 4,282.2 | 37.8 | $ | 114.29 | $ | 4,330.0 | 2.5 | $ | (47.8 | ) | $ | (325.9 | ) | $ | 278.1 | |||||||||||||||||
Distillate | 34.9 | $ | 118.09 | $ | 4,122.3 | 30.6 | $ | 126.79 | $ | 3,880.6 | 4.3 | $ | 241.7 | $ | (303.5 | ) | $ | 545.2 | ||||||||||||||||||
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(1) | Barrels in millions |
(2) | Sales dollars in million |
Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $8,013.4 million for the year ended December 31, 2014, compared to $7,526.7 million for the year ended December 31, 2013. The increase of $486.7 million was primarily the result of an increase in the cost of consumed crude oil and refined fuels purchased for resale. The increase in consumed crude oil cost was due to a 4.8% increase in consumed volumes, which was partially offset by lower crude oil prices. Our average cost per barrel of crude oil consumed for the year ended December 31, 2014 was $92.57 compared to $95.05 for the year ended December 31, 2013, a decrease of approximately 2.6%. Sales volumes of refined fuels increased by approximately 8.4%. The impact of FIFO accounting also impacted cost of product sold 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, 2014 and 2013, we had an unfavorable FIFO inventory impact of $160.8 million compared to a favorable FIFO inventory impact of $21.3 million, respectively. The major factor contributing to the unfavorable FIFO impact for the year ended December 31, 2014 was the decline in the market price of WTI from $95.44 at the beginning of 2014 to $53.27 on December 31, 2014. The FIFO inventory impact for 2014 includes a lower of cost or market write-down of $36.8 million, which was recorded in the fourth quarter as a result of the significant decline in the market price of crude oil.
Refining margin per barrel of crude oil throughput decreased to $11.38 for the year ended December 31, 2014 from $16.90 for the year ended December 31, 2013. Refining margin adjusted for FIFO impact was $13.62 per crude oil throughput barrel for the year ended December 31, 2014, as compared to $16.59 per crude oil throughput barrel for the year ended December 31, 2013. Gross profit per barrel decreased to $3.87 for the year ended December 31, 2014, as compared to gross profit per barrel of $9.94 in the equivalent period in 2013. The decrease in refining margin and gross profit per barrel was primarily due to a decrease in sales prices for gasoline and distillate. Our average sales price for both gasoline and distillates declined approximately 7.0% for the year ended December 31, 2014 as compared to the same period last year.
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 $416.0 million for the year ended December 31, 2014, compared to direct operating expenses of $361.7 million for the year ended December 31, 2013. The increase of $54.3 million was primarily the result of the increase in expenses associated with energy and utility costs ($18.1 million), repairs and maintenance ($10.2 million), labor ($8.9 million), certain turnaround activities performed at our Coffeyville and Wynnewood refineries ($6.8 million), production chemicals ($4.7 million) and rental costs ($4.5 million). The increase in energy and utility costs was primarily due to a 27.3% increase in natural gas cost per unit and a 12.5% increase in natural gas consumption. The increase in repairs and maintenance and turnaround costs was due to opportunity maintenance and turnaround activities performed at our Coffeyville refinery during the shutdown following the isomerization fire in the third quarter of 2014 and during the FCCU outage at our Wynnewood refinery during the fourth quarter of 2014. Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2014 increased to $5.80 per barrel as compared to $5.28 per barrel for the year ended December 31, 2013. 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 $70.6 million for the year ended December 31, 2014, as compared to $77.8 million for the year ended December 31, 2013. The decrease of $7.2 million over the comparable period was primarily the result of decreased share-based compensation costs and decreased allocated personnel and consulting costs.
Operating Income. Operating income was $207.2 million for the year ended December 31, 2014, as compared to operating income of $603.0 million for the year ended December 31, 2013. The decrease of $395.8 million was the result of a decrease in the refining margin ($340.5 million) and increases in direct operating expenses ($54.3 million) and depreciation and amortization ($8.2 million), partially offset by a decrease in selling, general and administrative expenses ($7.2 million).
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Interest Expense. Interest expense for the year ended December 31, 2014 was $34.2 million as compared to interest expense of $44.1 million for the year ended December 31, 2013. The decrease of $9.9 million resulted primarily from interest expense on the outstanding 2022 Notes (as defined below) for the year ended December 31, 2014 as compared to interest expense incurred during the year ended December 31, 2013 related to both the Second Lien Notes (prior to their extinguishment in the first quarter of 2013) and the 2022 Notes and higher capitalized interest for the year ended December 31, 2014.
Gain on Derivatives, net. For the year ended December 31, 2014, we recorded a $185.6 million net gain on derivatives compared to a $57.1 million net gain on derivatives for the year ended December 31, 2013. 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.
Loss on Extinguishment of Debt. For the year ended December 31, 2013, we incurred a $26.1 million loss on extinguishment of debt. The loss on the extinguishment of debt was the result of the extinguishment of the Second Lien Notes and included amounts related to the premium paid, the write-off of previously deferred financing costs and the write-off of the unamortized original issuance discount.
Net Income. For the year ended December 31, 2014, net income was $358.7 million as compared to net income of $590.4 million for the year ended December 31, 2013, a decrease of $231.7 million.
Year Ended December 31, 2013 Compared to Year Ended December 31, 2012
Net Sales. Net sales were $8,683.5 million for the year ended December 31, 2013, compared to $8,281.7 million for the year ended December 31, 2012. The increase of $401.8 million was the result of higher overall sales volumes, which was partially offset by lower product prices. The higher sales volume was due to the downtime associated with completion of the second phase of our Coffeyville refinery's turnaround in the first quarter of 2012 and our Wynnewood refinery's turnaround in the fourth quarter of 2012, which decreased products available for sale in the prior year. Current year sales volumes were impacted by the downtime associated with the FCCU outage at our Coffeyville refinery during the third quarter of 2013. Our average sales price per gallon for the year ended December 31, 2013 for gasoline of $2.72 and distillate of $3.02 decreased by approximately 4.9% and 1.9%, respectively, as compared to the year ended December 31, 2012.
Year Ended December 31, 2013 | Year Ended December 31, 2012 | Total Variance | ||||||||||||||||||||||||||||||||||
Volume(1) | $ per barrel | Sales $(2) | Volume(1) | $ per barrel | Sales $(2) | Volume(1) | Sales $(2) | Price Variance | Volume Variance | |||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||
Gasoline | 37.8 | $ | 114.29 | $ | 4,330.0 | 35.6 | $ | 120.14 | $ | 4,283.1 | 2.2 | $ | 46.9 | $ | (221.8 | ) | $ | 268.7 | ||||||||||||||||||
Distillate | 30.6 | $ | 126.79 | $ | 3,880.6 | 27.5 | $ | 129.51 | $ | 3,563.9 | 3.1 | $ | 316.7 | $ | (83.4 | ) | $ | 400.1 | ||||||||||||||||||
(1) | Barrels in millions |
(2) | Sales dollars in million |
Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, RINs and transportation and distribution costs. Cost of product sold (exclusive of depreciation and amortization) was $7,526.7 million for the year ended December 31, 2013, compared to $6,667.5 million for the year ended December 31, 2012. The increase of $859.2 million was primarily the result of an increase in the cost of consumed crude oil and the cost of RINs. The increase in consumed crude oil cost was due to an increase in consumed volumes and crude oil prices. Our average cost per barrel of crude oil consumed for the year ended December 31, 2013 was $95.05 compared to $91.69 for the year ended December 31, 2012, an increase of approximately 3.7%. Consumed crude volume increased by approximately 10.5% primarily due to the downtime associated with our Wynnewood refinery turnaround in the fourth quarter of the prior year. The impact of FIFO accounting also impacted cost of product sold 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, 2013 and 2012, we had a favorable FIFO inventory impact of $21.3 million compared to an unfavorable FIFO inventory impact of $58.4 million, respectively.
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Refining margin per barrel of crude oil throughput decreased to $16.90 for the year ended December 31, 2013 from $26.04 for the year ended December 31, 2012. Refining margin adjusted for FIFO impact was $16.59 per barrel of crude oil throughput for the year ended December 31, 2013, as compared to $26.98 per crude oil throughput barrel for the year ended December 31, 2012. Gross profit per barrel decreased to $9.94 for the year ended December 31, 2013, as compared to gross profit per barrel of $17.42 in the equivalent period in 2012. The decrease in refining margin and gross profit per barrel was primarily due to a decrease in sales prices of gasoline and distillates and an increase in our per barrel cost of consumed crude oil. Consumed crude oil costs increased due primarily to a 4.1% increase in WTI for the year ended December 31, 2013 over the year ended December 31, 2012.
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 (exclusive of depreciation and amortization) were $361.7 million for the year ended December 31, 2013, compared to direct operating expenses and major scheduled turnaround expenses of $426.5 million for the year ended December 31, 2012. The decrease of $64.8 million was primarily the result of the decrease in expenses associated with major scheduled turnaround ($123.7 million). Our Coffeyville refinery completed the second phase of its planned turnaround in the first quarter of 2012 and our Wynnewood refinery completed its planned turnaround in the fourth quarter of 2012. The decrease was partially offset by an increase in general repairs and maintenance ($39.4 million), energy and utility costs ($13.4 million) and labor ($11.4 million). The increase in repairs and maintenance were primarily due to the FCCU outage and repair at our Coffeyville refinery during the third quarter of 2013. Direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2013 decreased to $5.28 per barrel as compared to $6.88 per barrel for the year ended December 31, 2012. The decrease in the direct operating expenses per barrel of crude oil throughput was a function of lower 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 $77.8 million for the year ended December 31, 2013, as compared to $86.2 million for the year ended December 31, 2012. The decrease of $8.4 million over the comparable period was primarily the result of a decrease in allocated share-based compensation expenses from CVR Energy, primarily related to the modification of CVR Energy's restricted shares to liability-classified restricted stock unit awards during the year ended December 31, 2012 and a decrease in integration costs related to the acquisition of the Wynnewood refinery, partially offset by increases in outside service costs and personnel expenses.
Operating Income. Operating income was $603.0 million for the year ended December 31, 2013, as compared to operating income of $993.9 million for the year ended December 31, 2012. The decrease of $390.9 million was the result of a decrease in the refining margin ($457.4 million) and an increase in depreciation and amortization ($6.7 million), partially offset by decreases in direct operating expenses ($64.8 million) and selling, general and administrative expenses ($8.4 million).
Interest Expense. Interest expense for the year ended December 31, 2013 was $44.1 million as compared to interest expense of $76.2 million for the year ended December 31, 2012. The decrease of $32.1 million resulted primarily from lower interest expense on the outstanding 2022 Notes for the year ended December 31, 2013 as compared to interest expense incurred during the year ended December 31, 2012 related to the First Lien Notes prior to their extinguishment in the fourth quarter of 2012, the Second Lien Notes and the 2022 Notes issued in October 2012.
Gain (Loss) on Derivatives, net. For the year ended December 31, 2013, we recorded a $57.1 million net gain on derivatives compared to a $285.6 million net loss on derivatives for the year ended December 31, 2012. 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.
Loss on Extinguishment of Debt. For the year ended December 31, 2013, we incurred a $26.1 million loss on extinguishment of debt compared to $37.5 million for the year ended December 31, 2012. In 2013, the loss on the extinguishment of debt was the result of the extinguishment of the Second Lien Notes in the first quarter. In 2012, the loss on the extinguishment of debt was the result of the extinguishment of the First Lien Notes ($33.4 million) and the write-off of deferred financing costs ($4.1 million) associated with the amendment of the then-existing ABL credit facility, both of which occurred during the fourth quarter.
Net Income. For the year ended December 31, 2013, net income was $590.4 million as compared to net income of $595.3 million for the year ended December 31, 2012, a decrease of $4.9 million.
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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. Prior to December 31, 2012, CRLLC historically used a centralized approach to cash management and provided cash as needed to support our operations and retained excess cash earned by our operations. As a result, amounts owed to or from CRLLC in our historical combined financial statements have been reflected as a component of divisional equity prior to CRLLC's contribution of the petroleum business to us on December 31, 2012. Beginning January 1, 2013, we have operated with an independent capital structure.
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 $250.0 million intercompany credit facility, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve 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 liquidity was enhanced during the first quarter of 2013 by the proceeds from our Initial Public Offering of approximately $653.6 million, after deducting underwriting discounts and commissions and offering expenses. Approximately $253.0 million of the net proceeds were used to redeem all of the outstanding Second Lien Notes, $160.0 million was used to fund certain maintenance and environmental capital expenditures through 2014, $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery in the fourth quarter of 2012, $85.1 million was distributed to CRLLC and the remaining proceeds have been used for general corporate purposes. Prior to the closing of the Initial Public Offering, we distributed approximately $150.0 million of cash on hand to CRLLC.
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, 2014, we had cash and cash equivalents of $370.2 million. Working capital at December 31, 2014 was $504.5 million, consisting of $888.5 million in current assets and $384.0 million in current liabilities. Working capital at December 31, 2013 was $656.9 million, consisting of $1,082.6 million in current assets and $425.7 million in current liabilities.
The Amended and Restated ABL Credit Facility provides us with borrowing availability of up to $400.0 million with an incremental facility, subject to compliance with a borrowing base. The Amended and Restated ABL Credit Facility is scheduled to mature on December 20, 2017. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Partnership and the credit facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swing line loans and 90% of the total facility commitment for letters of credit. The intercompany credit facility provides us with borrowing availability of up to $250.0 million effective October 29, 2014.
As of February 17, 2015, we had $372.4 million available under the Amended and Restated ABL Credit Facility and $218.5 million available under the intercompany credit facility. Additionally, as of February 17, 2015, we had cash and cash equivalents of approximately $485.0 million.
Borrowing Activities
2022 Notes. On October 23, 2012, Refining LLC and Coffeyville Finance Inc. ("Coffeyville Finance") issued $500.0 million aggregate principal amount of the 2022 Notes. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. The remaining proceeds from the offering were used to fund a completed and settled redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.
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Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of these transactions, a loss on extinguishment of debt of $33.4 million was recorded in the Consolidated and Combined Statements of Operations in the fourth quarter of 2012, which includes the total premiums paid of $31.6 million and the write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million.
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. As of December 31, 2014, the 2022 Notes had an aggregate principal balance and a net carrying value of $500.0 million.
The 2022 Notes were issued by Refining LLC and Coffeyville Finance and are 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. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, CVR Partners and Coffeyville Nitrogen Fertilizers ("CRNF") are not guarantors. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes were no longer secured as of and after January 23, 2013.
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 our obligations contained in the registration rights agreement entered into in connection with the issuance of the 2022 Notes. We incurred approximately $0.4 million of debt registration costs related to the registration and exchange offering 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 bear interest at a rate of 6.5% per annum and 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, 2015, up to 35% of the 2022 Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 106.5% of the principal amount thereof, plus any accrued and unpaid interest. Prior to November 1, 2017, some or all of the 2022 Notes may be 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 (1) 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), (2) liquidation or dissolution of Refining LLC, or (3) any person, other than a qualifying owner, directly or indirectly acquiring 50% of the voting stock of Refining LLC.
The indenture governing the 2022 Notes imposes covenants that restrict our ability to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the 2022 Notes are rated investment grade by both Standard & Poor's Ratings Services 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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The indenture governing the 2022 Notes prohibits us from making distributions to unitholders if any default or event of default (as defined in the indenture) exists. In addition, the indenture limits our 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, we will generally be permitted to make restricted payments, including distributions to our unitholders, without substantive restriction. If the fixed charge coverage ratio is less than 2.5 to 1.0, we will generally be permitted to make restricted payments, including distributions to our unitholders, up to an aggregate $100.0 million basket plus certain other amounts referred to as "incremental funds" under the indenture. We were in compliance with the covenants as of December 31, 2014, and the ratio was satisfied (not less than 2.5 to 1.0).
Amended and Restated Asset Based (ABL) Credit Facility. On December 20, 2012, we entered into the Amended and Restated ABL Credit Facility with Wells Fargo, as administrative agent and collateral agent for a syndicate of lenders. The Amended and Restated ABL Credit Facility replaced CRLLC's prior ABL credit facility. Under the Amended and Restated ABL Credit Facility, we assumed CRLLC's position as borrower and its obligations under the Amended and Restated ABL Credit Facility upon the closing of the Initial Public Offering on January 23, 2013. 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 swing line loans of $360.0 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 and projected excess availability at all times during the three-month period following the distribution exceeds 20% of the lesser of the borrowing base and the total commitments; provided, that, if excess availability and projected excess availability for the six-month period following the distribution is greater than 25% at all times, then the following condition in clause (iii) will not apply, and (iii) the fixed charge coverage ratio for the immediately preceding twelve-month period shall be equal to or greater than 1.10 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) 1.75% for LIBOR borrowings and (b) 0.75% 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) 2.00% for LIBOR borrowings and (b) 1.00% 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) 0.40% 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) 0.30% 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. We are 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).
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 subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined under the facility. We were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of December 31, 2014.
Intercompany Credit Facility. On January 23, 2013, prior to the closing of the Initial Public Offering, 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. The intercompany credit facility is for a term of six years and bears interest at a rate of LIBOR plus 3% per annum. 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.
The intercompany credit facility contains covenants that require us to, among other things, notify CRLLC of the occurrence of any default or event of default and provide CRLLC with information in respect of our business and financial
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status as it may reasonably require, including, but not limited to, copies of our unaudited quarterly financial statements and our audited annual financial statements. We were in compliance with the covenants of the intercompany credit facility as of December 31, 2014.
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 our general partner, or (ii) CRLLC and its affiliates no longer owning a majority of our equity interests. As of December 31, 2014, we had borrowings of $31.5 million outstanding and $218.5 million available under the intercompany credit facility.
Old Notes. On April 6, 2010, CRLLC and Coffeyville Finance completed the private offering of $275.0 million aggregate principal amount of First Lien Notes and $225.0 million aggregate principal amount of Second Lien Notes. The 2010 First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, the issuers made a voluntary unscheduled principal payment of $27.5 million on the First Lien Notes. On May 16, 2011, we repurchased $2.7 million of the Notes at a purchase price of 103% of the outstanding principal amount. On December 15, 2011, the issuers issued an additional $200.0 million aggregate principal amount of First Lien Notes to partially fund the Wynnewood Acquisition. The additional First Lien Notes were issued at 105% of their principal amount. As the Old Notes were incurred for the benefit of our operations, all debt and associated costs have been allocated to us. On October 23, 2012, we repurchased approximately $323.0 million of the First Lien Notes pursuant to a tender offer and on November 23, 2012, we redeemed the remaining $124.1 million of outstanding First Lien Notes. On January 23, 2013, we used a portion of the proceeds from the Initial Public Offering to satisfy and discharge the indenture governing the Second Lien Notes and all have been redeemed.
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 2014 and current estimated capital expenditures in 2015 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, | |||||||||||
2014 Actual | 2015 Estimate | ||||||||||
Low | High | ||||||||||
(in millions) | |||||||||||
Coffeyville refinery: | |||||||||||
Maintenance | $ | 74.8 | $ | 88.0 | $ | 98.0 | |||||
Growth | 5.5 | 82.0 | 92.0 | ||||||||
Coffeyville refinery total capital excluding major scheduled turnaround expenses | 80.3 | 170.0 | 190.0 | ||||||||
Wynnewood refinery | |||||||||||
Maintenance | 58.5 | 50.0 | 58.0 | ||||||||
Growth | 38.9 | 10.0 | 12.0 | ||||||||
Wynnewood refinery total capital excluding major scheduled turnaround expenses | 97.4 | 60.0 | 70.0 | ||||||||
Other Petroleum: | |||||||||||
Maintenance | 7.0 | 12.0 | 14.0 | ||||||||
Growth | 6.6 | 8.0 | 11.0 | ||||||||
Other petroleum total capital excluding major scheduled turnaround expenses | 13.6 | 20.0 | 25.0 | ||||||||
Total capital spending excluding major scheduled turnaround expenses | $ | 191.3 | $ | 250.0 | $ | 285.0 | |||||
In October 2014, the board of directors of the general partner of the Partnership approved the construction of a hydrogen plant at our Coffeyville refinery. The hydrogen plant will increase the overall plant liquid volume recovery and provide
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additional hydrogen that is needed for environmental compliance. The estimated cost of this project, excluding capitalized interest, is approximately $122.5 million with an anticipated completion date in the second quarter of 2016. The project will be financed by the expanded $250.0 million intercompany credit facility. For the year ended December 31, 2014, the Partnership incurred costs of approximately $9.8 million, excluding capitalized interest, for the hydrogen plant.
Our estimated capital expenditures are subject to change due to unanticipated increases/decreases in the cost, scope and completion time for our capital projects. For example, we may experience increases/decreases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refineries.
Cash Flows
The following table sets forth our consolidated and combined cash flows for the periods indicated below:
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Net cash provided by (used in): | |||||||||||
Operating activities | $ | 715.8 | $ | 601.0 | $ | 917.3 | |||||
Investing activities | (191.2 | ) | (204.4 | ) | (119.8 | ) | |||||
Financing activities | (434.2 | ) | (269.9 | ) | (647.1 | ) | |||||
Net increase in cash and cash equivalents | $ | 90.4 | $ | 126.7 | $ | 150.4 | |||||
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.
Cash Flows Provided by Operating Activities
Net cash flows provided by operating activities for the year ended December 31, 2014 were approximately $715.8 million. The positive cash flow from operating activities generated over this period was primarily driven by $358.7 million of net income and favorable impacts to trade working capital and other working capital. Trade working capital for the year ended December 31, 2014 resulted in a net cash inflow of $247.2 million, which was attributable to decreases in inventory ($200.3 million) and accounts receivable ($105.4 million), partially offset by a decrease in accounts payable ($58.5 million). Each of the cash flow impacts in trade working capital were largely attributable to the crude oil pricing environment and significant reduction in pricing during the fourth quarter of 2014. The favorable trade working capital impacts for inventory and accounts receivable resulted from higher product prices and crude oil prices at the end of 2013 as compared to the end of 2014. These favorable trade working capital impacts were partially offset by the decrease in accounts payable as a result of payables related to crude purchases based on higher crude oil prices at the end of 2013 as compared to the end of 2014. Other working capital activities resulted in net cash inflow of $40.5 million, which was primarily related to an increase in accrued expenses and other current liabilities ($36.6 million). The increase in accrued expenses and other current liabilities was primarily attributable to an increase in accruals related to the biofuel blending obligation as a result of higher RINs prices as of December 31, 2014 as compared to the prior year.
Net cash flows provided by operating activities for the year ended December 31, 2013 were approximately $601.0 million. The positive cash flow from operating activities generated over this period was primarily driven by $590.4 million of net income. Trade working capital for the year ended December 31, 2013 resulted in a net cash outflow of $42.4 million, which was primarily attributable to an increase in accounts receivable ($29.3 million) and a decrease in accounts payable ($18.9 million). The increase in accounts receivable primarily resulted from increased sales volumes as compared to the end of 2012 due to the turnaround at the Wynnewood refinery completed in the fourth quarter of 2012. The decrease in accounts payable was largely the result of a decrease in amounts payable related to the turnaround completed at the Wynnewood refinery in the fourth quarter of 2012, partially offset by increased payables for lease crude purchases due to increased crude gathering capacity and timing of payments. Other working capital activities resulted in a net cash outflow of $48.8 million, which was primarily related to an increase in prepaid expenses and other current assets ($47.8 million). The increase in prepaid expenses and other current assets was primarily due to the timing of settlements associated with our crude oil intermediation agreement and increases in prepaid insurance.
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Net cash flows provided by operating activities for the year ended December 31, 2012 were approximately $917.3 million. The positive cash flow from operating activities generated over this period was primarily driven by $595.3 million of net income. The positive net income was primarily due to the operating margins for the period, which resulted in $993.9 million of operating income. Trade working capital for the year ended December 31, 2012 resulted in a net cash outflow of $17.8 million, which was attributable to a decrease in accounts payable ($101.3 million) and an increase in accounts receivable ($30.4 million), partially offset by a decrease in inventory ($113.9 million). The decrease in accounts payable was primarily the result of the timing of payments for trade payables and lease crude purchasing, partially offset by increased payables related to the Wynnewood refinery turnaround in the fourth quarter of 2012. The increase in accounts receivable was primarily the result of increased sales volumes for distillates, natural gas and asphalt in the fourth quarter of 2012. The decrease in inventory was primarily the result of decreases related to in-process inventory volumes and decreased prices for gasoline, distillates and crude oil. Other working capital activities resulted in a net cash inflow of approximately $19.9 million primarily related to a decrease in prepaid expenses and other current assets ($15.4 million) and an increase in other current liabilities ($4.4 million). The decrease in prepaid expenses and other current assets was primarily the result of a decrease in the working capital receivable associated with the purchase accounting for the Wynnewood Acquisition in December 2011. The increase in other current liabilities was primarily related to increased personnel accruals.
Cash Flows Used In Investing Activities
Net cash used in investing activities for the year ended December 31, 2014 was $191.2 million compared to $204.4 million for the year ended December 31, 2013. The decrease in cash used in investing activities was the result of a $13.2 million decrease in capital expenditures for the year ended December 31, 2014 compared to the year ended December 31, 2013. The decrease primarily resulted from a $32.8 million decrease in capital expenditures at the Wynnewood refinery, partially offset by a $24.1 million increase in capital expenditures at the Coffeyville refinery.
Net cash used in investing activities for the year ended December 31, 2013 was $204.4 million compared to $119.8 million for the year ended December 31, 2012. The increase in cash used in investing activities was the result of a $84.3 million increase in capital expenditures for the year ended December 31, 2013 compared to the year ended December 31, 2012 largely resulting from incremental spending at the Wynnewood refinery.
Cash Flows Used in Financing Activities
Net cash used in financing activities for the year ended December 31, 2014 was approximately $434.2 million compared to $269.9 million for the year ended December 31, 2013. The net cash used in financing activities for the year ended December 31, 2014 was primarily attributable to distributions to our common unitholders of $432.5 million (including $313.4 million to affiliates). The net cash used in financing activities for the year ended December 31, 2013 was primarily attributable to payments to extinguish the Second Lien Notes of $243.4 million, distributions to affiliates of $235.1 million and distributions to our common unitholders of $476.7 million (including $378.7 million to affiliates), partially offset by proceeds from the initial public offering of $655.7 million.
Net cash used in financing activities for the year ended December 31, 2013 was approximately $269.9 million compared to $647.1 million for the year ended December 31, 2012. Prior to December 31, 2012, CRLLC provided cash as necessary to support our operations and retained excess cash earned by our operations. Cash received or paid by CRLLC on our behalf has been recorded as net contributions from or net distributions to parent as a component of divisional equity which are reflected as a financing activity in the Consolidated and Combined Statements of Cash Flows. Net cash used in financing activities for the year ended December 31, 2012 was primarily attributable to net distributions to parent of $651.6 million, payments of $478.7 million to extinguish the First Lien Notes and payment of financing costs of approximately $12.8 million. These cash uses were offset by the net proceeds received of $491.3 million from the issuance of the 2022 Notes.
As of and for the year ended December 31, 2014, there were no borrowings or repayments under the Amended and Restated ABL Credit Facility. As of December 31, 2014, the Partnership had borrowings of $31.5 million outstanding under the intercompany credit facility.
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Contractual Obligations
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, 2014 relating to long-term debt outstanding on that date, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the five-year period following December 31, 2014 and thereafter.
Payments Due by Period | |||||||||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | 2019 | Thereafter | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||||||||
Contractual Obligations | |||||||||||||||||||||||||||
Long-term debt(1) | $ | 531.5 | $ | — | $ | — | $ | — | $ | — | $ | 31.5 | $ | 500.0 | |||||||||||||
Operating leases(2) | 3.4 | 1.5 | 1.1 | 0.3 | 0.1 | 0.1 | 0.3 | ||||||||||||||||||||
Capital lease obligations(3) | 49.9 | 1.4 | 1.6 | 1.9 | 2.1 | 2.3 | 40.6 | ||||||||||||||||||||
Unconditional purchase obligations(4) | 1,237.2 | 113.8 | 104.0 | 102.4 | 101.6 | 101.0 | 714.4 | ||||||||||||||||||||
Environmental liabilities(5) | 1.2 | 0.2 | 0.1 | 0.1 | 0.1 | 0.1 | 0.6 | ||||||||||||||||||||
Interest payments(6) | 310.4 | 38.5 | 38.3 | 38.1 | 38.0 | 36.8 | 120.7 | ||||||||||||||||||||
Total | $ | 2,133.6 | $ | 155.4 | $ | 145.1 | $ | 142.8 | $ | 141.9 | $ | 171.8 | $ | 1,376.6 | |||||||||||||
Other Commercial Commitments | |||||||||||||||||||||||||||
Standby letters of credit(7) | $ | 27.3 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
(1) | Consists of the 2022 Notes and borrowings outstanding on the intercompany credit facility as of December 31, 2014. |
(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 $799.6 million payable ratably over sixteen 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, 2014, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011. |
(5) | Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. We also are required to make payments with respect to other environmental liabilities, which are not contractual obligations but which would be necessary for our continued operations. See "Business — Environmental Matters." |
(6) | Interest payments are based on stated interest rates for our long-term debt outstanding and interest payments for the capital lease obligation as of December 31, 2014. |
(7) | Standby letters of credit issued against the Amended and Restated ABL Credit Facility include $0.2 million of letters of credit issued in connection with environmental liabilities, $26.3 million in letters of credit to secure transportation services for crude oil and a $0.8 million letter of credit issued to guarantee a portion of our insurance policy. |
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
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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
In May 2014, the Financial Accounting Standards Board ("FASB") issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which 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. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The standard is effective for interim and annual periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. We have not yet selected a transition method and are currently evaluating the standard and the impact on our consolidated financial statements and footnote disclosures.
Critical Accounting Policies
We prepare our consolidated and combined 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 financial statements included elsewhere in this Report. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.
Long-Lived Assets
We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we estimate what we believe are their reasonable useful lives. We account for impairment of long-lived assets in accordance with ASC Topic 360, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets ("ASC 360"). In accordance with ASC 360, we review long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.
Allocation of Costs
Prior to the contribution of Refining LLC to us and entering into the services agreement with CVR Energy on December 31, 2012, certain expenses incurred by CVR Energy and its affiliates were only indirectly attributable to our ownership of the refining and related logistics assets of CRLLC. Accordingly, the consolidated and combined financial statements included elsewhere in this Report have been prepared in accordance with SAB Topic 1-B, as more fully explained in Item 8, Note 2 ("Basis of Presentation") to our audited consolidated and combined financial statements. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting and legal services, and other general and administrative expenses. CVR Energy has allocated general and administrative expenses to us based on allocation methodologies that management considers reasonable and result in an allocation of the cost of doing business borne by CVR Energy and CRLLC on our behalf; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.
Our Consolidated and Combined Statements of Operations for the year ended December 31, 2012 reflects all of the expenses that CRLLC and CVR Energy incurred on our behalf. For the years ended December 31, 2014 and 2013, amounts
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incurred by CVR Energy and its affiliates on our behalf have been governed and billed in accordance with the services agreement entered into between us and CVR Energy on December 31, 2012. See Item 8, Note 15 ("Related Party Transactions") to our audited consolidated and combined financial statements for further discussion of expenses incurred under the services agreement. Our consolidated and combined financial statements therefore include certain expenses incurred by our parent which may include, but are not necessarily limited to, the following:
• | Officer and employee salaries and share-based compensation; |
• | Rent or depreciation; |
• | Advertising; |
• | Accounting, tax, legal and information technology services; |
• | Other selling, general and administrative expenses; |
• | Costs for defined contribution plans, medical and other employee benefits; and |
• | Financing costs, including interest, and losses on extinguishment of debt. |
Selling, general and administrative expense allocations were based primarily on the nature of the expense incurred, with the exception of compensation and compensation related expenses. Compensation expenses, including share-based compensation, are allocated to CVR Refining based upon percentages determined by management to be reasonable and in line with the nature of an individual's roles and responsibilities. Allocations related to share-based compensation are more fully described in Item 8, Note 4 ("Share-Based Compensation"). If shared costs rise or the method by which shared costs are allocated changes, additional selling general and administrative expenses could be allocated to us, which could be material.
Derivative Instruments and Fair Value of Financial Instruments
We use 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 ("ASC 815"), 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. We recorded net gains (losses) from derivative instruments of $185.6 million, $57.1 million and $(285.6) million for the years ended December 31, 2014, 2013 and 2012, respectively.
Share-Based Compensation
We record share-based compensation related to the CVR Refining LTIP, and we have been allocated share-based compensation expense from CVR Energy and CRLLC. We 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. Total share-based compensation expense for the years ended December 31, 2014, 2013 and 2012 was $8.0 million, $11.6 million and $18.5 million, respectively.
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 and interest rates. None of our market risk sensitive instruments are held for trading.
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
75
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.
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, 2014, we had no open commodity positions. At December 31, 2014, our account balance maintained at the third-party clearing house
76
totaled approximately $3.1 million, which is reflected on the Consolidated Balance Sheets in cash and cash equivalents. NYMEX transactions conducted for the year ended December 31, 2014 resulted in gain (loss) on derivatives, net of approximately $0.3 million.
In addition, we enter into commodity contracts in order to fix the margin on a portion of future production. 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 and Combined Statements of Operations. At December 31, 2014 we had over-the-counter commodity swaps consisting of 9.1 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production from our two refineries. The fair value of the outstanding contracts at December 31, 2014 was a net unrealized gain of $47.3 million, comprised of both short-term and long-term unrealized gains and losses. A change of $1.00 per barrel in the fair value of the crack spread swaps would result in an increase or decrease in the related fair values of the commodity hedging instruments of $9.1 million.
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 Canadian crude oil purchases are conducted 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 delivery and settlement of purchases of crude oil in Canadian dollars, the exposure to foreign currency exchange rate risk and the resulting foreign currency gain (loss) is not material.
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Item 8. Financial Statements and Supplementary Data
CVR REFINING, LP AND SUBSIDIARIES
INDEX TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
Audited Financial Statements: | Page Number |
78
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
We have audited the accompanying consolidated balance sheets of CVR Refining, LP (a Delaware limited partnership) and subsidiaries (the "Partnership") as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in partners' capital, and cash flows for each of the two years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CVR Refining, LP and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2014, 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), the Partnership's internal control over financial reporting as of December 31, 2014 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 20, 2015 expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Houston, Texas
February 20, 2015
79
Report of Independent Registered Public Accounting Firm
The Board of Directors of CVR Refining GP, LLC
and
The Unitholders of CVR Refining, LP
and
The General Partner of CVR Refining, LP:
We have audited the accompanying CVR Refining, LP and subsidiaries (the Partnership) combined statements of operations, changes in partners' capital/divisional equity, and cash flows for the year ended December 31, 2012. These combined financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these combined financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present fairly, in all material respects, CVR Refining, LP and subsidiaries' results of operations and cash flows for the year ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Houston, Texas
March 14, 2013
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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
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, 2014, based on criteria established in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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 under Item 9A. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.
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.
In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, 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), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2014, and our report dated February 20, 2015 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Houston, Texas
February 20, 2015
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, | |||||||
2014 | 2013 | ||||||
(in millions, except unit data) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 370.2 | $ | 279.8 | |||
Accounts receivable, net of allowance for doubtful accounts of $0.3 and $0.9, including $0.5 and $0.6 due from affiliates at December 31, 2014 and 2013, respectively | 130.0 | 234.9 | |||||
Inventories | 293.8 | 493.7 | |||||
Prepaid expenses and other current assets, including $4.1 and $1.5 due from affiliates at December 31, 2014 and 2013, respectively | 94.5 | 74.2 | |||||
Total current assets | 888.5 | 1,082.6 | |||||
Property, plant, and equipment, net of accumulated depreciation | 1,487.1 | 1,430.2 | |||||
Deferred financing costs, net | 8.1 | 10.0 | |||||
Other long-term assets, including $0.1 due from affiliates at December 31, 2013 | 34.1 | 10.5 | |||||
Total assets | $ | 2,417.8 | $ | 2,533.3 | |||
LIABILITIES AND PARTNERS' CAPITAL | |||||||
Current liabilities: | |||||||
Note payable and capital lease obligations | $ | 1.4 | $ | 1.3 | |||
Accounts payable, including $8.9 and $17.7 due to affiliates at December 31, 2014 and 2013, respectively | 269.9 | 341.0 | |||||
Personnel accruals, including $1.6 due to affiliates at December 31, 2014 | 18.6 | 13.0 | |||||
Accrued taxes other than income taxes | 24.7 | 30.0 | |||||
Accrued expenses and other current liabilities, including $6.9 and $0.2 due to affiliates at December 31, 2014 and 2013, respectively | 69.4 | 40.4 | |||||
Total current liabilities | 384.0 | 425.7 | |||||
Long-term liabilities: | |||||||
Long-term debt and capital lease obligations, net of current portion, including $31.5 due to affiliates at December 31, 2014 and 2013 | 580.0 | 581.4 | |||||
Accrued environmental liabilities, net of current portion | 0.9 | 1.2 | |||||
Other long-term liabilities, including $1.0 and $1.1 due to affiliates at December 31, 2014 and 2013, respectively | 2.8 | 2.9 | |||||
Total long-term liabilities | 583.7 | 585.5 | |||||
Commitments and contingencies | |||||||
Partners’ capital: | |||||||
Common unitholders, 147,600,000 units issued and outstanding at December 31, 2014 and 2013 | 1,450.1 | 1,522.1 | |||||
General partner interest | — | — | |||||
Total partners' capital | 1,450.1 | 1,522.1 | |||||
Total liabilities and partners' capital | $ | 2,417.8 | $ | 2,533.3 | |||
See accompanying notes to consolidated and combined financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions, except per unit data) | |||||||||||
Net sales | $ | 8,829.7 | $ | 8,683.5 | $ | 8,281.7 | |||||
Operating costs and expenses: | |||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 8,013.4 | 7,526.7 | 6,667.5 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 416.0 | 361.7 | 426.5 | ||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 70.6 | 77.8 | 86.2 | ||||||||
Depreciation and amortization | 122.5 | 114.3 | 107.6 | ||||||||
Total operating costs and expenses | 8,622.5 | 8,080.5 | 7,287.8 | ||||||||
Operating income | 207.2 | 603.0 | 993.9 | ||||||||
Other income (expense): | |||||||||||
Interest expense and other financing costs | (34.2 | ) | (44.1 | ) | (76.2 | ) | |||||
Interest income | 0.3 | 0.4 | — | ||||||||
Gain (loss) on derivatives, net | 185.6 | 57.1 | (285.6 | ) | |||||||
Loss on extinguishment of debt | — | (26.1 | ) | (37.5 | ) | ||||||
Other income (expense), net | (0.2 | ) | 0.1 | 0.7 | |||||||
Total other income (expense) | 151.5 | (12.6 | ) | (398.6 | ) | ||||||
Income before income tax expense | 358.7 | 590.4 | 595.3 | ||||||||
Income tax expense | — | — | — | ||||||||
Net income | $ | 358.7 | $ | 590.4 | $ | 595.3 | |||||
Net income subsequent to initial public offering (January 23, 2013 through December 31, 2013) | $ | 512.6 | |||||||||
Net income per common unit - basic(1) | $ | 2.43 | $ | 3.47 | |||||||
Net income per common unit - diluted(1) | $ | 2.43 | $ | 3.47 | |||||||
Weighted average common units outstanding: | |||||||||||
Basic | 147.6 | 147.6 | |||||||||
Diluted | 147.6 | 147.6 | |||||||||
(1) Represents net income per common unit since closing the Partnership’s initial public offering on January 23, 2013. See Note 10 to the consolidated and combined financial statements.
See accompanying notes to consolidated and combined financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL/DIVISIONAL EQUITY
Common Units Issued | Divisional Equity | Limited Partner Interest | Common Unitholders | General Partner Interest | Total Partners' Capital/Divisional Equity | |||||||||||||||||
(in millions, except unit data) | ||||||||||||||||||||||
Balance at December 31, 2011 | — | $ | 1,018.6 | $ | — | $ | — | $ | — | $ | 1,018.6 | |||||||||||
Share-based compensation | — | 18.5 | — | — | — | 18.5 | ||||||||||||||||
Distribution to parent, net | — | (651.6 | ) | — | — | — | (651.6 | ) | ||||||||||||||
Net income | — | 595.3 | — | — | — | 595.3 | ||||||||||||||||
CRLLC contribution to CVR Refining, LP for limited partner interest | — | (980.8 | ) | 980.8 | — | — | — | |||||||||||||||
Balance at December 31, 2012 | — | — | 980.8 | — | — | 980.8 | ||||||||||||||||
Net income attributable to period from January 1, 2013 through January 22, 2013 | — | — | 77.8 | — | — | 77.8 | ||||||||||||||||
Share-based compensation – affiliates attributable to the period from January 1, 2013 through January 22, 2013 | — | — | 0.8 | — | — | 0.8 | ||||||||||||||||
Distributions to affiliates, net | — | — | (150.0 | ) | — | — | (150.0 | ) | ||||||||||||||
Conversion of limited partner interest to common units and general partner interest | 147,600,000 | — | (909.4 | ) | 909.4 | — | — | |||||||||||||||
January issuance of common units to public, net of offering costs | — | — | — | 653.6 | — | 653.6 | ||||||||||||||||
Distributions to affiliates, net | — | — | — | (85.1 | ) | — | (85.1 | ) | ||||||||||||||
May issuance of additional common units to public, net of offering costs | 13,209,236 | — | — | 393.6 | — | 393.6 | ||||||||||||||||
May redemption of common units from CVR Refining Holdings, LLC | (13,209,236 | ) | — | — | (394.0 | ) | — | (394.0 | ) | |||||||||||||
Share-based compensation - Affiliates | — | — | — | 8.7 | — | 8.7 | ||||||||||||||||
Cash distributions to common unitholders - Affiliates | — | — | — | (378.7 | ) | — | (378.7 | ) | ||||||||||||||
Cash distributions to common unitholders - Non-affiliates | — | — | — | (98.0 | ) | — | (98.0 | ) | ||||||||||||||
Net income attributable to the period from January 23, 2013 through December 31, 2013 | — | — | — | 512.6 | — | 512.6 | ||||||||||||||||
Balance at December 31, 2013 | 147,600,000 | — | — | 1,522.1 | — | 1,522.1 | ||||||||||||||||
June issuance of additional common units to the public, net of offering costs | 7,089,100 | — | — | 178.5 | — | 178.5 | ||||||||||||||||
June redemption of common units from CVR Refining Holdings, LLC | (7,089,100 | ) | — | — | (179.0 | ) | — | (179.0 | ) | |||||||||||||
Share-based compensation - Affiliates | — | — | — | 2.3 | — | 2.3 | ||||||||||||||||
Cash distributions to common unitholders - Affiliates | — | — | — | (313.4 | ) | — | (313.4 | ) | ||||||||||||||
Cash distributions to common unitholders - Non-affiliates | — | — | — | (119.1 | ) | — | (119.1 | ) | ||||||||||||||
Net income | — | — | — | 358.7 | — | 358.7 | ||||||||||||||||
Balance at December 31, 2014 | 147,600,000 | $ | — | $ | — | $ | 1,450.1 | $ | — | $ | 1,450.1 | |||||||||||
See accompanying notes to consolidated and combined financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Cash flows from operating activities: | |||||||||||
Net income | $ | 358.7 | $ | 590.4 | $ | 595.3 | |||||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
Depreciation and amortization | 122.5 | 114.3 | 107.6 | ||||||||
Allowance for doubtful accounts | (0.5 | ) | (1.1 | ) | 0.7 | ||||||
Amortization of deferred financing costs | 1.9 | 1.9 | 6.4 | ||||||||
Amortization of original issue discount | — | — | 0.5 | ||||||||
Amortization of original issue premium | — | — | (2.8 | ) | |||||||
Loss on disposition of assets | 0.2 | 0.1 | 1.2 | ||||||||
Loss on extinguishment of debt | — | 26.1 | 37.5 | ||||||||
Share-based compensation | 8.0 | 11.6 | 18.5 | ||||||||
(Gain) loss on derivatives, net | (185.6 | ) | (57.1 | ) | 285.6 | ||||||
Current period settlements on derivative contracts | 122.2 | 6.4 | (137.6 | ) | |||||||
Changes in assets and liabilities: | |||||||||||
Accounts receivable | 105.4 | (29.3 | ) | (30.4 | ) | ||||||
Inventories | 200.3 | 5.8 | 113.9 | ||||||||
Prepaid expenses and other current assets | 3.9 | (47.8 | ) | 15.4 | |||||||
Other long-term assets | (0.6 | ) | 0.2 | 2.2 | |||||||
Accounts payable | (58.5 | ) | (18.9 | ) | (101.3 | ) | |||||
Accrued expenses and other current liabilities | 36.6 | (1.0 | ) | 4.4 | |||||||
Accrued environmental liabilities | (0.3 | ) | (0.4 | ) | 0.1 | ||||||
Other long-term liabilities | 1.6 | (0.2 | ) | 0.1 | |||||||
Net cash provided by operating activities | 715.8 | 601.0 | 917.3 | ||||||||
Cash flows from investing activities: | |||||||||||
Capital expenditures | (191.3 | ) | (204.5 | ) | (120.2 | ) | |||||
Proceeds from sale of assets | 0.1 | 0.1 | 0.4 | ||||||||
Net cash used in investing activities | (191.2 | ) | (204.4 | ) | (119.8 | ) | |||||
Cash flows from financing activities: | |||||||||||
Proceeds, gross on issuance of CVR Refining's senior notes | — | — | 500.0 | ||||||||
Payments on senior secured notes | — | (243.4 | ) | (478.7 | ) | ||||||
Payment of capital lease obligations | (1.2 | ) | (1.1 | ) | (0.9 | ) | |||||
Payment of deferred financing costs | — | (0.4 | ) | (12.8 | ) | ||||||
Revolving debt borrowings - affiliates | — | 31.5 | — | ||||||||
Proceeds from January 2013 issuance of common units, net of offering costs | — | 655.7 | — | ||||||||
Proceeds from May 2013 issuance of common units, net of offering costs | — | 393.6 | — | ||||||||
Redemption of common units from CVR Refining Holdings, LLC - May 2013 | — | (394.0 | ) | — | |||||||
Proceeds from June 2014 issuance of common units, net of offering costs | 178.5 | — | — | ||||||||
Redemption of common units from CVR Refining Holdings, LLC - June 2014 | (179.0 | ) | — | — | |||||||
Deferred costs associated with the initial public offering | — | — | (3.1 | ) | |||||||
Net distributions to parent | — | — | (651.6 | ) | |||||||
Distributions to affiliates | — | (235.1 | ) | — | |||||||
Distributions to common unitholders - affiliates | (313.4 | ) | (378.7 | ) | — | ||||||
Distributions to common unitholders - non-affiliates | (119.1 | ) | (98.0 | ) | — | ||||||
Net cash used in financing activities | (434.2 | ) | (269.9 | ) | (647.1 | ) | |||||
Net increase in cash and cash equivalents | 90.4 | 126.7 | 150.4 | ||||||||
Cash and cash equivalents, beginning of period | 279.8 | 153.1 | 2.7 | ||||||||
Cash and cash equivalents, end of period | $ | 370.2 | $ | 279.8 | $ | 153.1 | |||||
Supplemental disclosures: | |||||||||||
Cash paid for interest net of capitalized interest of $9.4, $3.2 and $3.0 for the years ended December 31, 2014, 2013 and 2012, respectively | $ | 32.4 | $ | 49.4 | $ | 75.2 | |||||
Non-cash investing and financing activities: | |||||||||||
Construction in process additions included in accounts payable | $ | 19.9 | $ | 30.4 | $ | 37.4 | |||||
Change in accounts payable related to construction in process additions | $ | (10.5 | ) | $ | (7.0 | ) | $ | 17.5 | |||
Reduction of proceeds for underwriting discount and financing costs | $ | — | $ | — | $ | 7.5 | |||||
See accompanying notes to consolidated and combined financial statements.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(1) Formation of the Partnership, Organization and Nature of Business
CVR Refining, LP and subsidiaries (referred to as "CVR Refining" or the "Partnership") is an independent petroleum refiner and marketer of high value transportation fuels. As of December 31, 2014, Coffeyville Resources, LLC (referred to as "CRLLC") a wholly-owned subsidiary of CVR Energy, Inc. (referred to as "CVR Energy"), owns 100% of our general partner interest and approximately 66% of our limited partner interests. As of December 31, 2014, Icahn Enterprises L.P. ("IEP") and its affiliates own approximately 82% of CVR Energy.
In preparation for the initial public offering (the "Initial Public Offering") of CVR Refining, on December 31, 2012, CRLLC contributed all of its interests in the operating subsidiaries which constitute its petroleum refining and related logistics business, as well as Coffeyville Finance Inc. ("Coffeyville Finance"), a finance subsidiary formed to serve as a co-issuer of debt securities, to a newly-formed subsidiary, CVR Refining, LLC ("Refining LLC"). The operating subsidiaries that were contributed to Refining LLC include the following entities: Wynnewood Energy Company, LLC ("WEC"); Wynnewood Refining Company, LLC ("WRC"); Coffeyville Resources Refining & Marketing, LLC ("CRRM"); Coffeyville Resources Crude Transportation, LLC ("CRCT"); Coffeyville Resources Terminal, LLC ("CRT"); and Coffeyville Resources Pipeline, LLC ("CRP"). The entities that were contributed by CRLLC to Refining LLC in connection with the Initial Public Offering are referred to herein as the "Refining Subsidiaries." CVR Refining Holdings, LLC ("CVR Refining Holdings"), a wholly-owned subsidiary of CRLLC, contributed its 100% membership interest in Refining LLC to the Partnership on December 31, 2012. In connection with the closing of the Initial Public Offering, CVR Refining Holdings and its subsidiary were issued a designated number of common units of the Partnership, which equated to an approximately 81% limited partner interest. CRLLC retained its other assets, including its ownership interests in CVR Partners, LP ("CVR Partners"), a NYSE traded manufacturer of nitrogen fertilizer, and its general partner.
The contribution of entities as discussed above by CRLLC to Refining LLC was not considered a business combination accounted for under the purchase method as it was a transfer of assets under common control and, accordingly, balances were transferred at their historical cost. The combined financial statements for the periods prior to the contribution on December 31, 2012 have been prepared using the Refining Subsidiaries' historical basis in the assets and liabilities, and include all revenues, costs, assets and liabilities attributed to these entities.
Initial Public Offering of CVR Refining, LP
On January 23, 2013, the Partnership completed 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 NYSE, began trading on January 17, 2013 under the symbol "CVRR." In connection with the Initial Public Offering, the Partnership paid approximately $32.5 million in underwriting fees and incurred approximately $3.9 million of other offering costs.
The net proceeds to CVR Refining of the Initial Public Offering were approximately $653.6 million after deducting underwriting discounts and commissions and offering expenses from the Initial Public Offering have been utilized as follows:
• | approximately $253.0 million was used to repurchase CRLLC's 10.875% senior secured notes due 2017 (including accrued interest); |
• | approximately $54.0 million was used to fund the turnaround expenses at the Wynnewood refinery that were incurred during the fourth quarter of 2012; |
• | approximately $85.1 million was distributed to CRLLC; |
• | approximately $160.0 million was used to fund certain maintenance and environmental capital expenditures through 2014; and |
• | the balance of the proceeds of approximately $101.5 million was allocated to be utilized for general corporate purposes. |
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Prior to the closing of the Initial Public Offering, the Partnership distributed approximately $150.0 million of cash on hand to CRLLC. Subsequent to 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 (this number includes the common units held by an affiliate of IEP, representing approximately 3% of all outstanding limited partner interests) and CVR Refining Holdings held common units approximating 81% of all outstanding limited partner interests.
Underwritten Offering
On May 20, 2013, the Partnership completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of IEP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a CVR Energy subsidiary, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Partnership sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the “Transactions.” In connection with the Transactions, the Partnership paid approximately $12.2 million in underwriting fees and approximately $0.4 million in offering costs.
CVR Refining utilized proceeds of approximately $394.0 million from the Underwritten Offering (including proceeds from the exercise of the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy. The Partnership did not receive any of the proceeds from the sale of common units by a CVR Energy subsidiary to AEPC.
Following the closing of the Transactions and prior to June 30, 2014, public security holders held approximately 29% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% of all outstanding limited partner interests), and CVR Refining Holdings held approximately 71% of all outstanding limited partner interests.
Second Underwritten Offering
On June 30, 2014, the Partnership completed a second underwritten offering (the "Second Underwritten Offering") by selling 6,500,000 common units to the public at a price of $26.07 per unit. The Partnership paid approximately $5.3 million in underwriting fees and approximately $0.5 million in offering costs. CVR Refining utilized net proceeds of approximately $164.1 million from the Second Underwritten Offering to redeem 6,500,000 common units from CVR Refining Holdings. Subsequent to the closing of the Second Underwritten Offering, public security holders held approximately 33% of all outstanding limited partner interests, and CVR Refining Holdings held approximately 67% of all outstanding limited partner interests.
On July 24, 2014, the Partnership sold an additional 589,100 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their option to purchase additional common units. The Partnership utilized net proceeds of approximately $14.9 million from the underwriters' exercise of their option to purchase additional common units to redeem an equal amount of common units from CVR Refining Holdings. Additionally, on July 24, 2014, CVR Refining Holdings sold 385,900 common units to the public at a price of $26.07 per unit in connection with the underwriters' exercise of their remaining option to purchase additional common units. CVR Refining Holdings received net proceeds of $9.7 million.
Subsequent to the closing of the underwriters' option for the Second Underwritten Offering and as of December 31, 2014, public security holders held approximately 34% of all outstanding limited partner interests (including common units owned by affiliates of IEP, representing approximately 4% 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, LLC, which holds a non-economic general partner interest.
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 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.
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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.
The Partnership entered into a services agreement on December 31, 2012, pursuant to which the Partnership and its general partner obtain certain management and other services from CVR Energy. In addition, by virtue of the fact that the Partnership is a controlled affiliate of CVR Energy, the Partnership is bound by an omnibus agreement entered into by CVR Energy, CVR Partners and the general partner of CVR Partners, pursuant to which the Partnership may not engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of CVR Partners' outstanding units.
CVR Energy Transaction Agreement
On April 18, 2012, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with an affiliate of IEP. Pursuant to the Transaction Agreement, IEP's affiliate offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent payment right for each share of CVR Energy common stock (the "CCP"), which represented the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy was executed on or prior to August 18, 2013 and such transaction closed. As no sale of CVR Energy was executed by the date outlined in the Transaction Agreement, the CCPs expired on August 19, 2013.
On May 7, 2012, IEP's affiliate announced that control of CVR Energy had been acquired through the Offer. As of December 31, 2014, IEP and its affiliates owned approximately 82% of the shares of CVR Energy.
(2) Basis of Presentation
The accompanying consolidated and combined financial statements have been prepared in accordance with Regulation S-X, Article 3, "General instructions as to financial statements" and Staff Accounting Bulletin, or SAB Topic 1-B, "Allocations of Expenses and Related disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity."
Prior to the contribution of Refining LLC to the Partnership and entering into the services agreement on December 31, 2012, certain expenses incurred by CVR Energy and its affiliates were only indirectly attributable to its ownership of the refining and related logistics assets of CRLLC. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such expenses to CVR Refining, so that the financial statements reflect substantially all costs of doing business. Accounts and balances related to the refining and related logistics operations were based on a combination of specific identification and allocations. CVR Energy and CRLLC allocated various corporate overhead expenses based on a percentage of total refining and related logistics payroll to the total payrolls of their segments (i.e. the petroleum and fertilizer segments are comprised of CVR Refining and CVR Partners, respectively). These allocations are not necessarily indicative of the cost that the Partnership would have incurred had it operated as an independent stand-alone entity during the year ended December 31, 2012. All intercompany accounts and transactions have been eliminated. The allocations and related estimates and assumptions are described more fully in Note 3 ("Summary of Significant Accounting Policies") and Note 15 ("Related Party Transactions").
CRLLC also used a centralized approach to cash management and the financing of its operations until the contribution of its petroleum refining and related logistics business to CVR Refining on December 31, 2012. As a result, amounts owed to or from CRLLC prior to December 31, 2012 are reflected as a component of divisional equity on the accompanying Consolidated and Combined Statements of Changes in Partners' Capital/Divisional Equity.
Beginning in 2013, the consolidated financial statements include certain selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization) that CVR Energy and its affiliates incurred on behalf of the Partnership. These related party transactions are governed by the services agreement originally entered into on December 31, 2012. See Note 15 ("Related Party Transactions") for additional
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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
discussion of the services agreement and billing and allocation of certain costs. The amounts charged or allocated to the Partnership are not necessarily indicative of the cost that the Partnership would have incurred had it operated as an independent entity.
The Partnership has omitted net income per unit for the year ended December 31, 2012 because the Partnership operated under a different capital structure prior to the closing of the Initial Public Offering and, as a result, the per unit data would not be meaningful to investors. Per unit data for the year ended December 31, 2013 is calculated since the closing of the Initial Public Offering on January 23, 2013.
(3) Summary of Significant Accounting Policies
Cash and Cash Equivalents
CRLLC historically provided cash as needed to support the operations of the refining and related logistics assets and retained excess cash earned by the Partnership. Cash received or paid by CRLLC on behalf of CVR Refining prior to December 31, 2012 is reflected as net contributions from or net distributions to parent on the accompanying Consolidated and Combined Statements of Changes in Partners' Capital/Divisional Equity. Effective December 31, 2012, the Partnership began operating with an independent capital structure. 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 and Combined 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, 2014 and 2013 was $18.9 million and $11.7 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 and Combined Statements of Cash Flows. At December 31, 2014, no customers individually represented greater than 10% of the total net accounts receivable balance. At December 31, 2013, 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, 2014 and 2013 was approximately 9% and 13%, 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 market for refined fuels and byproducts 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 market. The cost of inventories includes inbound freight costs.
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Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to our 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 |
Leasehold improvements 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 and Combined Statements of Operations.
Deferred Financing Costs, Underwriting and Original Issue Discount
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, the underwriting and original issue discount and premium related to debt issuances have been 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 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. Planned major maintenance activities for the refineries varies by unit, but generally is every four to five years.
During the outage at the Coffeyville refinery as discussed in Note 7 ("Insurance Claims"), the Partnership accelerated certain planned turnaround activities scheduled for 2015 and incurred approximately $5.5 million in turnaround expenses for the year ended December 31, 2014. The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012 and incurred approximately $21.2 million in turnaround expenses for the year ended December 31, 2012. The first phase was completed during the fourth quarter of 2011. During the fluid catalytic cracking unit ("FCCU") outage at the Wynnewood refinery, the Partnership accelerated certain planned turnaround activities previously scheduled for 2016 and incurred approximately $1.3 million in turnaround expenses for the year ended December 31, 2014. The Wynnewood refinery completed a turnaround in the fourth quarter of 2012 and incurred approximately $102.5 million in turnaround expenses for the year ended December 31, 2012. Costs associated with these turnaround activities were included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Cost Classifications
Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, renewable identification numbers (“RINs”) and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $5.9 million, $4.8 million and $3.6 million for the years ended December 31, 2014, 2013 and 2012, respectively.
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 as discussed in Note 4 ("Share-Based Compensation"). Direct operating expenses exclude depreciation and amortization of approximately $115.0 million, $109.1 million and $103.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated legal expenses, 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 as discussed in Note 4 ("Share-Based Compensation"). Selling, general and administrative expenses exclude depreciation and amortization of approximately $1.6 million, $0.4 million and $0.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
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 and combined 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 ASC Topic 740, Income Taxes ("ASC 740"), 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, 2014 and 2013, the Partnership has no material tax balances associated with the Texas franchise tax.
Segment Reporting
The Partnership accounts for segment reporting in accordance with the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic ASC 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.
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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Divisional Equity
Partners' capital is referred to as divisional equity during the periods covered by the consolidated and combined financial statements prior to the contribution of the Refining Subsidiaries to the Partnership. Upon CRLLC's contribution of the Refining Subsidiaries to the Partnership on December 31, 2012, divisional equity became partners' capital.
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 and Combined Statements of Operations.
The Partnership also engages in trading activities, whereby the Partnership enters into agreements to purchase and sell refined products with third parties. The Partnership acts as a principal in these transactions, taking title to the products in purchases from counterparties, and accepting the risks and rewards of ownership. The Partnership records revenue for the gross amount of the sales transactions, and records costs of purchases as an operating expense in the accompanying consolidated and combined financial statements.
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 product sold (exclusive of depreciation and amortization).
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 ("ASC 815"), 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 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.
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
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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
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.
Use of Estimates
The consolidated and combined financial statements have been prepared in conformity with U.S. generally accepted accounting principles ("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.
Related Party Transactions
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 and combined 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 and Combined 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). For the years ended December 31, 2014 and 2013, amounts incurred by CVR Energy and its affiliates on behalf of Partnership have been governed and billed in accordance with the services agreement entered into between the Partnership and CVR Energy on December 31, 2012. 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.
Allocation of Costs
Prior to the contribution of Refining LLC to the Partnership and entering into the services agreement with CVR Energy on December 31, 2012, certain expenses incurred by CVR Energy and its affiliates were only indirectly attributable to its ownership of the refining and related logistics assets of CRLLC. Accordingly, the accompanying financial statements have been prepared in accordance with SAB Topic 1-B, as more fully explained in Note 2 ("Basis of Presentation"). These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting and legal services, and other general and administrative expenses. CVR Energy and CRLLC have allocated general and administrative expenses to CVR Refining based on allocation methodologies that management considers reasonable and result in an allocation of the cost of doing business borne by CVR Energy and CRLLC on behalf of CVR Refining. These allocations may not be indicative of the cost of future operations.
CVR Refining's Combined Statements of Operations for the year ended December 31, 2012 reflects all of the expenses that CRLLC and CVR Energy incurred on CVR Refining's behalf. For the years ended December 31, 2014 and 2013, amounts incurred by CVR Energy and its affiliates on our behalf have been governed and billed in accordance with the services agreement as discussed above. CVR Refining's financial statements therefore include certain expenses incurred by CVR Energy and CRLLC which may include, but are not necessarily limited to, the following:
• | Officer and employee salaries and share-based compensation; |
• | Rent or depreciation; |
• | Advertising; |
• | Accounting, tax, legal and information technology services; |
• | Other selling, general and administrative expenses; |
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• | Costs for defined contribution plans, medical and other employee benefits; and |
• | Financing costs, including interest, and losses on extinguishment of debt. |
Selling, general and administrative expense allocations were based primarily on the nature of the expense incurred, with the exception of compensation and compensation related expenses. Compensation expenses, including share-based compensation, are allocated to CVR Refining as governed by percentages determined by management to be reasonable and in line with the nature of an individual's roles and responsibilities. Allocations related to share-based compensation are more fully described in Note 4 ("Share-Based Compensation").
The table below reflects cost allocations for the year ended December 31, 2012 reflected in the Combined Statements of Operations.
Year Ended December 31, 2012 | |||
(in millions) | |||
Direct operating expenses (exclusive of depreciation and amortization) | $ | 13.3 | |
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 65.5 | ||
$ | 78.8 | ||
Subsequent Events
The Partnership evaluated subsequent events, if any, that would require an adjustment to the Partnership's consolidated and combined financial statements or require disclosure in the notes to the consolidated and combined financial statements through the date of issuance of the consolidated and combined financial statements. See Note 18 ("Subsequent Events") for further discussion.
New Accounting Pronouncements
In May 2014, the FASB issued Accounting Standard Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which 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. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The standard is effective for interim and annual periods beginning after December 15, 2016 and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The Partnership has not yet selected a transition method and is currently evaluating the standard and the impact on its consolidated financial statements and footnote disclosures.
(4) Share-Based Compensation
Certain employees of CVR Refining and employees of CVR Energy 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 SAB Topic 1-B 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 allocated 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/divisional equity, 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
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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, 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, 2014, only restricted stock units and 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.
Restricted Stock Units
Through the CVR Energy LTIP, shares of restricted stock and restricted stock units (collectively "restricted shares") have been 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 are generally graded-vesting awards, which vest over a three-year period. Compensation expense is recognized on a straight-line basis over the vesting period of the respective tranche of the award.
The change of control and related Transaction Agreement discussed in Note 1 ("Formation of the Partnership, Organization and Nature of Business") triggered a modification to outstanding awards under the CVR Energy LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. The CCPs expired on August 19, 2013. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be 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. As a result of the modification, the Partnership was allocated additional share-based compensation of approximately $6.3 million for the year ended December 31, 2012. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest.
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 are expected to vest 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 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 represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the CVR Energy's common stock, plus (b) 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 will be remeasured at each subsequent reporting date until they vest.
Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at December 31, 2014, there was approximately $0.8 million of total unrecognized compensation cost related to restricted stock units and associated dividend equivalent rights to be recognized over a weighted-average period of approximately 0.9 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 restricted stock units and associated dividend equivalent rights and respective allocation percentages for individuals for whom, as of December 31, 2014, compensation expense has been allocated to the Partnership. Total compensation expense recorded for the years ended December 31, 2014, 2013 and 2012 was approximately $2.2 million, $9.5 million and $18.5 million, respectively. 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, 2014, 2013 and 2012 have been reflected as an increase to partners' capital/divisional equity.
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Performance Unit Awards
In December 2013, CVR Energy entered into Performance Unit Award Agreements with Mr. Lipinski. Certain of the Performance Unit Awards were entered into in connection with the cancellation of Mr. Lipinski's December 2012 restricted stock unit award, as discussed above. In accordance with accounting guidance related to the modification of share-based and other compensatory award arrangements, CVR Energy concluded that the cancellation and concurrent issuance of the performance awards created a substantive service period from the original grant date of the December 2012 restricted stock unit award through the end of the performance period for the related performance awards. Compensation cost for these awards is being recognized over the substantive service period. Total compensation expense recorded for the years ended December 31, 2014 and 2013 related to the performance unit awards was approximately $1.9 million and $2.1 million, respectively. The Partnership will be responsible for reimbursing CVR Energy for its allocated portion of the performance unit awards.
On June 30, 2014, the first award of Mr. Lipinski's Performance Unit Award Agreements vested. The Partnership reimbursed CVR Energy approximately $2.0 million for its allocated portion of the performance unit award payment on July 15, 2014 as a result of the vesting. On December 15, 2014 and December 31, 2014, the second and third awards of Mr. Lipinski's Performance Unit Award Agreements vested. The Partnership reimbursed CVR Energy approximately $1.4 million for its allocated portion of the second award. As of December 31, 2014 the Partnership had a liability of $0.7 million for vested and unreimbursed performance unit awards, which is recorded in accrued expenses and other current liabilities on the Consolidated Balance Sheets.
Incentive Unit Awards
In December 2013 and during 2014, CVR Energy granted awards of incentive units and distribution equivalent rights to certain employees of CRLLC and CVR Energy. 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 (a) the average fair market value of one unit of the Partnership's common units in accordance with the award agreement, plus (b) 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 allocation of costs from CVR Energy remains consistent with the allocation percentages in place at December 31, 2014, there was approximately $4.6 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 1.9 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, 2014, compensation expense has been allocated to the Partnership. Total compensation expense recorded for the year ended December 31, 2014 related to the incentive unit awards was $1.5 million. Total compensation expense for the year ended December 31, 2013 related to the incentive units was not material. The Partnership will be responsible for reimbursing CVR Energy for its allocated portion of the incentive unit awards.
As of December 31, 2014, the Partnership had a liability of $0.5 million 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 year ended December 31, 2014, the Partnership reimbursed CVR Energy $1.0 million for its allocated portion of the incentive unit award payments.
In December 2014, CVR Energy granted an award of 227,927 incentive units in the form of stock appreciation rights ("SARs") to an executive of CVR Energy. 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. Total compensation expense during the year ended December 31, 2014 and the liability related to the SARs as of December 31, 2014 were not material. The Partnership will be responsible for reimbursing CVR Energy for its allocated portion of the award.
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Long-Term Incentive Plan — CVR Refining
In connection with the Initial Public Offering, on January 16, 2013, the board of directors of the general partner of the Partnership adopted the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"). Individuals who are eligible to receive awards under the CVR Refining LTIP include (1) employees of the Partnership and its subsidiaries, (2) employees of the general partner, (3) members of the board of directors of the general partner and (4) 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. 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. On August 14, 2013, the Partnership filed a Form S-8 to register the common units.
In December 2013 and during 2014, 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 (a) the average fair market value of one unit of the Partnership's common units in accordance with the award agreement, plus (b) 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, 2014 and 2013 is presented below:
Phantom Units | Weighted- Average Grant-Date Fair Value | Aggregate Intrinsic Value | ||||||||
(in millions) | ||||||||||
Non-vested at January 16, 2013 | — | $ | — | $ | — | |||||
Granted | 187,177 | 21.55 | ||||||||
Vested | — | — | ||||||||
Forfeited | — | — | ||||||||
Non-vested at December 31, 2013 | 187,177 | $ | 21.55 | $ | 4.2 | |||||
Granted | 281,948 | 17.74 | ||||||||
Vested | (61,002 | ) | 21.55 | |||||||
Forfeited | (4,176 | ) | 21.55 | |||||||
Non-vested at December 31, 2014 | 403,947 | $ | 18.89 | $ | 6.8 | |||||
As of December 31, 2014, there was approximately $6.2 million of total unrecognized compensation cost related to the awards under the CVR Refining LTIP to be recognized over a weighted-average period of 1.8 years. Total compensation expense recorded for the year ended December 31, 2014 related to the awards under the CVR Refining LTIP was $2.4 million. Total compensation expense recorded for the year ended December 31, 2013 was not material. As of December 31, 2014, the Partnership had a liability of $1.0 million 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 year ended December 31, 2014, the Partnership paid cash of $1.4 million to settle liability-classified phantom unit awards and associated distribution equivalent rights upon vesting.
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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
(5) Inventories
Inventories consisted of the following:
December 31, | |||||||
2014 | 2013 | ||||||
(in millions) | |||||||
Finished goods | $ | 163.5 | $ | 259.0 | |||
Raw materials and precious metals | 78.8 | 169.1 | |||||
In-process inventories | 20.6 | 36.8 | |||||
Parts and supplies | 30.9 | 28.8 | |||||
$ | 293.8 | $ | 493.7 | ||||
Due to the current crude environment and subsequent reduction in sales prices for refined products, the Partnership recorded a lower of FIFO cost or market inventory adjustment of approximately $36.8 million as of December 31, 2014. The inventory adjustment is included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
(6) Property, Plant and Equipment
A summary of costs for property, plant and equipment is as follows:
December 31, | |||||||
2014 | 2013 | ||||||
(in millions) | |||||||
Land and improvements | $ | 27.7 | $ | 26.6 | |||
Buildings | 45.4 | 37.7 | |||||
Machinery and equipment | 2,015.5 | 1,757.7 | |||||
Automotive equipment | 21.2 | 18.4 | |||||
Furniture and fixtures | 8.4 | 7.3 | |||||
Leasehold improvements | 0.8 | 0.8 | |||||
Construction in progress | 61.2 | 157.3 | |||||
2,180.2 | 2,005.8 | ||||||
Accumulated depreciation | 693.1 | 575.6 | |||||
Total property, plant and equipment, net | $ | 1,487.1 | $ | 1,430.2 | |||
Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2014, 2013 and 2012 totaled approximately $9.4 million, $3.2 million and $3.0 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, 2014 and 2013. Amortization of assets held under capital leases is included in depreciation expense.
(7) Insurance Claims
On July 29, 2014, the Coffeyville refinery experienced a fire at its isomerization unit. Four employees were injured in the fire, including one employee who was fatally injured. 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. The refinery returned to operations in mid-August, with all units except the isomerization unit in operation by August 23, 2014. The isomerization unit started operating on October 12, 2014. 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.
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The Partnership is covered by property damage insurance policies which have an associated deductible of $5.0 million for the Coffeyville refinery. The Partnership anticipates amounts in excess of the $5.0 million deductible related to the isomerization unit fire incident will be recoverable under the property insurance policies. As of December 31, 2014, the Partnership recorded an insurance receivable related to the incident of approximately $1.3 million, which is included in prepaid expenses and other current assets in the Consolidated Balance Sheets. The recording of the receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization). The Partnership also maintains workers' compensation insurance with a $0.5 million per accident deductible.
During the outage at the Coffeyville refinery as discussed above, the Partnership accelerated certain planned turnaround activities scheduled for 2015 and incurred approximately $5.5 million in turnaround expenses for the year ended December 31, 2014.
(8) Long-Term Debt
Long-term debt was as follows:
December 31, | |||||||
2014 | 2013 | ||||||
(in millions) | |||||||
6.5% Second Lien Senior Secured Notes, due 2022 | $ | 500.0 | $ | 500.0 | |||
Intercompany credit facility | 31.5 | 31.5 | |||||
Capital lease obligations | 48.5 | 49.9 | |||||
Long-term debt | $ | 580.0 | $ | 581.4 | |||
Senior Secured Notes
On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the "First Lien Notes") and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the "Second Lien Notes" and together with the First Lien Notes, the "Old Notes"). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Old Notes was amortized to interest expense and other financing costs over the respective terms of the Old Notes.
On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of approximately $27.5 million on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount in 2010. On May 16, 2011, CRLLC repurchased $2.7 million of the Old Notes at a purchase price of 103.0% of the outstanding principal amount. In connection with the repurchase, CRLLC wrote off a portion of previously deferred financing costs and unamortized original issue discount in 2011. CRLLC also recorded additional immaterial losses on extinguishment of debt in connection with premiums paid for the repurchase. As the Old Notes were incurred for the benefit of the operations of CVR Refining, all the debt and associated costs were allocated to CVR Refining.
On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the "Additional First Lien Notes" and together with the First Lien Notes issued in 2010, the "First Lien Notes"). The Additional First Lien Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of $10.0 million for the Additional First Lien Notes and other debt issuance costs were amortized to interest expense and other financing costs over the term of the Additional First Lien Notes. The Additional First Lien Notes were offered in connection with CRLLC's acquisition of WEC. Proceeds of the Additional First Lien Notes were used to partially fund the Wynnewood Acquisition. In conjunction with the issuance of the Additional First Lien Notes, CRLLC expanded the then existing ABL credit facility (see "ABL Credit Facility" below for further discussion of the expansion and associated accounting treatment) and incurred a commitment fee and other third-party costs associated with the expansion.
The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the issuers. See further discussion below related to the tender offer for and redemption of all of the outstanding First Lien Notes in the fourth quarter of 2012. The Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by
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the issuers. On January 23, 2013, $253.0 million of the proceeds from the Initial Public Offering were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the year ended December 31, 2013 which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.
Old Notes Tender Offer
The change of control discussed in Note 1 ("Formation of the Partnership, Organization and Nature of Business") required CVR Energy to make an offer to repurchase all of the Issuers' outstanding Old Notes. On June 4, 2012, the issuers offered to purchase all or any part of the Old Notes, at a cash purchase price of 101% of the aggregate principal amount of the Old Notes, plus accrued and unpaid interest, if any. The offer expired on July 5, 2012 with none of the outstanding Old Notes tendered.
2022 Senior Notes
On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured 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 were secured by substantially the same assets that secured the outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. Accordingly, the 2022 Notes are no longer secured. The 2022 Notes are 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. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, CVR Partners and Coffeyville Nitrogen Fertilizers, LLC ("CRNF") are not guarantors.
A portion of the net proceeds from the offering of the 2022 Notes approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. CRLLC used the remaining proceeds from the offering to fund a completed and settled redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.
Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of these transactions, a loss on extinguishment of debt of $33.4 million was recorded in the Consolidated and Combined Statements of Operations in the fourth quarter of 2012, which includes the total premiums paid of $31.6 million and the write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of unamortized original issuance premium of $6.3 million.
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.
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The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinated debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the Partnership can make distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio and there is no default or event of default under the 2022 Notes. As of December 31, 2014, the Partnership was in compliance with the covenants contained in the 2022 Notes.
Included in other current liabilities on the Consolidated Balance Sheets is accrued interest payable totaling approximately $5.4 million as of both December 31, 2014 and 2013 related to the 2022 Notes. At December 31, 2014, the estimated fair value of the 2022 Notes was approximately $475.0 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.
Asset Based (ABL) Credit Facility
On February 22, 2011, CRLLC entered into a $250.0 million asset-based revolving credit agreement (the "ABL credit facility") with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. This ABL credit facility, which was scheduled to mature in August 2015, replaced the $150.0 million first priority credit facility which was terminated. The ABL credit facility was used to finance ongoing working capital, capital expenditures, letters of credit issuance and general needs of CVR Refining and includes, among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to $250.0 million (in the aggregate), subject to additional lender commitments. On December 15, 2011, CRLLC entered into an incremental commitment agreement to increase the borrowings under the ABL credit facility to $400.0 million in the aggregate in connection with the Additional First Lien Notes issuance as discussed above. Terms of the ABL credit facility did not change as a result of the additional availability. In connection with the incremental commitment under the ABL credit facility, CRLLC incurred lender and other third-party costs of approximately $9.1 million in 2011. On December 20, 2012, the ABL credit facility was amended and restated as discussed below.
In connection with the change in control described in Note 1 ("Formation of the Partnership, Organization and Nature of Business") above, CRLLC, Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent, the lenders and the other parties thereto, entered into a First Amendment to Credit Agreement effective as of May 7, 2012 (the "ABL First Amendment"), pursuant to which the parties agreed to exclude IEP's acquisition of common stock from the definition of change of control as provided in the ABL credit facility.
Amended and Restated Asset Based (ABL) Credit Facility
On December 20, 2012, CRLLC, CVR Refining, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into an amended and restated ABL credit agreement (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility replaced the ABL credit facility described above and is scheduled to mature on December 20, 2017. Under the amended and restated facility, the Partnership assumed CRLLC's position as borrower and CRLLC's obligations under the facility upon closing of the Initial Public Offering on January 23, 2013, as further discussed in Note 1 ("Formation of the Partnership, Organization and Nature of Business").
The Amended and Restated ABL Credit Facility is a senior secured asset based revolving credit facility in an aggregate principal amount of up to $400.0 million with an incremental facility, which permits an increase in borrowings of up to $200.0 million subject to receipt of additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit Parties and their subsidiaries. The Amended and Restated ABL Credit Facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit.
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) 1.75% for LIBOR borrowings and (b) 0.75% 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) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess
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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) 0.40% 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) 0.30% 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 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 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, 2014.
In connection with the Amended and Restated ABL Credit Facility, CRLLC and its subsidiaries incurred lender and other third-party costs of approximately $2.1 million for the year ended December 31, 2012. These costs are being deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. In connection with amendment of the ABL credit facility, a portion of the unamortized deferred financing costs associated with the ABL Credit Facility, totaling approximately $4.1 million, were written off in the fourth quarter of 2012. This expense is reflected on the Consolidated and Combined Statements of Operations as a loss on extinguishment of debt for the year ended December 31, 2012. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining approximately $2.8 million of unamortized deferred financing costs associated with the ABL credit facility will continue to be amortized over the term of the Amended and Restated ABL credit facility.
As of December 31, 2014, the Partnership had availability under the Amended and Restated ABL Credit Facility of $372.7 million and had letters of credit outstanding of approximately $27.3 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of December 31, 2014.
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.
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, 2014.
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, 2014, the Partnership had borrowings of $31.5 million outstanding and $218.5 million available under the intercompany credit facility. Accrued interest payable included in other current liabilities on the Consolidated Balance Sheets as of December 31, 2014 and 2013 is not material.
Deferred Financing Costs
For the years ended December 31, 2014, 2013 and 2012, amortization of deferred financing costs reported as interest expense and other financing costs totaled approximately $1.9 million, $2.0 million and $4.1 million, respectively.
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Estimated amortization of deferred financing costs is as follows:
Year Ending December 31, | Deferred Financing | ||
(in millions) | |||
2015 | $ | 1.9 | |
2016 | 1.9 | ||
2017 | 1.8 | ||
2018 | 0.9 | ||
2019 | 0.9 | ||
Thereafter | 2.6 | ||
$ | 10.0 | ||
Capital Lease Obligations
As a result of the Wynnewood Acquisition, CVR Refining acquired two leases, accounted for as a capital lease and a finance obligation, related to Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. The underlying assets and related depreciation are included in property, plant and equipment. The capital lease relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The lease has 178 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 177 months remaining and will expire in September 2029. As of December 31, 2014, the outstanding obligation associated with these arrangements totaled approximately $49.9 million, of which $48.5 million is included in long-term liabilities and $1.4 million is included in current liabilities in the Consolidated Balance Sheets.
Future payments required under capital lease at December 31, 2014 are as follows:
Year Ending December 31, | Capital Lease | ||
(in millions) | |||
2015 | $ | 6.4 | |
2016 | 6.4 | ||
2017 | 6.4 | ||
2018 | 6.5 | ||
2019 | 6.5 | ||
2020 and thereafter | 63.7 | ||
Total future payments | 95.9 | ||
Less: amount representing interest | 46.0 | ||
Present value of future minimum payments | 49.9 | ||
Less: current portion | 1.4 | ||
Long-term portion | $ | 48.5 | |
(9) Partners’ Capital and Partnership Distributions
The Partnership had two types of partnership interests outstanding at December 31, 2014:
• | common units; and |
• | a general partner interest, which is not entitled to any distributions, and which is held by the general partner. |
At December 31, 2014, 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 units outstanding.
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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 future major scheduled turnaround expenses and, (iv) to the extent applicable, reserves for future operating or capital needs that the board of directors of our 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 impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) loss on extinguishment of debt, (iv) major scheduled turnaround expenses, (v) (gain) loss on derivatives, net and (vi) current period settlements on derivative contracts. Available cash for distributions may be increased by previously established cash reserves, if any, and other excess cash, at the discretion of the board of directors of our general partner.
The following is a summary of cash distributions paid to our unitholders during the years ended December 31, 2014 and 2013 for the respective quarters to which the distributions relate:
December 31, 2013 | March 31, 2014 | June 30, 2014 | September 30, 2014 | Total Cash Distributions Paid in 2014 | |||||||||||||||
(in millions, except per unit data) | |||||||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates | $ | 49.8 | $ | 108.6 | $ | 99.2 | $ | 55.8 | $ | 313.4 | |||||||||
Amounts paid to non-affiliates | 16.6 | 36.1 | 42.5 | 23.9 | 119.1 | ||||||||||||||
Total amount paid | $ | 66.4 | $ | 144.7 | $ | 141.7 | $ | 79.7 | $ | 432.5 | |||||||||
Per common unit | $ | 0.45 | $ | 0.98 | $ | 0.96 | $ | 0.54 | $ | 2.93 | |||||||||
Common units outstanding | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||||||
March 31, 2013 (1) | June 30, 2013 | September 30, 2013 | Total Cash Distributions Paid in 2013 | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Amount paid to CVR Refining Holdings, LLC and affiliates | $ | 195.9 | $ | 149.6 | $ | 33.2 | $ | 378.7 | |||||||
Amounts paid to non-affiliates | 37.3 | 49.7 | 11.1 | 98.0 | |||||||||||
Total amount paid | $ | 233.2 | $ | 199.3 | $ | 44.3 | $ | 476.7 | |||||||
Per common unit | $ | 1.58 | $ | 1.35 | $ | 0.30 | $ | 3.23 | |||||||
Common units outstanding | 147.6 | 147.6 | 147.6 | ||||||||||||
(1) | The distribution for the period ended March 31, 2013 was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Initial Public Offering). |
(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, 2014 or 2013, as all unvested awards under the CVR Refining LTIP were liability-classified awards.
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The following table illustrates the Partnership's calculation of net income per common unit for the years ended December 31, 2014 and 2013:
Year Ended December 31, | |||||||
2014 | 2013(1) | ||||||
(in millions, except per unit data) | |||||||
Net income | $ | 358.7 | $ | 512.6 | |||
Net income per common unit, basic | $ | 2.43 | $ | 3.47 | |||
Net income per common unit, diluted | $ | 2.43 | $ | 3.47 | |||
Weighted-average common units outstanding, basic | 147.6 | 147.6 | |||||
Weighted-average common units outstanding, diluted | 147.6 | 147.6 | |||||
(1) | Reflective of net income and net income per common unit from the closing of the Initial Public Offering on January 23, 2013 to December 31, 2013. |
(11) Benefit Plans
As of December 31, 2014, CVR Energy sponsored two defined-contribution 401(k) plans (the "Plans") in which all employees of CVR Refining may participate. Participants in the Plans may elect to contribute up to 100% of their annual salaries and up to 100% of their annual income sharing. The Partnership matches up to 100% of the first 6% of the participant's contribution for the union and nonunion plans. Both Plans are administered by CVR Energy and contributions for the union plans were determined in accordance with provisions of negotiated labor contracts. Participants in both Plans are immediately vested in their individual contributions. Both Plans have a three-year vesting schedule for matching funds and contain a provision to count service with any predecessor organization. The Partnership's contributions under the Plans for employees of CVR Refining were approximately $4.7 million, $4.2 million and $3.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.
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(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) | |||||||
2015 | $ | 1.5 | $ | 113.8 | |||
2016 | 1.1 | 104.0 | |||||
2017 | 0.3 | 102.4 | |||||
2018 | 0.1 | 101.6 | |||||
2019 | 0.1 | 101.0 | |||||
Thereafter | 0.3 | 714.4 | |||||
$ | 3.4 | $ | 1,237.2 | ||||
(1) | This amount includes approximately $799.6 million payable ratably over sixteen 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, 2014, where applicable. Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of twenty years on TransCanada's Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011. |
CVR Refining leases various equipment, including real properties, under long-term operating leases expiring at various dates. For the years ended December 31, 2014, 2013 and 2012, lease expense totaled approximately $2.5 million, $3.2 million and $2.9 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, 2014, 2013 and 2012, total expense of $121.5 million, $117.1 million and $107.5 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 (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 had an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, 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 the Initial Term or any Renewal Term. The Vitol Agreement was extended for a one-year Renewal Term through December 31, 2015.
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
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consolidated and combined 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.
Flood, Crude Oil Discharge and Insurance
Crude oil was discharged from CVR Refining'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. In connection with the discharge, CVR Refining received in May 2008, notices of claims from sixteen private claimants under the Oil Pollution Act ("OPA") in an aggregate amount of approximately $4.4 million (plus punitive damages). In August 2008, those claimants filed suit against CVR Refining in the United States District Court for the District of Kansas in Wichita (the "Angleton Case"). In October 2009 and June 2010, companion cases to the Angleton Case were filed in the United States District Court for the District of Kansas in Wichita, seeking a total of approximately $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. CVR Refining has settled all of the claims with the plaintiffs from the Angleton Case and has settled all of the claims from the companion cases with the last remaining claim against CVR Refining being settled during the first quarter of 2014. The settlements did not have a material adverse effect on the consolidated and combined financial statements.
On October 25, 2010, CVR Refining received a letter from the United States Coast Guard on behalf of the EPA seeking approximately $1.8 million in oversight cost reimbursement. CVR Refining 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 OPA. CRRM reached an agreement with the DOJ resolving its claims under CWA and the 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 the majority of which have already 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, and provided for a civil penalty of $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP claims. In 2014, CRRM completed 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. In November 2014, CVR Refining concluded a jury trial against the remaining insurance carriers and received a verdict and judgment of approximately $27.1 million, exclusive of potential prejudgment interest and attorneys' fees, which have been requested in post-trial motions. CVR Refining has a $4.0 million receivable related to this matter included in other assets on the Consolidated Balance Sheets as of December 31, 2014 and 2013. In accordance with accounting guidance related to gain contingencies, no additional amounts have been recognized related to the verdict and judgment in the consolidated and combined financial statements.
Environmental, Health, and Safety ("EHS") Matters
CRRM, CRCT, CRT and 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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CRRM, CRCT, WRC and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution. Therefore, CRRM, CRCT, WRC and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the 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, WRC and CRT are subject to extensive and frequently changing federal, state and local environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water and the storage, handling, use and transportation of petroleum and 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 our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.
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 the RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-20 and Docket No. VII-95-H-11, respectively). As of December 31, 2014 and 2013, environmental accruals of approximately $1.1 million and $1.5 million, respectively, were reflected in the Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.2 million and $0.3 million, respectively, are included in other current liabilities. Accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at December 31, 2014 and 2013, respectively. The accruals include estimated closure and post-closure costs of approximately $0.9 million and $0.7 million for two landfills at December 31, 2014 and 2013, respectively. The estimated future payments for these required obligations are as follows:
Year Ending December 31, | Amount | ||
(in millions) | |||
2015 | $ | 0.2 | |
2016 | 0.1 | ||
2017 | 0.1 | ||
2018 | 0.1 | ||
2019 | 0.1 | ||
Thereafter | 0.6 | ||
Undiscounted total | 1.2 | ||
Less amounts representing interest at 2.06% | 0.1 | ||
Accrued environmental liabilities at December 31, 2014 | $ | 1.1 | |
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.
In 2007, the EPA promulgated the Mobile Source Air Toxic II ("MSAT II") rule that requires 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,
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2014. The projects were completed at a total cost of approximately $47.6 million and $88.3 million, excluding capitalized interest, by CRRM and WRC, respectively.
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. motor fuel market, there may be a decrease in demand for petroleum products. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its transportation fuel or purchase RINs in lieu of blending. In 2013, the Wynnewood refinery was subject to the RFS for the first time. However, because the cost of purchasing RINs had been extremely volatile and had significantly increased, the Wynnewood refinery petitioned the EPA as a "small refinery" for hardship relief from the RFS requirements in 2013 based on the "disproportionate economic hardship" of the rule on the Wynnewood refinery. The EPA denied the petition in a letter dated September 5, 2014.
During 2013, the cost of RINs was extremely volatile as the EPA's proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 proposed percentage standards were published; however, RIN prices remained volatile and increased subsequently in 2014. In May 2014, the EPA lowered the 2013 cellulosic biofuel standard to 0.0005%, and, in June 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to September 30, 2014. In August 2014, the EPA further extended the compliance demonstration deadline for the 2013 RFS to 30 days following publication of the final 2014 annual renewable fuel percentage standards. In November 2014, the EPA announced that it would not finalize the 2014 annual renewable fuel standards before the end of 2014, thereby extending the compliance deadline for the 2013 RFS as well.
The cost of RINs for the years ended December 31, 2014, 2013 and 2012 was approximately $127.2 million, $180.5 million and $21.0 million, respectively. As of December 31, 2014 and 2013, CVR Refining's biofuel blending obligation was approximately $52.3 million and $17.4 million, respectively, which is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets. The future cost of RINs for CRRM and WRC going forward is difficult to estimate, particularly until such time that the 2014 renewable fuel percentage standards are finalized and the 2015 renewable fuel percentage standards are announced. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of petroleum products, as well as the fuel blending performed at the refineries, all of which can vary significantly from quarter to quarter.
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 must be in compliance with the more stringent emission standards by January 1, 2017; however, compliance with the rule is extended until January 1, 2020 for approved small volume refineries and small refiners. The Wynnewood refinery has submitted an application to the EPA requesting "small volume refinery" status. It is not anticipated that the refineries will require additional controls or capital expenditures to meet the anticipated new standard.
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 install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its 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" with the EPA, which replaces the 2004 Consent Decree, as amended (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 gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the
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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 NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% 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, the Partnership 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. The remaining costs of complying with the Second Consent Decree are expected to be approximately $44.0 million. Additional incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a several year timeframe.
WRC entered into a Consent Order with the Oklahoma Department of Environmental Quality ("ODEQ") in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses certain historic Clean Air Act compliance issues related to the operations of the refinery by the prior owner. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be $3.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.
From time to time, ODEQ conducts air inspections of the Wynnewood refinery and pursues enforcement related to any alleged non-compliance with the Clean Air Act seeking civil penalties and injunctive relief, which may necessitate the installation of controls. In January 2014, ODEQ issued a full compliance evaluation ("FCE") report covering the period from December 2010 to June 2013, which covers periods of the previous owner's ownership and operation and, in some cases, continued into CVR Refining's ownership of the Wynnewood refinery. In addition, on April 11, 2014, WRC received a partial compliance evaluation ("PCE") report from ODEQ alleging violations of the Clean Air Act. ODEQ conducted a follow-up inspection on June 30, 2014. WRC has responded to both the FCE and PCE. The costs of any enforcement that may arise as a result of the FCE or PCE cannot be predicted at this time. However, based on its experience related to Clean Air Act enforcement and control requirements, CVR Refining does not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material.
WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest consent order (the "CWA Consent Order"), which superseded other consent orders, became effective in September 2011. The CWA Consent Order addressed alleged non-compliance by WRC with its Oklahoma Pollutant Discharge Elimination System ("OPDES") permit limits. The CWA Consent Order required WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery's wastewater treatment plant capacity is sufficient. WRC completed its obligations under the CWA Consent Order, and ODEQ notified WRC that the CWA Consent Order is closed.
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 currently are engaged in settlement discussions related to a civil penalty and injunctive relief. The costs of any related enforcement settlement cannot be predicted at this time. However, based on its experience related to RCRA enforcement, CVR Refining does not anticipate that the costs of any civil penalties, required additional controls or operational changes would be material.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the years ended December 31, 2014, 2013 and 2012, capital expenditures were approximately $100.5 million, $111.3 million and $27.9 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.
CRRM, CRCT, WRC and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.
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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. CVR Refining has completed an internal investigation of the incident and cooperated with 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 and combined financial statements. On September 25, 2013, WRC agreed to pay a small civil penalty to settle, rather than defend claims alleged by the EPA under the Clean Air Act's general duty clause related to the boiler incident. In addition to the above, the spouses of the two employees fatally injured have filed a civil lawsuit against WRC, CVR Refining and CVR Energy in Fort Bend County, Texas. The civil suit is in discovery and the companies will vigorously defend the suit. It is currently too early to assess a potential outcome in the matter.
(13) Fair Value Measurements
ASC Topic 820 — Fair Value Measurements and Disclosures ("ASC 820") established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value and required additional disclosures about fair value measurements. ASC 820 clarifies that fair value is an exit price, representing the amount from the perspective of a market participant that holds the asset or owes the liability at the measurement date.
ASC 820 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities or a group of assets and liabilities such as a business), the income approach (techniques to convert future amounts to a single current amount based on market expectations about those future amounts including present value techniques and option pricing), and the cost approach (amount that would be required currently to replace the service capacity of an asset which is often referred to as a replacement cost).
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, 2014 and 2013:
December 31, 2014 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(in millions) | |||||||||||||||
Location and Description | |||||||||||||||
Other current assets (derivative agreements) | $ | — | $ | 25.0 | $ | — | $ | 25.0 | |||||||
Other long-term assets (derivative agreements) | — | 22.3 | — | 22.3 | |||||||||||
Total Assets | $ | — | $ | 47.3 | $ | — | $ | 47.3 | |||||||
Other current liabilities (biofuel blending obligation) | — | (49.6 | ) | — | (49.6 | ) | |||||||||
Total Liabilities | $ | — | $ | (49.6 | ) | $ | — | $ | (49.6 | ) | |||||
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December 31, 2013 | |||||||||||||||
Level 1 | Level 2 | Level 3 | Total | ||||||||||||
(in millions) | |||||||||||||||
Location and Description | |||||||||||||||
Other current assets (derivative agreements) | $ | — | $ | 0.9 | $ | — | $ | 0.9 | |||||||
Other long-term assets (derivative agreements) | — | 0.1 | — | 0.1 | |||||||||||
Total Assets | $ | — | $ | 1.0 | $ | — | $ | 1.0 | |||||||
Other current liabilities (derivative agreements) | — | (15.3 | ) | — | (15.3 | ) | |||||||||
Other current liabilities (biofuel blending obligation) | — | (16.2 | ) | — | (16.2 | ) | |||||||||
Other long-term liabilities (derivative agreements) | — | (1.8 | ) | — | (1.8 | ) | |||||||||
Total Liabilities | $ | — | $ | (33.3 | ) | $ | — | $ | (33.3 | ) | |||||
As of December 31, 2014 and 2013, the only financial assets and liabilities that are measured at fair value on a recurring basis are CVR Refining's derivative instruments and uncommitted biofuel blending obligation. Additionally, the fair value of the debt issuances is disclosed in Note 8 ("Long-Term Debt"). The commodity derivative contracts and the uncommitted biofuel blending 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, 2014.
(14) Derivative Financial Instruments
Gain (loss) on derivatives, net and current period settlements on derivative contracts were as follows:
Year Ended December 31, | |||||||||||
2014 | 2013 | 2012 | |||||||||
(in millions) | |||||||||||
Current period settlements on derivative contracts | $ | 122.2 | $ | 6.4 | $ | (137.6 | ) | ||||
Gain (loss) on derivatives, net | 185.6 | 57.1 | (285.6 | ) | |||||||
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 for GAAP purposes. 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 and Combined 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, 2014. The fair value of the open commodity positions as of December 31, 2013 was an immaterial net gain included in other current assets. For the years ended December 31, 2014, 2013 and 2012, CVR Refining recognized a net gain of $0.3 million and net losses of $2.9 million and $11.7 million, respectively, which are recorded in gain (loss) on derivatives, net in the Consolidated and Combined Statements of Operations.
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Commodity Swaps
CVR Refining enters into commodity swap contracts in order to fix the margin on a portion of future production. 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 and Combined 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, 2014 and 2013, CVR Refining had open commodity hedging instruments consisting of 9.1 million and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at December 31, 2014 was a net unrealized gain of $47.3 million, of which $25.0 million is included in current assets and $22.3 million is included in other long-term assets. The fair value of the outstanding contracts at December 31, 2013 was a net unrealized loss of $16.1 million, of which $0.9 million is included in current assets, $0.1 million is included in other long-term assets, $15.3 million is included in current liabilities and $1.8 million is included in other long-term liabilities. For the years ended December 31, 2014, 2013 and 2012, the Partnership recognized net gains of $187.4 million and $60.1 million and a net loss of $273.9 million, respectively, which are recorded in gain (loss) on derivatives, net in the Consolidated and Combined Statements of Operations.
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, 2014, the counterparty credit risk adjustment was not material to the consolidated and combined 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. In accordance with guidance issued by the FASB related to "Disclosures about Offsetting Assets and Liabilities," 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, 2014 are recorded as current assets and non-current assets in prepaid expenses and other current assets and other long-term assets, respectively, in the Consolidated Balance Sheets as follows:
As of December 31, 2014 | |||||||||||||||||||
Description | Gross Current Assets | Gross Amounts Offset | Net Current Assets Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 25.3 | $ | (0.3 | ) | $ | 25.0 | $ | — | $ | 25.0 | ||||||||
Total | $ | 25.3 | $ | (0.3 | ) | $ | 25.0 | $ | — | $ | 25.0 | ||||||||
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As of December 31, 2014 | |||||||||||||||||||
Description | Gross Non-Current Assets | Gross Amounts Offset | Net Non-Current Assets Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 22.3 | $ | — | $ | 22.3 | $ | — | $ | 22.3 | |||||||||
Total | $ | 22.3 | $ | — | $ | 22.3 | $ | — | $ | 22.3 | |||||||||
The offsetting assets and liabilities for CVR Refining's derivatives as of December 31, 2013 are recorded as current assets, non-current assets, current liabilities and non-current liabilities in prepaid expenses and other current assets, other long-term assets, accrued expenses and other current liabilities and other long-term liabilities, respectively, in the Consolidated Balance Sheets as follows:
As of December 31, 2013 | |||||||||||||||||||
Description | Gross Current Assets | Gross Amounts Offset | Net Current Assets Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 4.3 | $ | (3.4 | ) | $ | 0.9 | $ | — | $ | 0.9 | ||||||||
Total | $ | 4.3 | $ | (3.4 | ) | $ | 0.9 | $ | — | $ | 0.9 | ||||||||
As of December 31, 2013 | |||||||||||||||||||
Description | Gross Non-Current Assets | Gross Amounts Offset | Net Non-Current Assets Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 0.1 | $ | — | $ | 0.1 | $ | — | $ | 0.1 | |||||||||
Total | $ | 0.1 | $ | — | $ | 0.1 | $ | — | $ | 0.1 | |||||||||
As of December 31, 2013 | |||||||||||||||||||
Description | Gross Current Liabilities | Gross Amounts Offset | Net Current Liabilities Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 31.4 | $ | (16.1 | ) | $ | 15.3 | $ | — | $ | 15.3 | ||||||||
Total | $ | 31.4 | $ | (16.1 | ) | $ | 15.3 | $ | — | $ | 15.3 | ||||||||
As of December 31, 2013 | |||||||||||||||||||
Description | Gross Non-Current Liabilities | Gross Amounts Offset | Net Non-Current Liabilities Presented | Cash Collateral Not Offset | Net Amount | ||||||||||||||
(in millions) | |||||||||||||||||||
Commodity Swaps | $ | 1.9 | $ | (0.1 | ) | $ | 1.8 | $ | — | $ | 1.8 | ||||||||
Total | $ | 1.9 | $ | (0.1 | ) | $ | 1.8 | $ | — | $ | 1.8 | ||||||||
(15) Related Party Transactions
In connection with the formation of CVR Refining in September 2012, CVR Refining and CRRM entered into certain agreements with CVR Energy and its subsidiaries that govern the business relations among CVR Refining, its general partner and CRRM on the one hand, and CVR Energy and its subsidiaries, on the other hand. CRRM has previously entered into other
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agreements with CVR Partners and its subsidiary. Certain of the agreements described below were subsequently amended and restated; the agreements are described as in effect at December 31, 2014. Amounts owed to CVR Refining and CRRM from CVR Energy and its subsidiaries with respect to these agreements are included in accounts receivable, prepaid expenses and other current assets, and other long-term 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 entered into a feedstock and shared services agreement with CRNF, which was amended on December 30, 2013, 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 nitrogen fertilizer plant.
Pursuant to the feedstock agreement, CRRM and CRNF have agreed to transfer excess hydrogen to one another; provided, CRRM is not required to sell hydrogen to CRNF if such hydrogen is required for operation of CRRM's refinery, if such sale would adversely affect the Partnership's classification as a partnership for federal income tax purposes, or if such sale would not be in CRRM's best interest. 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 product sold (exclusive of depreciation and amortization) for CVR Refining. For the years ended December 31, 2014, 2013 and 2012, the net sales generated from the sale of hydrogen to CRNF were approximately $0, $0.6 million and $0.2 million, respectively. For the years ended December 31, 2014, 2013 and 2012, CVR Refining also recognized $10.1 million, $11.4 million and $6.3 million, respectively, of cost of product sold (exclusive of depreciation and amortization) related to the purchase of excess hydrogen from the nitrogen fertilizer facility. At December 31, 2014 and 2013, there were approximately $1.3 million and $2.6 million, respectively, of payables included in accounts payable on the Consolidated Balance Sheets associated with unpaid balances related to hydrogen.
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 the nitrogen fertilizer plant, as determined by CRNF in a commercially reasonable manner. Direct operating expenses associated with nitrogen purchased by CRRM from CRNF for the years ended December 31, 2014, 2013 and 2012, were approximately $1.0 million, $0.5 million and $1.4 million, respectively. No amounts were paid by CRNF to CRRM for any of the years presented.
The agreement also provides a mechanism pursuant to which CRNF transfers a tail gas stream to CRRM. For the years ended December 31, 2014, 2013 and 2012 CRRM recognized approximately $0.1 million, $0.2 million and $0.2 million, respectively, of direct operating expenses generated from the purchase of tail gas from CRNF.
In April 2011, in connection with the tail gas stream, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF has agreed to pay CRRM the cost of installing the pipe over the next three years and in the fourth year provide an additional 15% to cover the cost of capital. At December 31, 2014 and 2013, an asset of approximately $0.1 million and $0.3 million, respectively, was included in other current assets and approximately $0 and $0.1 million, respectively, was included in other non-current assets with an offset liability of approximately $0.2 million in other current liabilities and approximately $1.0 million and $1.1 million, respectively, in other non-current liabilities in the Consolidated Balance Sheets.
The agreement has an initial term of 20 years, 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 the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
At December 31, 2014 and 2013, 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. At December 31, 2014 and 2013, receivables of approximately $1.1 million and $1.0 million, respectively, were included in prepaid expenses and other
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current assets on the Consolidated Balance Sheets associated with receivables related to components of the feedstock and shared services agreement.
Coke Supply Agreement
CRRM entered into 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 percent 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"), or the UAN-based price, and 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 (exclusive of transportation cost), or 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.
The agreement has an initial term of 20 years 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 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 the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
Net sales associated with the transfer of pet coke from CRRM to CRNF were approximately $8.7 million, $9.6 million and $9.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. Receivables of approximately $0.5 million and $0.6 million related to the coke supply agreement were included in accounts receivable on the Consolidated Balance Sheets at December 31, 2014 and 2013, respectively.
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 agreement provides for indemnification in the case of contamination or releases of hazardous materials that were present but unknown at the time the agreement was entered into to the extent such contamination or releases were identified in reasonable detail through October 2012. The agreement further provides for indemnification in the case of contamination or releases which occur subsequent to the execution of the agreement.
The term of the agreement is for at least 20 years, or for so long as the feedstock and shared services agreement is in force, whichever is longer.
Services Agreement
On December 31, 2012, CVR Refining entered into a services agreement with CVR Energy. 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 conduct a substantial
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portion of its day-to-day business operations. CVR Energy provides CVR Refining with the following services under the agreement, 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 shall 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 services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
• | management of the Partnership's property and the property of its operating subsidiaries in the ordinary course of business; |
• | 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. |
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, other than administrative personnel, 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, including administrative personnel, 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. Beginning in January 2014, either 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 its 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.
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Net amounts incurred under the services agreement for the years ended December 31, 2014 and 2013 were as follows:
December 31, | |||||||
2014 | 2013 | ||||||
(in millions) | |||||||
Direct operating expenses (exclusive of depreciation and amortization) | $ | 21.3 | $ | 25.2 | |||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 50.8 | 62.1 | |||||
Total | $ | 72.1 | $ | 87.3 | |||
At December 31, 2014 and 2013, payables and liabilities of $13.6 million and $14.8 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. See Note 3 ("Summary of Significant Accounting Policies") - "Allocation of Costs" for costs allocated to CVR Refining for the year ended December 31, 2012 prior to this services agreement going into effect.
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.
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, 2014 and 2013, approximately $6.0 million and $0.3 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.
As of December 31, 2014, the Partnership had borrowings of $31.5 million outstanding. For the years ended December 31, 2014 and 2013, the Partnership paid $1.0 million and $0.1 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.
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
International Truck Purchase
During the year ended December 31, 2013, the Refining Partnership purchased seven trucks from a subsidiary of Navistar International Corporation ("Navistar") for approximately $0.8 million.
(16) Major Customers and Suppliers
Sales to major customers were as follows:
Year Ended December 31, | ||||||||
2014 | 2013 | 2012 | ||||||
Customer A | 13 | % | 12 | % | 10 | % | ||
CRRM obtained crude oil from one third-party supplier under a long-term supply agreement during 2014, 2013 and 2012. 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, | ||||||||
2014 | 2013 | 2012 | ||||||
Supplier A | 67 | % | 69 | % | 45 | % | ||
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
(17) Selected Quarterly Financial Information (unaudited)
Summarized quarterly financial data for December 31, 2014 and 2013:
Year Ended December 31, 2014 | |||||||||||||||
Quarter | |||||||||||||||
First | Second | Third | Fourth | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Net sales | $ | 2,375.3 | $ | 2,466.3 | $ | 2,215.2 | $ | 1,772.8 | |||||||
Operating costs and expenses: | |||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 2,063.3 | 2,172.6 | 2,053.7 | 1,723.8 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 99.2 | 93.2 | 110.6 | 112.9 | |||||||||||
Selling, general and administrative (exclusive of depreciation and amortization) | 18.7 | 17.9 | 17.3 | 16.8 | |||||||||||
Depreciation and amortization | 29.5 | 30.7 | 29.7 | 32.6 | |||||||||||
Total operating costs and expenses | 2,210.7 | 2,314.4 | 2,211.3 | 1,886.1 | |||||||||||
Operating income (loss) | 164.6 | 151.9 | 3.9 | (113.3 | ) | ||||||||||
Other income (expense): | |||||||||||||||
Interest expense and other financing costs | (8.7 | ) | (7.9 | ) | (7.9 | ) | (9.7 | ) | |||||||
Interest income | 0.1 | 0.1 | 0.1 | 0.1 | |||||||||||
Gain on derivatives, net | 109.4 | 35.9 | 25.7 | 14.5 | |||||||||||
Other expense, net | — | — | — | (0.1 | ) | ||||||||||
Total other income | 100.8 | 28.1 | 17.9 | 4.8 | |||||||||||
Income (loss) before income tax expense | 265.4 | 180.0 | 21.8 | (108.5 | ) | ||||||||||
Income tax expense | — | — | — | — | |||||||||||
Net income (loss) | $ | 265.4 | $ | 180.0 | $ | 21.8 | $ | (108.5 | ) | ||||||
Net income (loss) per common unit - basic | $ | 1.80 | $ | 1.22 | $ | 0.15 | $ | (0.73 | ) | ||||||
Net income (loss) per common unit - diluted | $ | 1.80 | $ | 1.22 | $ | 0.15 | $ | (0.73 | ) | ||||||
Weighted-average common units outstanding: | |||||||||||||||
Basic | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
Diluted | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
Year Ended December 31, 2013 | |||||||||||||||
Quarter | |||||||||||||||
First | Second | Third | Fourth | ||||||||||||
(in millions, except per unit data) | |||||||||||||||
Net sales | $ | 2,274.0 | $ | 2,138.1 | $ | 1,910.5 | $ | 2,360.9 | |||||||
Operating costs and expenses: | |||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 1,805.8 | 1,776.6 | 1,734.7 | 2,209.7 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 86.0 | 83.8 | 104.7 | 87.2 | |||||||||||
Selling, general and administrative (exclusive of depreciation and amortization) | 18.6 | 20.2 | 18.9 | 20.0 | |||||||||||
Depreciation and amortization | 28.0 | 28.4 | 28.8 | 29.1 | |||||||||||
Total operating costs and expenses | 1,938.4 | 1,909.0 | 1,887.1 | 2,346.0 | |||||||||||
Operating income | 335.6 | 229.1 | 23.4 | 14.9 | |||||||||||
Other income (expense): | |||||||||||||||
Interest expense and other financing costs | (14.2 | ) | (10.6 | ) | (10.0 | ) | (9.3 | ) | |||||||
Interest income | 0.1 | 0.1 | 0.1 | 0.1 | |||||||||||
Gain (loss) on derivatives, net | (20.0 | ) | 120.5 | 72.5 | (115.9 | ) | |||||||||
Loss on extinguishment of debt | (26.1 | ) | — | — | — | ||||||||||
Other income, net | — | 0.1 | — | — | |||||||||||
Total other income (expense) | (60.2 | ) | 110.1 | 62.6 | (125.1 | ) | |||||||||
Income (loss) before income tax expense | 275.4 | 339.2 | 86.0 | (110.2 | ) | ||||||||||
Income tax expense | — | — | — | — | |||||||||||
Net income (loss) | $ | 275.4 | $ | 339.2 | $ | 86.0 | $ | (110.2 | ) | ||||||
Net income subsequent to initial public offering (January 23, 2013 - March 31, 2013) | $ | 197.5 | |||||||||||||
Net income (loss) per common unit - basic(1) | $ | 1.34 | $ | 2.30 | $ | 0.58 | $ | (0.75 | ) | ||||||
Net income (loss) per common unit - diluted(1) | $ | 1.34 | $ | 2.30 | $ | 0.58 | $ | (0.75 | ) | ||||||
Weighted-average common units outstanding: | |||||||||||||||
Basic | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
Diluted | 147.6 | 147.6 | 147.6 | 147.6 | |||||||||||
(1) | For the first quarter 2013, reflective of net income per common unit from the closing of the Partnership's initial public offering on January 23, 2013 through March 31, 2013. |
Factors Impacting the Comparability of Quarterly Results of Operations
As discussed in Note 7 ("Insurance Claims"), the fire at the Coffeyville refinery's isomerization unit adversely impacted production of refined products 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 and are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
During the fourth quarter of 2014, the FCCU at the Wynnewood refinery was offline for approximately 16 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at the Wynnewood refinery was significantly reduced during the fourth quarter of 2014. Additionally, the Partnership incurred approximately $8.5 million in
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CVR REFINING, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS (Continued)
costs to repair the FCCU for the year ended December 31, 2014. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
As discussed in Note 5 ("Inventories"), the Partnership recorded a lower of FIFO cost or market inventory adjustment of approximately $36.8 million during the fourth quarter of 2014, which is included in cost of product sold (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
During the third quarter of 2013, the FCCU at the Coffeyville refinery was offline for approximately 55 days for necessary repairs. As a result of the FCCU outage, crude throughput and production at the Coffeyville refinery was significantly reduced during the third quarter of 2013. Additionally, the Partnership incurred approximately $21.1 million in costs to repair the FCCU for the year ended December 31, 2013. These costs are included in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated and Combined Statements of Operations.
(18) Subsequent Events
Distribution
On February 18, 2015, the board of directors of the Partnership's general partner declared a cash distribution for the fourth quarter of 2014 to the Partnership's unitholders of $0.37 per common unit, or $54.6 million in aggregate. The cash distribution will be paid on March 9, 2015 to unitholders of record at the close of business on March 2, 2015.
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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, 2014, 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 SEC'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, 2014. 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, 2014 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, LLC ("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.
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 initially consisted of 11 directors in 2014, but currently consists of 10 directors, three of whom at all times the board has affirmatively determined are independent in accordance with the rules of the NYSE. The board of directors of our general partner met two times in 2014, and acted by consent 15 times. All of the directors who served during 2014 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, except that Mr. Shea was absent from our board meetings. Effective February 18, 2014, Keith Cozza resigned from, and Andrew Roberto was concurrently appointed to, the board of directors of our general partner. Effective May 19, 2014, Samuel Merksamer resigned from, and Courtney Mather was concurrently appointed to, the board of directors of our general partner. Stanley A. Riemann resigned from the board of directors of our general partner effective June 30, 2014 in connection with his retirement. Effective September 12, 2014, Vincent J. Intrieri and Daniel A. Ninivaggi resigned from, and on September 16, 2014 Andrew Langham and Louis J. Pastor were appointed to, the board of directors of our general partner.
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 review our accounting and auditing principles and procedures, accounting functions and internal controls; to oversee the qualifications, independence, appointment, retention, compensation and performance of our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent accountants; to review with the independent accountants the plans and results of the auditing engagement; and to oversee "whistle-blowing" procedures and certain other compliance matters. 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 six times in 2014.
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
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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 one time in 2014.
The board of directors of our general partner has also established a compensation committee. During 2014, the compensation committee was initially comprised of Vincent J. Intrieri (chairman), Samuel Merksamer and Daniel A. Ninivaggi. Mr. Merksamer resigned from the board of directors of our general partner on May 19, 2014 and Messrs. Intrieri and Ninivaggi resigned on September 12, 2014. The compensation committee currently consists of Andrew Roberto (chairman) and Andrew Langham. The compensation committee (1) establishes policies and periodically determines matters involving executive compensation, (2) grants or recommends the grant of equity awards under the CVR Refining LTIP, (3) provides counsel regarding key personnel selection, (4) may elect to retain independent compensation consultants, (5) recommends to the board of directors the structure of non-employee director compensation and (6) 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 2014.
The board of directors of our general partner has created an environmental, health and safety committee. During 2014, the environmental, health and safety committee initially consisted of Jon R. Whitney (chairman), Stanley A. Riemann and Keith Cozza. Mr. Cozza resigned from the board of directors of our general partner on February 18, 2014 and Mr. Riemann resigned on June 30, 2014 in connection with his retirement. The environmental, health and safety committee currently consists of Jon R. Whitney (chairman) and Andrew Roberto. 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 2014.
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 2014, three of our 10 directors were independent, and nine of our 10 directors were non-management. Our independent directors met during one executive session in 2014. Mr. Zander (independent) presided over the executive session held by our independent directors. Our non-management directors did not meet in executive session in 2014. 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: Senior 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 2014 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 17, 2015) 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 CVR Partners' general partner, 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 2014 are as follows: John J. Lipinski (45%), Susan M. Ball (55%), Martin J. Power (95%), John R. Walter (48%), Robert W. Haugen (90%) and David L. Landreth (100%).
Effective February 18, 2014, Keith Cozza resigned from, and Andrew Roberto was concurrently appointed to, the board of directors of our general partner. Effective May 19, 2014, Samuel Merksamer resigned from, and Courtney Mather was concurrently appointed to, the board of directors of our general partner. Stanley A. Riemann resigned from the board of directors of our general partner effective June 30, 2014 in connection with his retirement. Effective September 12, 2014, Vincent J. Intrieri and Daniel A. Ninivaggi resigned from, and on September 16, 2014 Andrew Langham and Louis J. Pastor were appointed to, the board of directors of our general partner.
Name | Age | Position With Our General Partner | |||
John J. Lipinski | 63 | Chief Executive Officer and President, Director | |||
Susan M. Ball | 51 | Chief Financial Officer and Treasurer | |||
John R. Walter | 38 | Senior Vice President, General Counsel and Secretary | |||
Robert W. Haugen | 56 | Executive Vice President, Refining Operations | |||
David L. Landreth | 58 | Senior Vice President, Economics and Planning | |||
Martin J. Power | 59 | Chief Commercial Officer | |||
Carl C. Icahn | 79 | Director | |||
SungHwan Cho | 40 | Director | |||
Andrew Langham | 41 | Director | |||
Courtney Mather | 37 | Director | |||
Louis J. Pastor | 30 | Director | |||
Kenneth Shea | 56 | Director | |||
Andrew Roberto | 28 | Director | |||
Jon R. Whitney | 70 | Director | |||
Glenn R. Zander | 67 | Director | |||
John J. Lipinski has served as the chief executive officer and president of our general partner, as well as a director of our general partner, since our inception in September 2012. In addition, he has served as CVR Energy's chief executive officer and president and as a member of its board of directors since September 2006, and previously served as the Chairman of its board of directors from April 2009 until May 2012. In addition, Mr. Lipinski has served as chairman of the board of the general partner of CVR Partners since November 2010, executive chairman of the general partner of CVR Partners since June 2011 and as chief executive officer and president of the general partner of CVR Partners from October 2007 to June 2011 and from January 2014 to May 2014. He has been a director of the general partner of CVR Partners since October 2007. Mr. Lipinski has over 40 years of experience in the petroleum refining industry. He began his career with Texaco Inc. In 1985, Mr. Lipinski joined The Coastal Corporation, eventually serving as Vice President of Refining with overall responsibility for Coastal Corporation's refining and petrochemical operations. Upon the merger of Coastal with El Paso Corporation in 2001, Mr. Lipinski was promoted to Executive Vice President of Refining and Chemicals, where he was responsible for all refining, petrochemical, nitrogen-based chemical processing and lubricant operations, as well as the corporate engineering and
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construction group. Mr. Lipinski left El Paso in 2002 and became an independent management consultant. In 2004, he became a managing director and partner of Prudentia Energy, an advisory and management firm. Mr. Lipinski currently serves on the board of directors of Chesapeake Energy Corporation, an oil and gas exploration and production company. Mr. Lipinski graduated from Stevens Institute of Technology with a bachelor's degree in Engineering (chemical) and received a Juris Doctor degree from Rutgers University School of Law. Mr. Lipinski's over 40 years of experience in the petroleum refining industry adds significant value to the board of directors of our general partner, and his in-depth knowledge of the issues, opportunities and challenges facing us provides the direction and focus the board needs to ensure the most critical matters are addressed.
Susan M. Ball has served as chief financial officer and treasurer of our general partner since our inception in September 2012. Ms. Ball has also served as the chief financial officer and treasurer of CVR Energy and of the general partner of CVR Partners since August 2012, and prior to that, 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 Coffeyville Resources, LLC ("CRLLC") since May 2006. 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.
John R. Walter has served as senior vice president, general counsel and secretary of CVR Energy, Inc. and each of the general partners of CVR Refining, LP and CVR Partners, LP since January 2015. 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 Morrison Hecker LLP in Kansas City Missouri from 2006 to 2008, and was an associate at Seigfreid, Bingham, Levy, Selzer & Gee, 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.
Robert W. Haugen has served as executive vice president, refining operations of our general partner since our inception in September 2012. Mr. Haugen joined CVR Energy on June 24, 2005 and has served as executive vice president, refining operations at CVR Energy since September 2006. He served as executive vice president — engineering & construction at CRLLC since June 24, 2005. Mr. Haugen brings more than 30 years of experience in the refining, petrochemical and nitrogen fertilizer business to CVR Energy. Prior to joining us, Mr. Haugen was a managing director and Partner of Prudentia Energy, an advisory and management firm focused on mid-stream/downstream energy sectors, from January 2004 to June 2005. On leave from Prudentia, he served as the Senior Oil Consultant to the Iraqi Reconstruction Management Office for the U.S. Department of State. Prior to joining Prudentia Energy, Mr. Haugen served in numerous engineering, operations, marketing and management positions at the Howell Corporation and at the Coastal Corporation. Upon the merger of Coastal and El Paso in 2001, Mr. Haugen was named Vice President and General Manager for the Coastal Corpus Christi Refinery and later held the positions of Vice President of Chemicals and Vice President of Engineering and Construction. Mr. Haugen received a Bachelor of Science degree in Chemical Engineering from the University of Texas.
David L. Landreth has served as senior vice president, economics and planning of our general partner since our inception in September 2012. Mr. Landreth has also served as vice president, economics and planning of Coffeyville Resources Refining & Marketing, LLC since January 2009. 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. Before joining CRLLC in 2005, 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.
Martin J. Power serves as chief commercial officer for our general partner, as well as chief commercial officer for the CVR Energy. Mr. Power has more than 35 years of experience in the areas of crude oil and petroleum products related to trading, marketing, logistics and business development. Before joining CVR Energy, he served as manager of business development and as a trading manager at Koch Supply & Trading, LP. Previous to Koch, Mr. Power was co-founder and president of Riverway Petroleum Partners, LLC, a petroleum products trading and logistics company. Prior to Riverway Petroleum Partners, Mr. Power spent much of his career in senior management roles for major petroleum companies. He served as managing director of light products and managing director of crude oil for El Paso Merchant Energy; vice president of trading, vice president of foreign crude and senior vice president of light products for Coastal States Trading; and as a senior
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trader for BP North America Petroleum and BP Oil Supply. Mr. Power holds a Bachelor of Science in Business Administration - Accounting from Nichols College and serves on its Board of Trustees.
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, real estate and home fashion). Mr. Icahn has been: chairman of the board of CVR Refining, LP, an independent downstream energy limited partnership, since January 2013; chairman of the board of CVR Energy, Inc., a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries, 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; a director of Federal−Mogul Corporation, a supplier of automotive powertrain and safety components, since December 2007, and the non-executive chairman of the board of Federal-Mogul since January 2008; 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: 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; 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; a director of Blockbuster Inc., a provider of in-home movie rental and game entertainment, from May 2005 to January 2010; a director of Voltari Corporation, a mobile data services provider, from April 2008 to January 2010; a director of Yahoo! Inc., a company that provides Internet services to users, advertisers, publishers and developers worldwide, from August 2008 to October 2009; and a director of WCI Communities, Inc., a homebuilding company, from August 2007 to September 2009, and was chairman of the board of WCI from September 2007 to September 2009. 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, 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 since October 2006. Mr. Cho has been a director of: American Railcar Leasing LLC, a lessor and seller of specialized railroad tank and covered hopper railcars, since September 2013; CVR Refining, LP, an independent downstream energy limited partnership, since January 2013; Icahn Enterprises L.P., since September 2012; CVR Energy, Inc., a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries, since May 2012; CVR Partners LP, a nitrogen fertilizer company, since May 2012; Federal-Mogul Corporation, a supplier of automotive powertrain and safety components, since May 2012; XO Holdings, a competitive provider of telecom services, since August 2011; 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); WestPoint Home LLC, a home textiles manufacturer, since January 2008; PSC Metals Inc., a metal recycling company, since December 2006; and Viskase Companies, Inc., a meat casing company, since November 2006. Mr. Cho was previously a director of Take-Two Interactive Software Inc., a publisher of interactive entertainment products, from April 2010 to November 2013. American Railcar Leasing, CVR Refining, Icahn Enterprises, CVR Energy, CVR Partners, Federal-Mogul, XO Holdings, American Railcar Industries, WestPoint Home, PSC Metals and Viskase Companies each are indirectly controlled by Carl C. Icahn. Mr. Icahn also had a non−controlling interest in 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.
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.
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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.
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 upon 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.
Kenneth Shea has been a member of the board of directors of our general partner since January 2013. Mr. Shea is the 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, and Hydra Industries Acquisition Corp., a special purpose acquisition company. 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.
Andrew Roberto, CFA, has served as an Analyst at Icahn Enterprises L.P. since May 2012. Icahn Enterprises is a diversified holding company engaged in a variety of businesses, including investment, automotive, energy, gaming, railcar, food packaging, metals, real estate and home fashion. Mr. Roberto is responsible for identifying, analyzing and monitoring investment opportunities and portfolio companies for Icahn Enterprises. Prior to joining Icahn Enterprises, Mr. Roberto served as a research analyst at RBS Securities covering the automotive, industrial, coal, homebuilding and building products sectors as a member of the high yield and distressed debt trading team. Mr. Roberto began his career at AllianceBernstein, where he focused on client services and relationship management. Mr. Roberto has been a director of: Voltari Corporation, a mobile data services provider, since August 2014; American Railcar Industries, Inc., a railcar manufacturing company, since February 2014; CVR Energy, Inc., a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries, since February 2014; CVR Partners LP, a nitrogen fertilizer company, since February 2014; CVR Refining, LP, an independent downstream energy limited partnership, since February 2014; WestPoint Home LLC, a home textiles manufacturer, since February 2014; and Viskase Companies, Inc., a meat casing company, since February 2014. Mr. Roberto was previously a director of American Railcar Leasing LLC, a lessor and seller of specialized railroad tank and covered hopper railcars, from February 2014 to June 2014. American Railcar Industries, American Railcar Leasing, CVR Energy, CVR Partners, Westpoint Home and Viskase are each indirectly controlled by Carl C. Icahn. Mr. Icahn also has a non−controlling interest in Voltari through the ownership of securities. Mr. Roberto received his B.A. in Economics from Williams College and is a CFA Charterholder. Based upon Mr. Roberto's strong financial background and experience as an analyst, we believe that Mr. Roberto has the requisite set of skills to serve as a member of our board.
Courtney Mather has served as a Managing Director of Icahn Capital LP, the entity through which Carl C. Icahn manages investment funds, since April 2014. Mr. Mather is responsible for identifying, analyzing, and monitoring investment opportunities and portfolio companies for Icahn Capital. Prior to joining Icahn Capital, Mr. Mather was Managing Director at Goldman Sachs & Co, where he served in various investment roles from 1998 to 2012. He was a director of the Loan Syndications and Trading Association (LSTA), an organization that develops policies and market practices with firms transacting in loans and related claims, in 2011. Mr. Mather has been a director of: American Railcar Industries, Inc., a railcar manufacturing company, since July 2014; CVR Refining, LP, an independent downstream energy limited partnership, since May 2014; and CVR Energy, Inc., a diversified
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holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries, since May 2014. American Railcar Industries, CVR Refining and CVR Energy are each indirectly controlled by Carl C. Icahn. Mr. Mather received a B.A. in Political Science from Rutgers College and attended the United States Naval Academy. We believe Mr. Mather's strong financial background and experience will be an asset to 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, real estate and home fashion) since January 2015. From 2005 to January 2015, 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: CVR Refining, LP, an independent downstream energy limited partnership, since September 2014; and CVR Energy, Inc., a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries, since September 2014. CVR Refining and CVR Energy are each indirectly controlled by Carl C. Icahn. Mr. Langham received a B.A. in 1995 from Whitman College and a J.D. from the University of Washington in 2000. 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 Assistant 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, real estate and home fashion) since May 2013. 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 Refining, LP, an independent downstream energy limited partnership, since September 2014. CVR Refining is indirectly controlled by Carl C. Icahn. Mr. Pastor received a B.A. in 2006 from The Ohio State University and a J.D. in 2009 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.
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 and the NYSE. 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 2014. 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 2014, with the exceptions noted below.
One Form 4 and one amendment to Form 4, covering one transaction each, were filed late for each of Susan M. Ball, Edmund S. Gross (a former officer), Robert W. Haugen, Wyatt E. Jernigan (a former officer) and Christopher G. Swanberg (a former officer).
Corporate Governance Guidelines and Codes of Ethics
Our Corporate Governance Guidelines, as well as our Code of Ethics, which applies to all of our directors, officers and employees, and our Senior Officer Code of Ethics, which applies 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.
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Item 11. Executive Compensation
Compensation Discussion and Analysis
Overview
We were formed in September 2012 for the purpose of holding the petroleum refining and logistics assets which, prior to the Initial Public Offering in January 2013, comprised a portion of the assets of CVR Energy. 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 senior vice president, economics and planning. The remaining executive officers that are responsible for managing our day-to-day affairs are executive officers of, and are employed by, CVR Energy, including John J. Lipinski (our chief executive officer and president), Susan M. Ball (our chief financial officer and treasurer), Robert W. Haugen (our executive vice president, refining operations) and Martin J. Power (our chief commercial officer). Throughout this Annual Report, we refer to Mr. Lipinski, Ms. Ball and Messrs. Haugen, 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 2014 are as follows: John J. Lipinski (45%); Susan M. Ball (55%); Robert W. Haugen (90%); 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 or CVR Partners.
During 2014, Mr. Lipinski, Ms. Ball, and Messrs. Haugen 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 2014 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 such services agreement, we are required to pay all compensation amounts allocated to us by CVR Energy, except for certain share-based compensation awarded by CVR Energy prior to December 2013, although we may object to amounts that we deem unreasonable. We also pay our allocated portion of performance units and incentive units issued by CVR Energy in December 2013 to those personnel providing services to the Partnership via the services agreement.
Prior to 2013, neither we nor our general partner reimbursed CVR Energy for the portion of the compensation paid to the named executive officers attributable to services performed for our business. However, we entered into a services agreement with our general partner and CVR Energy in connection with the Initial Public Offering, which provides, among other matters, that:
• | 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, with the exception of costs attributable to certain share-based compensation awarded by CVR Energy prior to December 2013. As noted above, we also pay our allocated portion of performance units and incentive units issued by CVR Energy in December 2013 and during 2014 to those personnel 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, other than administrative personnel, 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, including administrative personnel, 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. 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
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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."
With the exception of Mr. Landreth, (who is employed by and whose compensation is determined by, our general partner), during 2014 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 following the Initial Public Offering 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, 2014 compensation for Mr. Lipinski, Ms. Ball and Messrs. Haugen and Power was set by CVR Energy, while the 2014 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 2014 compensation of the named executive officer who was an employee of our general partner through December 31, 2014, 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 2014, 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.
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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.
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 chief executive officer of CVR Refining, while not a member of the compensation committee, reviews information provided by the committee's 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 on behalf of its compensation committee to assist the committee with benchmarking of certain executive compensation levels and to generally assess the level of compensation increases from 2013 to 2014 and 2015. The compensation committee utilized this information, in addition to Longnecker's 2013 study, to review and approve executive compensation levels. Longnecker's 2013 study included an analysis regarding executive compensation levels and the mix of compensation as compared to peer companies, companies of similar size and other relevant market information. Management reviewed this compilation of information and then provided it to the compensation committee for its use in making decisions regarding the salary, bonus and other compensation amounts paid to named executive officers. The following companies were included in the 2013 report and analysis prepared by Longnecker as members of CVR Energy's and CVR Refining's "peer group" — the independent refining companies of HollyFrontier Corporation and Tesoro Corporation, as well as PBF Energy, Inc. and Rentech, Inc. Although no specific target for total compensation or any particular element of compensation was set relative to CVR Refining's peer group, the focus of Longnecker's 2013 recommendations was centered on compensation levels between the 50th and 75th percentile of the peer group.
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) peer or market 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 survey and peer group data prepared by Longnecker 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 2014 in conjunction with his responsibilities and expectations for 2015. They concluded their review in December 2014, and set the base salary for Mr. Landreth of $265,000 as of January 1, 2015. Individual performance, the practices of our peer group of companies as reflected in the analysis and report of Longnecker, 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 the report and findings of Longnecker.
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.
Information about total cash compensation paid by members of CVR Refining's peer group 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
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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 2014, the target bonus for David L. Landreth was 80%. This target percentage was the result of individual negotiations between the named executive officer and CVR Refining, and was in correlation with the findings and recommendations by Longnecker based upon review of CVR Refining's peer group, companies of similar size and other relevant market information. 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 2014 performance pursuant to the CVR Energy Inc. Performance Incentive Plan (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. Haugen’s annual bonus (at a target of 120%) is also evaluated based on these metrics due to the 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 2014 performance year to the named executive officers depended on the achievement of financial, operational and safety measures, which comprised 30%, 50% and 20% of the annual bonuses, respectively. Specific bonus measures were determined by the compensation committee based on its review of peer group information provided by Longnecker 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 will be made with respect to the measures unless the threshold of the relevant performance measure is achieved.
The 2014 financial measure was adjusted EBITDA for the refining business, which was derived from refining earnings before interest, taxes, depreciation and amortization, and adjusted for total cash and non-cash share-based compensation expense, loss on extinguishment of debt, turnaround expenses and gain/loss on derivatives.
The 2014 operational measures were petroleum reliability for the Coffeyville and Wynnewood refineries, measured by crude throughput barrels per day.
The 2014 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 for petroleum operations); air reportable release quantity (based upon EPA reportable quantity releases for petroleum operations); tier 1 process safety events (based upon API process safety events of petroleum operations); tier 1 severity (based on API process safety events of petroleum operations); tier 2 process safety events (based upon API process safety events 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: (i) the financial, operational and safety measures used to determine 2014 bonuses for Messrs. Haugen and Landreth; (ii) the threshold, target and maximum performance levels for each measure; (iii) the actual results with respect to each measure; and (iv) the portion of the 2014 bonus determined based on each such measure. Messrs. Haugen and Landreth could have received 0% or 50% for threshold levels, 100% for target levels, and 150% for maximum levels, respectively.
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2014 Performance Measure | 2014 Performance Goals Threshold/Target/Maximum | 2014 Actual Results | Portion of Target Bonus Allocable to Measure | |||
Consolidated adjusted EBITDA — Petroleum business | Threshold: $468.7 million Target: $669.6 million Maximum: $1,004.4 million | $627.3 million | 30% of bonus for Messrs. Haugen and Landreth | |||
Coffeyville petroleum reliability measures | Threshold: 105,000 bpd Target: 111,000 bpd Maximum: 117,000 bpd | 119,704 bpd | 30% of bonus for Messrs. Haugen and Landreth | |||
Wynnewood petroleum reliability measures | Threshold: 61,000 bpd Target: 66,000 bpd Maximum: 71,000 bpd | 76,841 bpd | 20% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated OSHA recordable injury statistics | Threshold: 11 recordable events Target: 8 recordable events Maximum: 4 recordable events | 15 recordable events | 2% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated OSHA lost time injury statistics | Threshold: 6 recordable events Target: 3 recordable events Maximum: 0 recordable events | 11 recordable events | 2% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated EH&S severity statistics | Threshold: 5 recordable events Target: 2 recordable events Maximum: 0 recordable events | 4 recordable events | 2% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated air reportable release | Threshold: 38 recordable events Target: 32 recordable events Maximum: 26 recordable events | 21 recordable events | 1% of bonus for Messrs. Haugen and Landreth | |||
Consolidated air reportable release quantity | Threshold: 1,060,451 pounds Target: 795,339 pounds Maximum: 530,226 pounds | 107,389 pounds | 3% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated Tier 1 process safety events | Threshold: 4 recordable events Target: 2 recordable events Maximum: 0 recordable events | 5 recordable events | 2% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated Tier 1 Severity process safety events | Threshold: 4 recordable events Target: 2 recordable events Maximum: 0 recordable events | 1 recordable event | 1% of bonus for Messrs. Haugen and Landreth | |||
Petroleum consolidated Tier 2 process safety events | Threshold: 6 recordable events Target: 4 recordable events Maximum: 2 recordable events | 8 recordable events | 2% of bonus for Messrs. Haugen and Landreth | |||
Reportable quantity spills — Pipeline | Threshold: 4 recordable events Target: 3 recordable events Maximum: 2 recordable events | 0 recordable events | 0.5% of bonus for Messrs. Haugen and Landreth | |||
Spills to Waters of U.S. — Pipeline | Threshold: 2 recordable events Target: 1 recordable events Maximum: 0 recordable events | 1 recordable event | 1% of bonus for Messrs. Haugen and Landreth | |||
Reportable Quantity Spills — Trucking | Threshold: 2 recordable events Target: 1 recordable events Maximum: 0 recordable events | 1 recordable event | 0.5% of bonus for Messrs. Haugen and Landreth | |||
Spills to Waters of U.S. — Trucking | Threshold: 2 recordable events Target: 1 recordable events Maximum: 0 recordable events | 0 recordable events | 1% of bonus for Messrs. Haugen and Landreth | |||
Trucking Incidents — On Road | Threshold: 3 recordable events Target: 2 recordable events Maximum: 1 recordable events | 1 recordable events | 1% of bonus for Messrs. Haugen and Landreth | |||
Trucking Incidents — Severity | Threshold: 1 recordable events Target: 0 recordable events Maximum: 0 recordable events | 1 recordable event | 1% of bonus for Messrs. Haugen and Landreth | |||
As a result of these levels of performance, Messrs. Haugen and Landreth earned approximately 114.34%, of their respective target bonuses.
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
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partner for its approval, as determined by the committee in its discretion. In 2014, 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 2014 was less than $10,000.
CVR Energy's Compensation Programs
The following discussion relates to the 2014 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 Mr. Lipinski, Ms. Ball and Messrs. Haugen and Power. In addition, all references to the compensation committee refer to the compensation committee of the board of directors of CVR Energy.
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 2014, 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.
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 chief executive officer of CVR Energy, while not a member of the compensation committee, reviews information provided by the committee's 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 has been engaged by CVR Energy on behalf of its compensation committee to assist the committee with benchmarking of certain executive compensation levels and to generally assess the level of compensation increases from 2013 to 2014 and 2015. The compensation committee utilized this information, in addition to Longnecker's 2013 study, to review and approve executive compensation levels. Longnecker's 2013 study included an analysis regarding executive compensation levels and the mix of compensation as compared to peer companies, companies of similar size and other relevant market information. Management reviewed this compilation of information and then provided it to the compensation committee for its use in making decisions regarding the salary, bonus and other compensation amounts paid to named executive officers. The following companies were included in the 2013 report and analysis prepared by Longnecker as members of CVR Energy's "peer group" — the independent refining companies of HollyFrontier Corporation and Tesoro Corporation, as well as PBF Energy, Inc. and Rentech, Inc. Although no specific target for total compensation or any particular element of compensation
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was set relative to CVR Energy's peer group, the focus of Longnecker's 2013 recommendations was centered on compensation levels between the 50th and 75th percentile of the peer group.
Base Salary. Each of the named executive officers has an employment agreement with CVR Energy that sets forth their initial base salaries. 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) peer or market 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 survey and peer group data prepared by Longnecker 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, with the assistance of Longnecker, most recently reviewed the level of base salary and cash bonus for each of the named executive officers in 2014 in conjunction with their responsibilities and expectations for 2015. They concluded their review in December 2014, and set the following base salaries for the named executive officers as of January 1, 2015: $1,000,000 for Mr. Lipinski (which is not a change from his 2014 salary); $415,000 for Ms. Ball; $350,000 for Mr. Haugen; and $325,000 for Mr. Power (which was set in connection with his initial employment agreement effective December 1, 2014). Individual performance, the practices of our peer group of companies as reflected in the analysis and report of Longnecker, and changes in the named executive officers' positions and levels of responsibility were considered. Among these three factors, slightly more weight was given to the report and findings of Longnecker.
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 peer group 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 2014, the target bonuses for the named executive officers were: John J. Lipinski (250%); Susan M. Ball (100%); and Robert W. Haugen (120%). Martin J. Power's employment with CVR Energy began effective December 1, 2014 and, as such, he was not eligible to receive an annual cash bonus for 2014. These target percentages were the result of individual negotiations between the named executive officers and CVR Energy, and were in correlation with the findings and recommendations by Longnecker based upon review of CVR Energy's peer group, companies of similar size and other relevant market information. Specific bonus measures were determined by the compensation committee, following discussions with CVR Energy management.
Each named executive officer (except for Mr. Power, who joined CVR Energy effective December 1, 2014) had the opportunity to earn bonuses in respect of 2014 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. Haugen’s annual bonus is evaluated based on these metrics (and approved by our compensation committee) due to the substantial amount of his time that is devoted to CVR Refining. These metrics and the annual bonus earned by Mr. Haugen is described above in "Annual Bonus" under “CVR Refining’s Compensation Programs”. The payment of annual bonuses for the 2014 performance year to the named executive
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officers will depend on the achievement of financial, operational and safety measures, which comprised 30%, 50% and 20% of the annual bonuses, respectively. Specific bonus measures were determined by the compensation committee based on its review of peer group information provided by Longnecker 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 will be made with respect to the measures unless the threshold of the relevant performance measure is achieved.
The 2014 financial measure was consolidated adjusted EBITDA for CVR Energy, which was derived from earnings before interest, taxes, depreciation and amortization, and adjusted for total cash and non-cash share-based compensation expense, first-in, first-out (FIFO) accounting impacts, unrealized gains on derivative transactions, turnaround expenses and board directed actions.
The 2014 operational measures were petroleum reliability for the total Coffeyville and Wynnewood refineries, measured by crude throughput barrels per day.
The 2014 safety measures include the aggregated EH&S results for the petroleum segment pursuant to the CVR Energy PIP and for the nitrogen fertilizer segment pursuant to the CVR Partners PIP, which include the following: consolidated OSHA recordable injury statistics (based upon enterprise-wide OSHA injuries and inclusive of petroleum, fertilizer and crude transportation); consolidated OSHA lost time injury statistics (based upon enterprise-wide OSHA lost time injuries and inclusive of petroleum, fertilizer and crude transportation); consolidated EH&S severity statistics (based upon enterprise-wide EH&S severity and inclusive of petroleum, fertilizer and crude transportation); consolidated air reportable releases (based upon enterprise-wide EPA reportable quantity releases and inclusive of petroleum and fertilizer operations); consolidated air reportable release quantity (based upon enterprise-wide EPA reportable quantity releases and inclusive of petroleum and fertilizer operations); consolidated tier 1 process safety events (based upon enterprise-wide API process safety events of petroleum and fertilizer operations); consolidated tier 1 severity (based on enterprise-wide API process safety events of petroleum and fertilizer operations); consolidated tier 2 process safety events (based upon enterprise-wide API process safety events of petroleum and fertilizer 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: (i) the financial, operational and safety measures used to determine 2014 bonuses for the named executive officers; (ii) the threshold, target and maximum performance levels for each measure; (iii) the actual results with respect to each measure; and (iv) the portion of the 2014 bonus that will be determined based on each such measure. The executives may receive 0% or 50% related to threshold levels, 100% for target levels, and 150% for maximum levels, respectively.
2014 Performance Measure | 2014 Performance Goals Threshold/Target/Maximum | 2014 Actual Results | Portion of Target Bonus Allocable to Measure | |||
Consolidated adjusted EBITDA for CVR Energy | Threshold: $535.3 million Target: $761.8 million Maximum: $1,126.6 million | $717.8 million | 30% of bonus for Mr. Lipinski and Ms. Ball | |||
Petroleum reliability measures | Threshold: 166,000 bpd Target: 177,000 bpd Maximum: 188,000 bpd | 196,545 bpd | 50% of bonus for Mr. Lipinski and Ms. Ball | |||
Petroleum environmental health & safety measures | Threshold: 0% of refining payout levels Target: 20% of refining payout levels Maximum: 30% of refining payout levels | 12.50% | 15% of bonus for Mr. Lipinski and Ms. Ball | |||
Nitrogen environmental health & safety measures | Threshold: 0% of nitrogen payout levels Target: 20% of nitrogen payout levels Maximum: 30% of nitrogen payout levels | 17.14% | 5% of bonus for Mr. Lipinski and Ms. Ball | |||
As a result of these levels of performance, Mr. Lipinski and Ms. Ball earned approximately 115.76% of their respective target bonuses.
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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. The compensation committee may elect to make grants of restricted stock, options, restricted stock units or other equity-based grants under the LTIP 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 2014 was less than $10,000.
Other Forms of Compensation. Each of the named executive officers has provisions in their respective employment agreements with CVR Energy that provide for severance benefits in the event a termination of their employment under certain circumstances. These severance provisions are described below in " — Change-in-Control and Termination Payments" and were negotiated between the applicable named executive officers and CVR Energy.
Compensation Committee Report
The compensation committee of our general partner has reviewed and discussed the Compensation Discussion and Analysis with management. Based on this review and discussion, the compensation committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this Annual Report.
Compensation Committee
Andrew Roberto (Chairman)
Andrew Langham
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Summary Compensation Table
The following table sets forth the compensation paid to the named executive officers during the years ended December 31, 2014, 2013 and 2012 (except as otherwise designated below). In the case of named executive officers who are employed by CVR Energy, all compensation paid to such named executive officers by CVR Energy is reflected in the table, not only the portion of compensation attributable to services performed for our business. Equity awards granted by CVR Energy prior to December 2013 are not included in this table as we are not obligated under the services agreement to reimburse CVR Energy for any portion of such awards made by CVR Energy. Commencing with awards made in December 2013, we are obligated to pay for our allocated portion of performance unit and incentive unit award made to those personnel providing services to CVR Refining via the services agreement.
Name and Principal Position | Year | Salary ($) | Stock Awards ($)(1) | Non-Equity Incentive Plan Compensation ($)(2) | All Other Compensation ($)(3) | Total ($) | |||||||||||
John J. Lipinski, | 2014 | 1,000,000 | — | 2,894,000 | 30,604 | 3,924,604 | |||||||||||
Chief Executive Officer and | 2013 | 950,000 | 2,889,236 | 9,442,250 | 29,933 | 13,311,419 | |||||||||||
President | 2012 | 950,000 | 3,771,738 | 25,105 | 4,746,843 | ||||||||||||
Susan M. Ball, | 2014 | 390,000 | 930,002 | 451,464 | 18,230 | 1,789,696 | |||||||||||
Chief Financial Officer and | 2013 | 360,000 | 896,838 | 468,720 | 17,629 | 1,743,187 | |||||||||||
Treasurer | 2012 | 281,189 | 379,886 | 16,869 | 677,944 | ||||||||||||
Robert W. Haugen, | 2014 | 325,000 | 615,010 | 445,926 | 21,985 | 1,407,921 | |||||||||||
Executive Vice President, | 2013 | 315,000 | 548,083 | 463,277 | 22,141 | 1,348,501 | |||||||||||
Refining Operations | 2012 | 290,000 | 535,294 | 19,829 | 845,123 | ||||||||||||
David L. Landreth | 2014 | 245,000 | 450,010 | 224,106 | 20,440 | 939,556 | |||||||||||
Senior Vice President, | 2013 | 235,000 | 403,481 | 244,776 | 7,451 | 890,708 | |||||||||||
Economics and Planning | |||||||||||||||||
Martin J. Power, | 2014 | 27,603 | 2,038,671 | — | — | 2,066,274 | |||||||||||
Chief Commercial Officer | |||||||||||||||||
_______________________________________
(1) | For 2014, the above table reflects the aggregate grant date fair value for incentive units granted to Ms. Ball and Messrs. Haugen and Power by CVR Energy in December 2014, and for phantom units granted to Mr. Landreth by CVR Refining, LP in December 2014, in each case, computed in accordance with FASB ASC 718, with the assumptions relied upon in such valuation set forth in Note 4 ("Share-Based Compensation") to our audited financial statements. We pay for our allocated portion of the performance and incentive units pursuant to the services agreement. For 2013, the above table reflects the aggregate grant date fair value for certain performance units granted in December 2013 to Mr. Lipinski, for incentive units granted to Ms. Ball and Mr. Haugen by CVR Energy in December 2013, and for phantom units granted to Mr. Landreth by CVR Refining, LP in December 2013, in each case, computed in accordance with FASB ASC 718, with the assumptions relied upon in such valuation set forth in Note 4 ("Share-Based Compensation") to our audited financial statements. We pay for our allocated portion of the performance and incentive units pursuant to the services agreement. |
(2) | Amounts in this column for 2014, 2013 and 2012 reflect amounts earned pursuant to the CVR Energy PIP in respect of performance during those years, paid in 2015, 2014, and 2013 respectively. For Mr. Lipinski, the amount for 2013 also reflects the aggregate grant date fair value for certain performance units granted in December 2013 that are valued based on a performance factor that is tied to certain operational performance metrics. |
(3) | Amounts in this column for 2014 include the following: (a) a company contribution under the CVR Energy 401(k) plan of $15,600 for Messrs. Lipinski, Haugen and Landreth and Ms. Ball; (b) $11,440 for Mr. Lipinski, $1,692 for Ms. Ball, $4,966 for Mr. Haugen and $3,834 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) $3,564 for Mr. Lipinski, $939 for Ms. Ball, $2,159 for Mr. Haugen and $1,006 for Mr. Landreth in premiums paid by CVR Energy on behalf of the executive officer with respect to its basic life insurance program. |
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As described in more detail in the Compensation Discussion and Analysis, during 2014 our named executive officers were employed by CVR Energy and dedicated only a portion of their time to our business in 2014, except for Mr. Landreth who is employed by our general partner and dedicated 100% of his time to the business. The following 2014 cash compensation paid to the named executive officers who are employed by CVR Energy was attributable to their service to our business, based on the percentage of time that each of them dedicated to our business during 2014:
Name | Salary ($) | Stock Awards ($) | Non-Equity Incentive Compensation ($) | Other ($) | ||||||||
John J. Lipinski | 450,000 | — | 1,302,300 | 13,772 | ||||||||
Susan M. Ball | 214,500 | 511,501 | 248,305 | 10,027 | ||||||||
Robert W. Haugen | 292,500 | 553,509 | 401,333 | 20,453 | ||||||||
Martin J. Power | 26,223 | 1,936,737 | — | — | ||||||||
_______________________________________
Grants of Plan-Based Awards
The following table sets forth information regarding amounts that could have been earned under the CVR Energy PIP with respect to the 2014 year, as well as certain incentive unit awards.
Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | |||||||||||||||||||||||
Name | Grant Date | Threshold ($) | Target ($) | Maximum ($) | All Other Stock Awards; Number of Shares of Stock or Units (#) | All Other Option Awards: Number of Shares of Stock or Units Underlying Options (#) | Exercise or Base Price of Option Awards ($/unit) | Grant Date Fair Value of Stock Awards (2) | |||||||||||||||
John J. Lipinski | 1,000,000 | 2,500,000 | 3,750,000 | — | — | ||||||||||||||||||
Susan M. Ball | 156,000 | 390,000 | 585,000 | — | — | ||||||||||||||||||
12/26/2014 | 52,424 | 930,002 | |||||||||||||||||||||
Robert W. Haugen | 156,000 | 390,000 | 585,000 | — | — | ||||||||||||||||||
12/26/2014 | 34,668 | 615,010 | |||||||||||||||||||||
David L. Landreth | 78,400 | 196,000 | 294,000 | — | — | ||||||||||||||||||
12/26/2014 | 25,367 | 450,011 | |||||||||||||||||||||
Martin J. Power | 12/1/2014 | 227,927 | 23.39 | 1,334,464 | |||||||||||||||||||
12/26/2014 | 39,696 | 704,207 | |||||||||||||||||||||
_______________________________________
(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 2014 performance at the threshold, target and maximum levels with respect to each performance measure. The performance measures and related goals for 2014 set by the compensation committee of CVR Energy are described in the Compensation Discussion and Analysis. |
(2) | Reflects the grant date fair value of certain incentive unit awards to Ms. Ball and Messrs. Haugen and Power, and phantom unit awards to Mr. Landreth during 2014, computed in accordance with FASB ASC Topic 718. |
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Employment Agreements
John J. Lipinski. On July 12, 2005, Coffeyville Resources, LLC entered into an employment agreement with Mr. Lipinski, as chief executive officer, which was subsequently assumed by CVR Energy and amended and restated effective as of January 1, 2008, January 1, 2010, January 1, 2011 and January 1, 2014. The agreement has a three year term continuing through January 1, 2017, unless otherwise terminated by CVR Energy or Mr. Lipinski; provided CVR Energy may extend the agreement in one-year increments by providing 90 days' notice prior to the expiration of the initial term or then current renewal term. Mr. Lipinski receives an annual base salary of $1,000,000 effective as of January 1, 2014. Mr. Lipinski is also eligible to receive a performance-based annual cash bonus with a target payment equal to 250% 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 for each fiscal year. In addition, Mr. Lipinski is 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 requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement and also includes 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 one year following termination of employment. In addition, Mr. Lipinski's agreement provides 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."
Susan M. Ball. On October 23, 2007, CVR Energy entered into an employment agreement with Ms. Ball, which was amended on March 5, 2009 and October 9, 2009, and amended and restated on each of January 1, 2010 and January 1, 2011. This agreement was subsequently amended and restated effective as of on August 7, 2012 in connection with Ms. Ball's promotion to the role of chief financial officer, and amended again on December 31, 2013. The agreement has a term extending through December 31, 2015, unless otherwise terminated by CVR Energy or Ms. Ball. The annual salary in effect for Ms. Ball effective January 1, 2014 was $390,000. Ms. Ball is also eligible to receive a performance-based annual cash bonus with a target payment equal to 100% of her annual base salary to be based upon individual and/or performance criteria as established by the compensation committee of the board of directors of CVR Energy for each fiscal year. In addition, Ms. Ball is 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 requires Ms. Ball to abide by a perpetual restrictive covenant relating to non-disclosure and also includes covenants relating to non-solicitation and non-competition that govern during her employment and for one year following termination of employment. In addition, the agreement provides 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."
Robert W. Haugen. On July 12, 2005, CRLLC entered into an employment agreements with Mr. Haugen, which was subsequently assumed by CVR Energy and amended and restated effective as of December 29, 2007. The agreement was amended and restated effective January 1, 2010 and on January 1, 2011, and amended on December 31, 2013 and December 18, 2014. The agreement with Mr. Haugen has a term extending through December 31, 2017, unless otherwise terminated earlier by CVR Energy or Mr. Haugen. The employment agreement provides Mr. Haugen is 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 for each fiscal year. The annual salary in effect for Mr. Haugen effective as of January 1, 2014 was $325,000 and the target annual bonus percentage for Mr. Haugen is 120%. Mr. Haugen is 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 requires Mr. Haugen to abide by a perpetual restrictive covenant relating to non-disclosure and also include covenants relating to non-solicitation and non-competition during their employment and for one year following termination of employment. In addition, the employment agreements provide 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."
David L. Landreth. Mr. Landreth does not have an employment agreement. The annual salary in effect for Mr. Landreth effective January 1, 2014 was $245,000. Mr. Landreth is 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.
Martin J. Power. Effective December 1, 2014, CVR Energy entered into an employment agreement with Mr. Power. The agreement with Mr. Power has a term extending through December 31, 2017, unless otherwise terminated earlier by CVR Energy or Mr. Power. The employment agreement provides Mr. Power is 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 for each fiscal year. The annual salary in effect for Mr. Power effective as of January 1, 2015
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was $325,000 and the target annual bonus percentage for Mr. Power is 108%. Mr. Power is also entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. The agreement require Mr. Haugen to abide by a perpetual restrictive covenant relating to non-disclosure and non-disparagement, and also include covenants relating to non-solicitation and non-competition during their employment and for periods of one year and six months, respectively, following termination of employment. In addition, the employment agreements provide for certain severance payments that may be due following the termination of employment under certain circumstances, which are described below under " — Change-in-Control and Termination Payments."
Outstanding Equity Awards at Fiscal Year End
The following table sets forth information concerning outstanding equity awards granted pursuant to the CVR Refining LTIP that were held by certain of the named executive officers as of December 31, 2014, as well as outstanding incentive unit awards made by CVR Energy and for which, the Partnership will share in the expense.
Option Awards | Stock Awards | ||||||||||||
Name | Number of Securities Underlying Options (#) Unexercisable | Option Exercise Price ($) | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($)(1) | |||||||||
Susan M. Ball | 26,432 | (2 | ) | 521,503 | |||||||||
52,424 | (3 | ) | 880,723 | ||||||||||
Robert W. Haugen | 16,153 | (2 | ) | 318,699 | |||||||||
34,668 | (3 | ) | 582,422 | ||||||||||
David L. Landreth | 12,482 | (4 | ) | 246,270 | |||||||||
25,367 | (5 | ) | 426,166 | ||||||||||
Martin J. Power | 227,927 | 23.39 | (6 | ) | 525,985 | ||||||||
39,696 | (3 | ) | 666,893 | ||||||||||
_______________________________________
(1) | This column represents the number of unvested units outstanding on such date, multiplied by the closing price of the units on December 31, 2014, which: (a) for purposes of the incentive units described in footnote (2) and the phantom units described in footnote (4) below, was $19.73 (the closing price of $16.80 plus $2.93 in accrued distributions); and (b) for purposes of the incentive units described in footnote (3) and the phantom units described in footnote (5) below was $16.80. For purposes of the incentive units described in footnote (6) below, this column represents the fair value of the outstanding units estimated using the Black-Scholes option-pricing model. |
(2) | The incentive units reflected were issued on December 31, 2013. The remaining unvested units are scheduled to vest in one-half increments on December 27, 2015 and 2016, provided the executive continues to serve as an employee of CVR Energy or one of its subsidiaries on such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled "Change-in-Control and Termination Payments" below. The Partnership will share in its prorated share of the costs associated with these awards based on the percentage of time that the executive dedicates to our business during the vesting term. |
(3) | The incentive units reflected were issued on December 26, 2014 and are scheduled to vest in one-third annual increments on the first three anniversaries of the date of grant, 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 phantom units reflected were issued on December 27, 2013. The remaining unvested units are scheduled to vest in one-half increments on December 27, 2015 and 2016, provided the executive continues to serve as an employee of the Partnership or one of its subsidiaries or parents on each 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. |
(5) | The phantom units reflected were issued on December 26, 2014 and are scheduled to vest in one-third annual increments on the first three anniversaries of the date of grant, provided the executive continues to serve as an |
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employee of the Partnership or one of its subsidiaries or parents on each 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 incentive units reflected were issued on December 1, 2014 in the form of stock appreciation rights and are scheduled to vest on December 1, 2017, provided the executive continues to serve as an employee of CVR 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. |
Equity Awards Vested During Fiscal Year 2014
This table reflects the portion of phantom units granted pursuant to the CVR Refining LTIP as well as incentive and performance unit awards made by CVR Energy and for which, the Partnership will share in the expense, that became vested during 2014.
Equity Awards | |||||||
Named Executive Officer | Number of Shares or Units Acquired on Vesting (#) | Value Realized on Vesting ($) | |||||
John J. Lipinski | 132,170 | 1,562,249 | (1) | ||||
Susan M. Ball | 13,216 | 312,426 | (2) | ||||
Robert W. Haugen | 8,077 | 190,940 | (2) | ||||
David L. Landreth | 6,241 | 147,537 | (3) | ||||
_______________________________________
(1) | For performance units that became vested during fiscal year 2014, the amount reflected includes a per unit value equal to (a) the average closing price of CVR Refining's common units in accordance with the agreement and (b) accrued distributions of $2.93 per unit, multiplied by a performance factor that is based upon CVR Energy's consolidated adjusted EBITDA, certain CVR Refining reliability measures, and aggregated environmental, health and safety results for CVR Refining and CVR Partners. |
(2) | For incentive units that became vested during fiscal year 2014, the amount reflected includes a per unit value equal to (a) the average closing price of CVR Refining's common units in accordance with the agreement, plus (b) accrued distributions of $2.93 per unit. |
(3) | For phantom units that became vested during fiscal year 2014, the amount reflected includes a per unit value equal to (a) the average closing price of CVR Refining's common units in accordance with the agreement, plus (b) accrued distributions of $2.93 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, 2014, 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 $75.8 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.
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Change-in-Control and Termination Payments
Under the terms 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. Mr. Landreth does not have an employment agreement with our general partner and is not entitled to any severance and other benefits from our general partner following the termination of his employment. The amounts of potential post-employment payments and benefits in the narrative and table below with respect to Mr. Lipinski, Ms. Ball and Messrs. Haugen and Power assume the triggering event took place on December 31, 2014, are based on salaries as of December 31, 2014, assume the payment of bonuses at 100% of target, assume Mr. Power was employed by CVR Energy as of January 1, 2014 (instead of his actual hire date of December 1, 2014), and for purposes of retirement, assumes the individual is eligible for retirement. Pursuant to the services agreement that we entered into with CVR Energy in connection with the Initial Public Offering, we are responsible only for the payment of severance and other benefits costs following the termination of employment of the executive officers that are expected to devote 100% of their time to managing our business, which excludes all of the named executive officers employed by CVR Energy.
John J. Lipinski. If Mr. Lipinski's employment is 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 is entitled to receive as severance: (a) salary continuation for the lesser of (A) 36 months and (B) the greater of (x) the remainder of the term of the employment agreement and (y) 12 months (such period, the “Post-Employment Period”); (b) a pro-rata bonus for the year in which termination occurs based on actual results; and (c) and the continuation of medical, dental, vision and life insurance benefits ("Welfare Benefits") during the Post-Employment Period, or if earlier, until he becomes eligible for such benefits from a subsequent employer. In addition, if Mr. Lipinski's employment is 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 agreement) or in specified circumstances prior to and in connection with a change in control, Mr. Lipinski will receive 1/12 of his target bonus for the year of termination for each month of the Post-Employment Period.
If Mr. Lipinski'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. Lipinski under disability plan(s), Mr. Lipinski is entitled to (a) disability payments during the Post-Employment Period equal to, in the aggregate, 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 (b) 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 must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. If Mr. Lipinski's employment is terminated at any time by reason of his death, then in addition to any Accrued Amounts, Mr. Lipinski's beneficiary (or his estate) will be paid (a) the base salary Mr. Lipinski would have received had he remained employed through the Post-Employment Period, and (b) 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 will be required to cooperate in obtaining such insurance. Upon a termination by reason of Mr. Lipinski's retirement after reaching age 62, in addition to any Accrued Amounts, Mr. Lipinski will receive (a) continuation of Welfare Benefits during the Post-Employment Period at active-employee rates or until such time as Mr. Lipinski becomes eligible for such benefits from a subsequent employer, (b) provision of an office at CVR Energy's headquarters and use of CVR Energy's facilities and administrative support during the Post-Employment Period at CVR Energy's expense and, at Mr. Lipinski's request, for two years following the Post-Employment Period at Mr. Lipinski's expense, and (c) a pro-rata bonus for the year in which termination occurs based on actual results.
In the event that Mr. Lipinski is eligible to receive continuation of Welfare Benefits at active-employee rates but is not eligible to continue to receive benefits under CVR Energy's plans pursuant to the terms of such plans or a determination by the insurance providers, CVR Energy will use reasonable efforts to obtain individual insurance policies providing Mr. Lipinski with such benefits at the same cost to CVR Energy as providing him with continued coverage under CVR Energy's plans. If such coverage cannot be obtained, CVR Energy will pay Mr. Lipinski on a monthly basis during the relevant continuation period, an amount equal to the amount CVR Energy would have paid had he continued participation in CVR Energy's plans.
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
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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 and not by reason of his retirement. The agreement requires Mr. Lipinski 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. Lipinski's employment term, and thereafter during the period he receives severance payments or supplemental disability payments, as applicable, or for one year following the end of the term (if no severance or disability payments are payable).
Susan M. Ball and Robert W. Haugen. If the employment of Ms. Ball or Mr. Haugen is terminated either by CVR Energy without cause and other than for disability or by the executive officer for good reason (as such terms are defined in their respective employment agreements), then these executive officers are entitled, in addition to any Accrued Amounts, to receive as severance (a) salary continuation for the lesser of 12 months or the remainder of the term of their respective employment agreement (the "Severance Period"), (b) a pro-rata bonus for the year in which termination occurs, based on actual results and (c) the continuation of Welfare Benefits during the Severance Period at active-employee rates or until such time as the executive officer becomes eligible for such benefits from a subsequent employer. In addition, if the employment of the named executive officer is terminated either by CVR Energy without cause and other than for disability or by the executives for good reason (as these terms are defined in their employment agreements) within one year following a change in control (as defined in their employment agreements) or in specified circumstances prior to and in connection with a change in control, they are also entitled to receive monthly payments equal to 1/12 of their respective target bonuses for the year of termination during the Severance Period. Upon a termination of these executives' employment upon retirement after reaching age 65, in addition to any Accrued Amounts, they will receive (a) a pro-rata bonus for the year in which termination occurs, based on actual results and (b) continuation of Welfare Benefits for 24 months at active-employee rates or until such time as they become eligible for such benefits from a subsequent employer.
In the event that Ms. Ball or Mr. Haugen are eligible to receive continuation of Welfare Benefits at active-employee rates but are not eligible to continue to receive benefits under CVR Energy's plans pursuant to the terms of such plans or a determination by the insurance providers, CVR Energy will use reasonable efforts to obtain individual insurance policies providing the executives with such benefits at the same cost to CVR Energy as providing them with continued coverage under CVR Energy's plans. If such coverage cannot be obtained, CVR Energy will pay the executives on a monthly basis during the relevant continuation period, an amount equal to the amount CVR Energy would have paid had they continued participation in its plans.
As a condition to receiving these severance payments and benefits, the executives must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide that if any payments or distributions due to an executive officer 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. These executive officers would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by the executive voluntarily without good reason and not by reason of retirement, death or disability. The agreements require each of the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure. The agreements also include a covenant relating to non-solicitation and non-competition during their employment terms and for one year following the end of the terms.
Martin J. Power. If the employment of Mr. Power is 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 agreements), then Mr. Power is 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 must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide 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 requires Mr. Power 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 the employment term and for six months and one year, respectively, following the end of the term.
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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 | 4,500,000 | 4,500,000 | 2,500,000 | 4,500,000 | 9,500,000 | 25,246 | 25,246 | 25,246 | 25,246 | 25,246 | |||||||||||||||||||
Susan M. Ball | — | — | 390,000 | 780,000 | 1,170,000 | — | — | 5,172 | 2,586 | 2,586 | |||||||||||||||||||
Robert W. Haugen | — | — | 390,000 | 715,000 | 1,105,000 | — | — | 11,794 | 5,897 | 5,897 | |||||||||||||||||||
Martin J. Power | — | — | — | 487,500 | 487,500 | — | — | — | — | — | |||||||||||||||||||
_______________________________________
(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. |
Each of our named executive officers (other than Mr. Lipinski) has been granted restricted stock units pursuant to the CVR Energy LTIP.
The awards that were granted in December 2012 consist of restricted stock units and dividend equivalent rights, which represent the right to receive, upon vesting, a cash payment equal to the fair market value of one share of CVR Energy common stock, plus the cash value of all dividends that were declared and paid by CVR Energy during the vesting period for that award. Awards of restricted stock units granted prior to the December 2012 grants (which only applies to Ms. Ball) represent the holder's right to receive, upon vesting, a cash payment equal to the lesser of $30.00 or the fair market value of a share of CVR Energy common stock, as defined in the Transaction Agreement. The awards are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on the first anniversary of the date of grant, subject to immediate vesting under certain circumstances.
The awards that were granted in December 2012 become immediately vested in the event of the relevant named executive officer's death or disability. In addition, (a) the awards become 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) with respect to all named executive officers other than Mr. Landreth, such named executive officer's employment is terminated under certain circumstances prior to a change in control; and (b) if such named executive officer is terminated other than for cause or resigns for good reason in the absence of a change in control, 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. The terms disability, cause, good reason and change in control are all defined in the CVR Energy LTIP.
The restricted stock units that were granted prior to December 2012 (which only applies to Ms. Ball) become immediately vested in the event of the relevant named executive officer's death, disability or retirement, or in the event of any of the following: (a) such named executive officer's employment is terminated other than for cause within the one-year period following a change in control; (b) such named executive officer resigns from employment for good reason within the one year period following a change in control; or (c) with respect to all named executive officers other than Mr. Landreth, such named executive officer's employment is terminated under certain circumstances prior to a change in control. The terms disability, retirement, cause, good reason and change in control are all defined in the CVR Energy LTIP. In addition, in the event that Ms. Ball is terminated by CVR Energy without cause and other than for disability at any time on or following the date that she reaches age 60, then Ms. Ball's restricted stock units would vest immediately. This acceleration provision would not apply to Ms. Ball during the term of the award.
In December 2013, CVR Energy granted Mr. Lipinski three separate awards of performance units. Awards 1 and 2 represent the right to receive a cash payment equal to $1,000 multiplied by certain performance factors. Award 3 represents the right to receive a cash payment equal to the product of (a) the 10-day average closing price of CVR Refining common units for the first 10 trading days of December 2014 plus the amount of distributions paid on a share of CVR Refining between December 19, 2013 and the last day of the 10 trading days described above and (b) the applicable performance factor. The
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awards are subject to transfer restrictions and carry performance cycles ending on June 30, 2014, December 15, 2014 and December 31, 2014. In the event of Mr. Lipinski’s termination of employment prior to, (i) with respect to Award 1 and Award 2, the applicable payment date and (ii) with respect to Award 3, December 31, 2014 (x) by reason of Mr. Lipinski’s death or disability, (y) by CVR Energy other than for cause or (z) by reason of Mr. Lipinski’s resignation for good reason (as each term is defined in the CVR Energy LTIP), 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.
Also in December 2013, CVR Energy granted Ms. Ball and Mr. Haugen 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 CVR Refining's common units for the first ten trading days in the month of vesting, plus (b) 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 awards are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on December 27, 2014. The awards become 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 such named executive officer is terminated other than for cause or resigns for good reason in the absence of a change in control, or 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.
In December 2014, CVR Energy granted Ms. Ball and Messrs. Haugen and 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 beginning on the first anniversary of the date of grant, subject to immediate vesting under certain circumstances. With respect to Ms. Ball and Mr. Haugen, the awards become 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 Ms. Ball or Messrs. Haugen or Power is terminated other than for cause or resigns for good reason in the absence of a change in control, or 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.
The following table reflects the value of accelerated vesting of the unvested restricted stock units and incentive units held by the named executive officers assuming the triggering event took place on December 31, 2014, and for purposes of retirement, assumes the individual is eligible for retirement. For purposes of: (a) the December 2012 restricted stock unit awards, the value is based on the closing price of the CVR Energy's common stock as of December 31, 2014 date, which was $38.71 per share plus accrued dividends of $19.25 per share; (b) the restricted stock unit awards prior to December 2012, the value is based on a value of $30.00 per share in accordance with the Transaction Agreement; (c) for purposes of the December 2013 incentive unit awards, the value is based on the 10-day average closing price of CVR Refining common units for the first 10 trading days of December 2014, or $20.71 per unit plus accrued distributions of $2.93 per unit; and (d) for purposes of the December 2014 incentive unit awards, the value is based on the 10-day average closing price for the 10 trading days preceding December 31, 2014, or $17.17. The table does not take into consideration the value of the performance units held by Mr. Lipinski (which are the only awards held by Mr. Lipinski) since such performance units would not accelerate, but instead pay out in the ordinary course as if his employment had not terminated. Mr. Power does not have any awards from CVR Energy that qualify for acceleration in these circumstances.
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Value of Accelerated Vesting of Restricted Stock Unit and Incentive Unit Awards
Death ($) | Disability ($) | Retirement ($) | Termination without Cause or with Good Reason ($) | |||||||||||
(1) | (2) | |||||||||||||
Susan M. Ball | 380,900 | 380,900 | 56,730 | — | 1,905,873 | |||||||||
Robert W. Haugen | 222,856 | 222,856 | — | — | 1,199,963 | |||||||||
David L. Landreth | 162,056 | 162,056 | — | — | 162,056 | |||||||||
_______________________________________
(1) | Termination without cause or resignation for good reason not in connection with a change in control. The values included for Mr. Lipinski reflect accelerated vesting by reason of termination without cause after such executive has reached age 60. |
(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 2013 and December 2014. Each phantom 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 in accordance with the award agreement, plus (b) 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 beginning on the anniversary of the grant 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 these circumstances.
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. 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 $1,000 for serving on a board committee and are reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors (and committees thereof) of our general partner and for other director-related education expenses. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.
The following table sets forth the compensation received by each independent director of our general partner for the year ended December 31, 2014.
Name | Fees Earned or Paid in Cash / Total Compensation (1)($) | |
Glenn R. Zander | 87,000 | |
Kenneth Shea | 77,000 | |
Jon R. Whitney | 84,000 | |
_______________________________________
(1) | Amounts reflected in this column include annual retainer fees and additional fees for service as committee members, including the chair positions during 2014. |
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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 17, 2015:
• | 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 | * | |||
Susan M. Ball | 8,000 | * | |||
Robert W. Haugen | 4,000 | * | |||
David L. Landreth | 11,000 | * | |||
Martin J. Power | — | — | |||
Carl C. Icahn(5) | 103,315,764 | 70.0 | % | ||
SungHwan Cho | — | — | |||
Glenn R. Zander | 5,000 | * | |||
Jon R. Whitney | 6,000 | * | |||
Andrew Roberto | — | — | |||
Kenneth Shea | — | — | |||
Courtney Mather | — | — | |||
Andrew Langham | 2,000 | * | |||
Louis J. Pastor | — | — | |||
All directors and executive officers of our general partner as a group (15 persons)(6) | 103,552,764 | 70.2 | % | ||
_______________________________________
* | Less than 1% |
(1) | Based on 147,600,000 common units outstanding as of February 17, 2015. |
(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 |
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G. Alexander, SungHwan Cho, Andrew Langham, John J. Lipinski, Courtney Mather, Stephen Mongillo, Andrew Roberto and James M. Strock.
(4) | Mr. Lipinski owns 80,000 common units directly. In addition, Mr. Lipinski may be deemed to be the beneficial owner of an additional 120,000 common units, which are owned by the 2011 Lipinski Exempt Family Trust, which are held in trust for the benefit of Mr. Lipinski's family. Mr. Lipinski's spouse is the trustee of the trust. |
(5) | The following disclosures are based on a Schedule 13D/A filed with the Commission on July 24, 2014 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 4,000,000 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.
(6) | The number of common units owned by all of the directors and executive officers of our general partner, as a group, reflects the sum of (1) the 200,000 common units owned directly or indirectly by Mr. Lipinski, the 8,000 common units owned by Ms. Ball, the 1,000 common units owned by Mr. Walter, the 4,000 common units owned by Mr. Haugen, and the 11,000 common units owned by Mr. Landreth, (2) the 103,315,764 common units owned directly or indirectly by Mr. Icahn, (3) the 5,000 common units owned by Mr. Zander, (4) the 6,000 common units owned by Mr. Whitney and (5) the 2,000 common units owned by Mr. Langham. |
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The following table sets forth, as of February 17, 2015, 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 | — | — | ||||
Susan M. Ball | — | — | ||||
Robert W. Haugen | 1 | * | ||||
David L. Landreth | — | — | ||||
Martin J. Power | — | — | ||||
Carl C. Icahn(2) | 71,198,718 | 82 | % | |||
SungHwan Cho | — | — | ||||
Glenn R. Zander | — | — | ||||
Jon R. Whitney | — | — | ||||
Andrew Roberto | — | — | ||||
Kenneth Shea | — | — | ||||
Courtney Mather | — | — | ||||
Andrew Langham | — | — | ||||
Louis J. Pastor | — | — | ||||
All directors and executive officers of our general partner as a group (15 persons) | 71,198,719 | 82 | % | |||
_______________________________________
* | Less than 1% |
(1) | Percentage calculated based upon 86,831,050 shares of common stock outstanding as of February 17, 2015. |
(2) | Shares of common stock reflected as beneficially owned by Mr. Icahn are owned of record by IEP Energy LLC, a subsidiary of Icahn Enterprises L.P. Mr. Icahn may be deemed to indirectly beneficially own such shares for purposes of Section 13(d) of the Exchange Act. Mr. Icahn disclaims beneficial ownership of such shares for all other purposes. |
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, 2014, 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 6,000,000 of our common units, representing approximately 4% of our outstanding common units.
Distributions and Payments to CVR Energy and its Affiliates
The following table summarizes the distributions and payments made by us to CVR Energy and its affiliates in connection with the Second Underwritten Offering. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Second Underwritten Offering | |
Proceeds from the sale of additional common units to the public | • We utilized the net proceeds received in connection with the sale of 6,500,000 common units in the Second Underwritten Offering to the public to redeem an equal number of units from CVR Refining Holdings. |
Proceeds from option units | • We utilized the net proceeds received in connection with the underwriters' exercise of their 30-day option to redeem 589,100 common units from CVR Refining Holdings. |
Proceeds from option units sold by CVR Refining Holdings | • CVR Refining Holdings sold 385,900 common units in connection with the underwriters' exercise of their 30-day option and received the net proceeds. |
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 6,000,000 common units. For the year ended December 31, 2014, we distributed $295.8 million and $17.6 million to CVR Refining Holdings and affiliates of IEP, respectively, as a result of quarterly distributions paid 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
Our subsidiaries entered into several agreements with CVR Partners and its affiliates in connection with CVR Partners' initial public offering in April 2011 and CVR Partners' formation in October 2007. The agreements govern the business relations among us and our subsidiaries and CVR Partners. We also entered into several agreements with CVR Energy in connection with the Initial Public Offering that govern our management and business relationship with CVR Energy and its affiliates. 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.
Contribution Agreement
On December 31, 2012, we entered into a Contribution Agreement with CVR Refining Holdings and certain of its affiliates pursuant to which CVR Refining Holdings contributed CVR Refining, LLC ("Refining LLC") to us and we assumed all liabilities (including unknown and contingent liabilities) associated with owning Refining LLC after its contribution to us. In addition, CVR Refining Holdings contributed a 0.01% limited partner interest in us to its wholly-owned subsidiary, CVR Refining Holdings Sub, LLC.
Reorganization Agreement
In connection with the Initial Public Offering, on January 16, 2013, we entered into a Reorganization Agreement, whereby CVR Refining Holdings agreed, if necessary, to contribute to us an amount of cash such that we would have approximately $340.0 million of cash on hand at the closing of the Initial Public Offering and excluding cash used to repurchase the Second Lien Notes issued by CRLLC and Coffeyville Finance Inc. If such amount of cash on hand at the closing of the Initial Public
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Offering were to exceed $340.0 million, we agreed to distribute the excess to CVR Refining Holdings. In addition, pursuant to the Reorganization Agreement, we agreed to (i) issue 119,988,000 common units to CVR Refining Holdings and 12,000 common units to CVR Refining Holdings Sub, LLC, (ii) issue any common units not purchased by the underwriters in the Initial Public Offering pursuant to their option to purchase additional common units, and distribute the net proceeds (after deducting discounts and commissions) from the exercise of such option, if any, to CVR Refining Holdings and (iii) undertake an offering of common units in the future upon request by CVR Refining Holdings and use the proceeds thereof (net of underwriting discounts and commissions) to redeem an equal number of common units from CVR Refining Holdings as a distribution to reimburse CVR Refining Holdings for certain capital expenditures incurred with respect to the assets contributed to us.
Prior to the closing of the Initial Public Offering, we distributed $150.0 million of cash on hand to CRLLC. Additionally, net proceeds from the underwriters' exercising their option to purchase the additional 3,600,000 shares of $85.1 million were distributed to CRLLC on January 28, 2013.
Intercompany Credit Facility
In connection with the Initial Public Offering, on January 23, 2013, we 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 of December 31, 2014, we had borrowings of $31.5 million 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
We, through our wholly-owned subsidiary CRRM, entered into a pet coke supply agreement with CVR Partners in October 2007 pursuant to which we supply CVR Partners with pet coke. This agreement provides that we must deliver to CVR Partners during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100% of the pet coke produced at our Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CVR Partners is also obligated to purchase this annual required amount. If we produce more than 41,667 tons of pet coke during a calendar month, CVR Partners will have the option to purchase the excess at the purchase price provided for in the agreement. If CVR Partners declines to exercise its option, we may sell the excess to a third party.
The price that we receive pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received by CVR Partners for urea ammonium nitrate ("UAN") (the "UAN-based price"), and 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 (exclusive of transportation cost), or 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.
CVR Partners also pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. CVR Partners is entitled to offset any amount payable for the pet coke against any amount we owe under the feedstock and shared services agreement, which is described below. If CVR Partners 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.
In the event we deliver pet coke to CVR Partners on a short-term basis and such pet coke is off-specification on more than 20 days in any calendar year, the price for such pet coke will be adjusted to compensate CVR Partners and/or we will contribute funds in order to share the cost of the expenditures CVR Partners must make to modify its equipment to process the off-specification pet coke it received. If we determine that there will be a change in pet coke quality on a long-term basis, we will be required to provide CVR Partners with at least three years' notice of such change. CVR Partners will then determine the appropriate changes necessary to its nitrogen fertilizer plant in order to process such off-specification pet coke. We will compensate CVR Partners for the cost of making such modifications and/or adjust the price of pet coke on a mutually agreeable commercially reasonable basis.
The terms of the pet coke supply agreement provide benefits to us as well as CVR Partners. The cost of the pet coke we supply to CVR Partners in most cases will be lower than the price CVR Partners otherwise would pay to third parties. The cost to CVR Partners will be lower both because the actual price paid will be lower and because CVR Partners 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 CVR Partners pays will be formulaically related to the price received for UAN (subject to a UAN based price floor and ceiling), CVR Partners will enjoy lower pet coke costs during periods of lower revenues regardless of the prevailing pet coke market.
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In return for us 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.
CVR Partners may be obligated to provide security for its payment obligations under the agreement if in our sole judgment there is a material adverse change in CVR Partners' financial condition or liquidity position or in its ability to make payments. This security shall not exceed an amount equal to 21 times the average daily dollar value of pet coke CVR Partners purchases for the 90-day period preceding the date on which we give CVR Partners notice that we have deemed that a material adverse change in its financial condition, liquidity position or in its ability to make payments has occurred. Unless otherwise agreed to by us and CVR Partners, CVR Partners can provide the security by means of a standby or documentary letter of credit, prepayment, a surety instrument, or a combination of the foregoing. If CVR Partners does not provide such security, we may require CVR Partners to pay for future deliveries of pet coke on a cash-on-delivery basis, failing which we may suspend delivery of pet coke until such security is provided and terminate the agreement upon 30 days' prior written notice. Additionally, CVR Partners may terminate the agreement within 60 days of providing such security, so long as it provides five days' prior written notice to us.
The agreement has an initial term of 20 years (ending October 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 the applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of CVR Partners' operations at its nitrogen fertilizer plant or at our 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 $24, $27 and $30 for the years ended December 31, 2014, 2013 and 2012, respectively. Our total sales to CVR Partners were approximately $8.7 million, $9.6 million and $9.9 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Feedstock and Shared Services Agreement
We, through our wholly-owned subsidiary CRRM, are party to a feedstock and shared services agreement with CVR Partners, which was most recently amended in December 2013. Under this agreement, we agreed with CVR Partners to exchange feedstocks and other services. The feedstocks and services are utilized in the respective production processes of our Coffeyville refinery and CVR Partners' nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas.
Pursuant to the feedstock agreement, we, through our wholly-owned subsidiary CRRM, and CVR Partners transfer excess hydrogen to one another. CVR Partners is only obligated to provide hydrogen to us upon demand if the hydrogen is not required for operation of CVR Partners' fertilizer plant, as determined in a commercially reasonable manner based upon CVR Partners' current or anticipated operational needs. The feedstock agreement provides hydrogen supply and pricing terms for sales of hydrogen by both parties. The price we pay for purchases of hydrogen from CVR Partners 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 we pay reverts to a UAN pricing structure to make CVR Partners whole, as if CVR Partners had produced UAN for sale. Pricing for sales of hydrogen by us to CVR Partners is based off of the price of natural gas. The hydrogen sales that we and CVR Partners make to each other are netted on a monthly basis, and we or CVR Partners will be paid to the extent that either of us sells more hydrogen than purchased in any given month. For the years ended December 31, 2014, 2013 and 2012, we recorded approximately $10.1 million, $11.4 million and $6.3 million, respectively, in cost of product sold for net monthly purchases of
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hydrogen from CVR Partners. For the years ended December 31, 2014, 2013 and 2012, we recorded net monthly sales for transfers of excess hydrogen to CVR Partners of approximately $0, $0.6 million and $0.2 million, respectively.
We, through our wholly-owned subsidiary CRRM, are obligated, upon reasonable notice or request of CVR Partners, to use commercially reasonable efforts to provide high-pressure steam to CVR Partners for the commencement or recommencement of its nitrogen plant operations or for use at its Linde air separation plant. CVR Partners is similarly obligated to provide high-pressure steam to us that it produces but does not require after we provide reasonable notice requesting the same. For the years ended December 31, 2014, 2013 and 2012, net reimbursed or (paid) direct operating expenses related to high pressure steam were not material. CVR Partners is also obligated to make available to us any nitrogen produced by the Linde air separation plant that is not required for the operation of CVR Partners' nitrogen fertilizer plant, as determined by CVR Partners 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 CVR Partners electric bill. For the years ended December 31, 2014, 2013 and 2012, we paid CVR Partners approximately $1.0 million, $0.5 million and $1.4 million, respectively, for nitrogen.
The agreement also provides that both we and CVR Partners must deliver instrument air to one another in some circumstances. CVR Partners must make instrument air available for our purchase at a minimum flow rate, to the extent produced by its Linde air separation plant and available to CVR Partners. The price for the 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 CVR Partners electric bill. To the extent that instrument air is not available from the Linde air separation plant but is available from us, we are required to make instrument air available to CVR Partners 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. The agreement provides a mechanism pursuant to which CVR Partners may transfer a tail gas stream (which is otherwise flared) to us through a pipe between our Coffeyville refinery and CVR Partners' nitrogen fertilizer plant, which we installed. CVR Partners agreed to pay us the cost of installing the pipe over the first three years (commencing in 2011) and in the fourth year provide an additional 15% to cover the cost of capital.
With respect to oxygen requirements, CVR Partners is obligated to provide oxygen produced by its Linde air separation plant and made available to CVR Partners to the extent that such oxygen is not required for operation of the nitrogen fertilizer plant. The oxygen is required to meet certain specifications and is sold to us at a fixed price.
The agreement also addresses the means that we and CVR Partners obtain natural gas. Currently, natural gas is delivered to both CVR Partners' nitrogen fertilizer plant and our Coffeyville refinery pursuant to a contract between us and Atmos Energy Corp. ("Atmos"). Under the amended and restated feedstock and shared services agreement, CVR Partners reimburses us for natural gas transportation and natural gas supplies purchased on CVR Partners' behalf. At our request, or at the request of CVR Partners, in order to supply CVR Partners with natural gas directly, both parties will be required to use their commercially reasonable efforts to (i) add CVR Partners as a party to the current contract with Atmos or reach some other mutually acceptable accommodation with Atmos whereby both we and CVR Partners would each be able to receive, on an individual basis, natural gas transportation service from Atmos on similar terms and conditions as set forth in the current contract, and (ii) would each be able to purchase natural gas supplies on its own account.
The agreement also addresses the allocation of various other feedstocks, services and related costs between us and CVR Partners. 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 us and CVR Partners by the terms of the agreement. The agreement also requires CVR Partners to reimburse us for utility costs related to a sulfur processing agreement between us and Tessenderlo Kerley, Inc. ("Tessenderlo Kerley"). CVR Partners has a similar agreement with Tessenderlo Kerley. Otherwise, costs relating to both our and CVR Partners' 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.
The agreement has an initial term of 20 years (ending October 2027) and 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 CVR Partners' nitrogen fertilizer plant or our Coffeyville refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding, or otherwise becomes insolvent.
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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.
Raw Water and Facilities Sharing Agreement
We, through our wholly-owned subsidiary CRRM, entered into a raw water and facilities sharing agreement with CVR Partners in October 2007 which (i) provides for the allocation of raw water resources between our Coffeyville refinery and CVR Partners' 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 both our Coffeyville refinery and CVR Partners' nitrogen fertilizer plant. 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 us. The agreement provides we and CVR Partners have an undivided one-half interest in the water rights which will allow the water to be removed from the Verdigris River for use at our Coffeyville refinery and CVR Partners' nitrogen fertilizer plant.
The agreement provides that CVR Partners' nitrogen fertilizer plant and our Coffeyville refinery 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, CVR Partners must reimburse us for electricity required to operate the water pumps on a prorated basis that is calculated monthly.
We or CVR Partners 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, we are required to cooperate with CVR Partners to allow CVR Partners to build its own water intake system on the Verdigris River to be used for supplying water to CVR Partners' nitrogen fertilizer plant. We are required to grant easements and access over our property so that CVR Partners 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. CVR Partners will bear all costs and expenses for such construction if it is the party that terminated the original water sharing agreement. If we terminate the original water sharing agreement, CVR Partners may either install a new water intake system at its own expense, or require us to sell the existing water intake system to CVR Partners 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 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.
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Cross-Easement Agreement
We, through our wholly-owned subsidiary CRRM, entered into a cross-easement agreement with CVR Partners in October 2007 and an amended and restated cross-easement agreement in April 2011. The purpose of the agreement is to enable both us and CVR Partners to access and utilize each other's land in certain circumstances in order to operate our 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.
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 CVR Partners' other agreements with us 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.
Environmental Agreement
We, through our wholly-owned subsidiary CRRM, entered into an environmental agreement with CVR Partners in October 2007 that provides for certain indemnification and access rights in connection with environmental matters affecting our Coffeyville refinery and CVR Partner's nitrogen fertilizer plant. A supplement to the agreement was entered into by us and CVR Partners in February 2008 in connection with the execution of a related comprehensive pet coke management plan and the transfer by us to CVR Partners of certain property related to the agreement. We and CVR Partners 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.
To the extent that liability arises from environmental contamination that is caused by us but is also commingled with environmental contamination caused by CVR Partners, we 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
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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.
The agreement also provides for indemnification in the case of contamination or releases of hazardous materials that are present but unknown at the time the agreement was entered into or that occur subsequent to the execution of the agreement to the extent such contamination or releases are identified in reasonable detail before October 2012. 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 CVR Partners' 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.
Omnibus Agreement
CVR Energy, CVR Partners, and CVR Partners' general partner entered into an omnibus agreement in October 2007 and amended and restated in connection with CVR Partners' initial public offering.
Under the omnibus agreement CVR Energy agreed to, and agreed to cause its controlled affiliates not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy continues to own at least 50% of CVR Partners' outstanding units and CVR Energy continues to control our general partner. As a controlled affiliate of CVR Energy, we are bound by the restrictions of the omnibus agreement. The restrictions do not apply to:
• | any fertilizer restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a fertilizer restricted business, as determined in good faith by CVR Energy's board of directors, as applicable; however, if at any time we complete such an acquisition, we must, within 365 days of the closing of the transaction, offer to sell the fertilizer-related assets to CVR Partners for their fair market value plus any additional tax or other similar costs that would be required to transfer the fertilizer-related assets to CVR Partners separately from the acquired business or package of assets; |
• | engaging in any fertilizer restricted business subject to the offer to CVR Partners described in the immediately preceding bullet point pending CVR Partners' determination whether to accept such offer and pending the closing of any offers the we accept; |
• | engaging in any fertilizer restricted business if CVR Partners has previously advised CVR Energy that CVR Partners has elected not to acquire such business; |
• | or acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any fertilizer restricted business. |
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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 obtain certain management and other services from CVR Energy to conduct our day-to-day business operations. CVR Energy provides us with the following services under the agreement, 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 shall serve us on a shared, part-time basis only, unless we and CVR Energy agree otherwise; |
• | administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
• | management of our property and the property of our subsidiaries in the ordinary course of business; |
• | 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, other than administrative personnel, 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, including administrative personnel, 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 must pay CVR Energy within 15 days for invoices it submits under the agreement.
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 plant level are employed directly by us and our subsidiaries, and we 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. After January 23, 2014, either 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
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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 years ended December 31, 2014 and 2013 were approximately $72.1 million and $87.3 million, respectively.
Trademark License Agreement
In connection with the Initial Public Offering, on January 23, 2013, we entered into a trademark license agreement pursuant to which CVR Energy granted us a non-exclusive, non-transferrable license to use the Coffeyville Resources and CVR Refining trademarks in connection with our business. Pursuant to this agreement, 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.
International Truck Purchase
During the year ended December 31, 2013, we purchased seven trucks from a subsidiary of Navistar International Corporation ("Navistar") for approximately $0.8 million.
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
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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.
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 10 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. Prior to August of 2013, KPMG LLP ("KPMG") served as the Partnership's independent public registered accounting firm. The audit committee has not selected the independent registered public accounting firm for the fiscal year ending December 31, 2015.
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 2014.
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 December 31, 2014 and 2013:
Fiscal | Fiscal | ||||||
Year 2014 | Year 2013 | ||||||
Audit fees(1) | $ | 1,311,600 | $ | 933,300 | |||
Audit-related fees(2) | 15,000 | — | |||||
Tax fees | — | — | |||||
All other fees | — | — | |||||
Total | $ | 1,326,600 | $ | 933,300 | |||
(1) | Represents the aggregate fees for professional services rendered for the audit of the Partnership's financial statements for fiscal years ended December 31, 2014 and 2013, the audit of the effectiveness of the Partnership's internal control over financial reporting as of December 31, 2014 and 2013 and consultations on financial accounting and reporting matters arising during the course of the audit for fiscal years 2014 and 2013. Also includes the review of the consolidated financial statements included in the Partnership's quarterly reports on Form 10-Q. Fees for 2014 also include audit services related to the Second Underwritten Offering. |
(2) | Represents fees for agreed-upon procedures performed for statutory reporting. |
The following table presents fees billed for professional services and other services in the following categories and amounts by KPMG for the fiscal year December 31, 2013:
Fiscal | |||
Year 2013 | |||
Audit fees(1) | $ | 358,800 | |
Audit-related fees | — | ||
Tax fees(2) | 183,800 | ||
All other fees | — | ||
Total | $ | 542,600 | |
(1) | Represents the aggregate fees for professional services rendered for the audit of the Partnership's financial statements for fiscal year ended December 31, 2013, assistance with Securities Act filings and related matters, consents issued in connection with Securities Act filings, and consultations on financial accounting and reporting standards arising during the course of the audit for fiscal year 2013. Also includes the review of the consolidated financial statements included in the Partnership's quarterly reports on Form 10-Q. |
(2) | Tax fees consist of fees for general income tax consulting and tax compliance. |
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
See "Index to Consolidated and Combined 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 are not required under the related instructions or are inapplicable and therefore have been omitted.
(a)(3) Exhibits
Exhibit Number | Exhibit Title |
3.1** | Certificate of Limited Partnership of CVR Refining, LP (incorporated by reference to Exhibit 3.1 to the Partnership's Form S-1 filed on October 1, 2012). |
3.2** | First Amended and Restated Agreement of Limited Partnership of CVR Refining, LP, dated as of January 23, 2013 (incorporated by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on January 29, 2013). |
4.1** | Indenture relating to 6.500% senior secured notes due 2022, dated as of October 23, 2012, by and among CVR Refining, LLC, Coffeyville Finance Inc., each of the guarantors party thereto, Wells Fargo Bank, National Association, as Trustee, and Wells Fargo Bank, National Association, as Collateral Trustee (incorporated by reference to Exhibit 4.1 of the Form 8-K filed by CVR Energy, Inc. on October 29, 2012 (Commission File No. 001-33492)). |
4.2** | Forms of 6.5% Second Lien Senior Secured Notes due 2022 (included within the Indenture filed as Exhibit 4.1). |
4.3** | Registration Rights Agreement, dated as of January 23, 2013, by and among CVR Refining, LP, Icahn Enterprises Holdings L.P., CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on January 29, 2013). |
10.1** | Contribution Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Partnership's Form S-1/A filed on January 8, 2013). |
10.2**++ | CVR Refining, LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership's Form 8-K filed on January 23, 2013). |
10.2.1**++ | Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.2.1 to the Partnership's Form 10-K filed on February 26, 2014). |
10.2.2*++ | Form of CVR Refining, LP Long-Term Incentive Plan Employee Phantom Unit Agreement. |
10.3*++ | Incentive Unit Agreement, dated as of December 1, 2014, by and between CVR Energy, Inc. and Martin J. Power. |
10.4** | Services Agreement, dated December 31, 2012, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.2 to the Partnership's Form 8-K filed on January 29, 2013). |
10.4.1** | Amendment to Services Agreement, dated February 17, 2014, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-Q filed on May 1, 2014). |
10.4.2** | Second Amendment to Services Agreement, dated June 27, 2014, by and among CVR Refining, LP, CVR Refining GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Partnership's Form 10-Q filed on August 1, 2014). |
10.5** | Trademark License Agreement, dated as of January 23, 2013, by and between CVR Refining, LP and CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 to the Partnership's Form 8-K filed on January 29, 2013). |
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Exhibit Number | Exhibit Title |
10.6** | Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 to the Partnership's Form S-1/A filed on November 27, 2012). |
10.7** | Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc., CVR GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.2 to CVR Energy, Inc.'s Form 8-K/A filed on May 23, 2011 (Commission File No. 001-33492)). |
10.8** | Amended and Restated ABL Credit Agreement, dated as of December 20, 2012, among Coffeyville Resources, LLC, CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, the lenders from time to time party thereto, Wells Fargo Bank, National Association, as collateral agent and administrative agent (incorporated by reference to Exhibit 1.1 to CVR Energy, Inc.'s Form 8-K filed on December 27, 2012 (Commission File No. 001-33492)). |
10.9** | Amended and Restated ABL Pledge and Security Agreement, dated as of December 20, 2012, among CVR Refining, LP, CVR Refining, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC, Coffeyville Resources Terminal, LLC, Wynnewood Energy Company, LLC, Wynnewood Refining Company, LLC and certain of their affiliates, and Wells Fargo Bank, National Association, as collateral agent (incorporated by reference to Exhibit 1.2 to CVR Energy, Inc.'s Form 8-K filed on December 27, 2012 (Commission File No. 001-33492)). |
10.10** | Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, as collateral agent (incorporated by reference to Exhibit 10.2 to CVR Energy Inc.'s Registration Statement on Form S-1/A, File No. 333-137588, filed on February 12, 2007 (Commission File No. 001-33492)). |
10.11** | ABL Intercreditor Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Finance Inc., Deutsche Bank Trust Company Americas, as collateral agent for the ABL secured parties, Wells Fargo Bank, National Association, as collateral trustee for the secured parties in respect of the outstanding first lien obligations, and the outstanding second lien notes and certain subordinated liens, respectively, and the Guarantors (as defined therein) (incorporated by reference to Exhibit 1.3 to CVR Energy, Inc.'s Form 8-K filed on February 28, 2011 (Commission File No. 001-33492)). |
10.12** | First Amended and Restated Collateral Trust and Intercreditor Agreement, dated as of April 6, 2010, among Coffeyville Resources, LLC, Coffeyville Finance Inc., the other grantors from time to time party thereto, Credit Suisse AG, Cayman Islands Branch, as administrative agent, Wells Fargo Bank, National Association, as indenture agent, J. Aron & Company, as hedging counterparty, each additional first lien representative and Wells Fargo Bank, National Association, as collateral trustee (incorporated by reference to Exhibit 10.33 to CVR Energy Inc.'s Form 10-K for the year ended December 31, 2011, filed on February 29, 2012 (Commission File No. 001-33492)). |
10.13** | Omnibus Amendment Agreement and Consent under the Intercreditor Agreement, dated as of April 6, 2010, by and among Coffeyville Resources, LLC, Coffeyville Finance Inc., Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, and certain subsidiaries of the foregoing as Guarantors, the Requisite Lenders, Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, Collateral Agent and Revolving Issuing Bank, J. Aron & Company, as a hedge counterparty and Wells Fargo Bank, National Association, as Collateral Trustee (incorporated by reference to Exhibit 1.4 to CVR Energy Inc.'s Form 8-K filed on April 12, 2010 (Commission File No. 001-33492)). |
10.14** | Senior Unsecured Revolving Credit Agreement, dated as of January 23, 2013, by and between CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.4 to the Partnership's Form 8-K filed on January 29, 2013). |
10.14.1** | First Amendment to Credit Agreement, dated as of October 29, 2014, by and between CVR Refining, LLC and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on October 30, 2014). |
10.15** | Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007 (Commission File No. 001-33492)). |
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Exhibit Number | Exhibit Title |
10.16** | Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011 (Commission File No. 001-33492)). |
10.17** | Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007). |
10.17.1** | Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 of the Form 10-K filed by CVR Energy, Inc. on March 28, 2008 (Commission File No. 001-33492)). |
10.17.2** | Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.1 of the Form 10-Q filed by CVR Energy, Inc. on August 14, 2008 (Commission File No. 001-33492)). |
10.18** | Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011 (Commission File No. 001-33492)). |
10.18.1** | Amendment to Amended and Restated Feedstock and Shared Services Agreement, dated as of December 30, 2013, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 to the Partnership's Form 10-K filed on February 26, 2014). |
10.19** | Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.9 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007 (Commission File No. 001-33492)). |
10.20**† | Amended and Restated Crude Oil Supply Agreement dated August 31, 2012, by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.16 to the Partnership's Form S-1 filed on October 1, 2012). |
10.21**† | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, by and between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (incorporated by reference to Exhibit 10.17 to the Partnership's Form S-1/A filed on November 27, 2012). |
10.22**++ | Fourth Amended and Restated Employment Agreement, dated as of December 19, 2013, by and between CVR Energy, Inc. and John J. Lipinski (incorporated by reference to Exhibit 10.21 to the Partnership's Form 10-K filed on February 26, 2014). |
10.22.1*++ | Amendment to Fourth Amended and Restated Employment Agreement, dated as of March 17, 2014, by and between CVR Energy, Inc. and John J. Lipinski |
10.23**++ | Third Amended and Restated Employment Agreement, dated as of July 27, 2012, by and between CVR Energy, Inc. and Susan M. Ball (incorporated by reference to Exhibit 10.1 of CVR Energy Inc.'s Form 10-Q for the quarter ended September 30, 2012, filed on November 6, 2012) (Commission File No. 001-33492)). |
10.23.1**++ | Amendment Number 1 to the Third Amended and Restated Employment Agreement, dated as of December 31, 2013, by and between CVR Energy, Inc. and Susan M. Ball (incorporated by reference to Exhibit 10.22.1 to the Partnership's Form 10-K filed on February 26, 2014). |
10.24**++ | Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.5 to the CVR Energy, Inc.'s Form 10-Q for the quarter ended March 31, 2011, filed on May 10, 2011 (Commission File No. 001-33492)). |
10.24.1**++ | Amendment Number 1 to the Third Amended and Restated Employment Agreement, dated as of December 31, 2013, by and between CVR Energy, Inc. and Robert W. Haugen (incorporated by reference to Exhibit 10.23.1 to the Partnership's Form 10-K filed on February 26, 2014). |
10.24.2*++ | Amendment Number 2 to the Third Amended and Restated Employment Agreement, dated as of December 18, 2014, by and between CVR Energy, Inc. and Robert W. Haugen. |
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Exhibit Number | Exhibit Title |
10.25*++ | Employment Agreement, dated as of December 1, 2014, by and between CVR Energy, Inc. and Martin J. Power. |
10.26** | Reorganization Agreement, dated as of January 16, 2013, by and among CVR Refining, LP, CVR Refining GP, LLC, CVR Refining Holdings, LLC and CVR Refining Holdings Sub, LLC (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on January 23, 2013). |
21.1** | List of Subsidiaries of CVR Refining, LP (incorporated by reference to Exhibit 21.1 to the Partnership's Form S-1 filed on October 1, 2012). |
23.1* | Consent of Grant Thornton LLP. |
23.2* | Consent of KPMG LLP. |
31.1* | Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer and President. |
31.2* | Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer and Treasurer. |
32.1* | Section 1350 Certification of Chief Executive Officer and President and Chief Financial Officer and Treasurer. |
101* | The following financial information for CVR Refining LP's Annual Report on Form 10-K for the year ended December 31, 2014, formatted in XBRL ("Extensible Business Reporting Language") includes: (1) Consolidated Balance Sheets, (2) Consolidated and Combined Statements of Operations, (3) Consolidated and Combined Statements of Changes in Partners' Capital/Divisional Equity, (4) Consolidated and Combined Statements of Cash Flows, (5) the Notes to Consolidated and Combined Financial Statements, tagged in detail. |
_______________________________________
* | Filed herewith. | |
** | Previously filed. | |
† | Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment which has been granted by the SEC. | |
++ | Denotes management contract or compensatory plan or arrangement. | |
PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporated 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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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/ JOHN J. LIPINSKI | |
Name: John J. Lipinski Title: Chief Executive Officer and President | ||
Date: February 20, 2015
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/ JOHN J. LIPINSKI | Chief Executive Officer, President and Director (Principal Executive Officer) | February 20, 2015 |
John J. Lipinski | ||
/s/ SUSAN M. BALL | Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) | February 20, 2015 |
Susan M. Ball | ||
Director | February 20, 2015 | |
Carl C. Icahn | ||
/s/ SUNGHWAN CHO | Director | February 20, 2015 |
SungHwan Cho | ||
/s/ ANDREW LANGHAM | Director | February 20, 2015 |
Andrew Langham | ||
/s/ COURTNEY MATHER | Director | February 20, 2015 |
Courtney Mather | ||
Director | February 20, 2015 | |
Louis J. Pastor | ||
/s/ ANDREW ROBERTO | Director | February 20, 2015 |
Andrew Roberto | ||
/s/ KENNETH SHEA | Director | February 20, 2015 |
Kenneth Shea | ||
/s/ JON R. WHITNEY | Director | February 20, 2015 |
Jon R. Whitney | ||
/s/ GLENN R. ZANDER | Director | February 20, 2015 |
Glenn R. Zander | ||
169