CVR ENERGY INC - Annual Report: 2019 (Form 10-K)
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________________________
Form 10-K
| (Mark One) | ||||||||
| ☑ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||||
| For the fiscal year ended | December 31, 2019 | |||||||
| OR | ||||||||
| ☐ | 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: 001-33492
_____________________________________________________________
CVR Energy, Inc.
(Exact name of registrant as specified in its charter)
| Delaware |  | 61-1512186 | ||||||
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) | |||||||
2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479
(Address of principal executive offices) (Zip Code)
281-207-3200
(Registrant’s Telephone Number, including Area Code)
____________________________________________________________
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Ticker Symbol(s) | Name of Each Exchange on Which Registered | ||||||
| Common Stock, $0.01 par value per share | CVI | 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 ☐ No ☑
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 ☐ No ☑
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 ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of 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 such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☑ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | ||||||||||||
| Smaller reporting company | ☐ | Emerging growth company | ☐ | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
At June 28, 2019, the aggregate market value of the voting common stock held by non-affiliates of the registrant was approximately $1,466 million based upon the closing price of its common stock on the New York Stock Exchange Composite tape. As of February 18, 2020, there were 100,530,599 shares of the registrant’s common stock outstanding.
Documents Incorporated By Reference
Portions of the registrant’s Proxy Statement to be filed pursuant to Regulation 14A pertaining to the 2020 Annual Meeting of Stockholders are incorporated by reference into Part III hereof. The Company intends to file such Proxy Statement no later than 120 days after the end of the fiscal year covered by this Form 10-K.
TABLE OF CONTENTS
CVR Energy
Annual Report on Form 10-K
| PART I | PART III | |||||||||||||||||||
| PART II | PART IV | |||||||||||||||||||
 | ||||||||||||||||||||
December 31, 2019 | 1
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, 2019 (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 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.
Ammonia — Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applications and finished fertilizer products.
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 gas liquids, ethanol, or reformate, among others.
Bpd — Abbreviation for barrels per day.
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 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, regulatory compliance costs and downstream unit constraints.
Catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.
Corn belt —The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.
Crack spread — A simplified calculation that measures the difference between the price for light products and crude oil.
Distillates — Primarily diesel fuel, kerosene and jet fuel.
Ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
FCCU — Refers to the fluid catalytic cracking unit.
Feedstocks — Petroleum products, such as crude oil or FCCU gasoline, that are processed and blended into refined products, such as gasoline, diesel fuel, and jet fuel during the refining process.
GHG — Greenhouse gas.
Group 3 — A geographic subset of the PADD II region comprising refineries in the midcontinent portion of the United States, specifically Oklahoma, Kansas, Missouri, Nebraska, Iowa, Minnesota, North Dakota, and South Dakota.
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.
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.
December 31, 2019 | 2
Liquid volume yield — A calculation of the total liquid volumes produced divided by total throughput.
MMBtu — One million British thermal units, or Btu: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.
Natural gas liquids — Natural gas liquids, often referred to as NGLs, are blendstocks used in the manufacture of refined fuels, as well as products of the refining process. Common NGLs used include propane, isobutane, normal butane, and natural gasoline.
Petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.
Product pricing at gate — Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons. Product pricing at gate is also referred to as netback.
Rack sales — Sales which are made at terminals into third-party tanker trucks or railcars.
RBOB — Reformulated blendstocks for oxygenate blending.
Refined products — Petroleum products, such as gasoline, diesel fuel, and jet fuel, that are produced by a refinery.
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 quantity of crude oil and other feedstocks processed at a refinery measured in barrels per day.
Turnaround — A periodically required standard procedure to inspect, refurbish, repair, and maintain the refinery or nitrogen fertilizer plant assets. This process involves the shutdown and inspection of major processing units and occurs every four to five years for the refineries and every two to three years for the nitrogen fertilizer facilities. A turnaround will typically extend the operating life of a facility and return performance to desired operating levels.
UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.
ULSD — Ultra low sulfur diesel.
Utilization — Measurement of the annual production of UAN and Ammonia expressed as a percentage of each facilities nameplate production capacity.
WCS —Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity (“API gravity”) of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.
WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.
WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.
Yield — The percentage of refined products that is produced from crude oil and other feedstocks.
December 31, 2019 | 3
Important Information Regarding Forward Looking Statements
This Annual Report on Form 10-K (this “Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), including, but not limited to, those under Item 1. Business, Item 1A. Risk Factors, and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. These forward looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements other than statements of historical fact, including without limitation, statements regarding future operations, financial position, estimated revenues and losses, growth, capital projects, stock repurchases, impacts of legal proceedings, projected costs, prospects, plans, and objectives of management are forward-looking statements. The words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar terms and phrases are intended to identify forward-looking statements.
Although we believe our assumptions concerning future events are reasonable, a number of risks, uncertainties, and other factors could cause actual results and trends to differ materially from those projected or forward looking. Forward looking statements, as well as certain risks, contingencies or uncertainties that may impact our forward looking statements, include but are not limited to the following:
•volatile margins in the refining industry and exposure to the risks associated with volatile crude oil, refined product and feedstock prices;
•the availability of adequate cash and other sources of liquidity for the capital needs of our businesses;
•the ability to forecast our future financial condition, results of operations, revenues and expenses;
•the effects of transactions involving forward and derivative instruments;
•changes in laws, regulations and policies with respect to the export of crude oil, refined products or other hydrocarbons;
•interruption in pipelines supplying feedstocks or distributing the petroleum business’ products;
•competition in the petroleum and nitrogen fertilizer businesses including potential impacts of domestic and global supply and demand;
•capital expenditures;
•changes in our or our segments’ credit profiles;
•the cyclical and seasonal nature of the petroleum and nitrogen fertilizer businesses;
•the supply, availability and price levels of essential raw materials and feedstocks;
•our production levels, including the risk of a material decline in those levels;
•accidents or other unscheduled shutdowns or interruptions affecting out facilities, machinery, or equipment, or thise of our suppliers or customers;
•existing and future laws, ruling and regulations, including but not limited to those relating to the environment, climate change and/or the transportation of production of hazardous chemicals like ammonia, including potential liabilities or capital requirements arising from such laws, rulings or regulations;
•potential operating hazards from accidents, fire, severe weather, tornadoes, floods, or other natural disasters;
•the impact of weather on the nitrogen fertilizer business including our ability to produce, market or sell fertilizer products profitability or at all;
•rulings, judgements or settlements in litigation, tax or other legal or regulatory matters;
•the dependence of the nitrogen fertilizer business on customers and distributors including to transport goods and equipment;
•the reliance on, or the ability to procure economically or at all, pet coke our nitrogen fertilizer business purchases from CVR Refining and third-party suppliers or the natural gas, electricity, oxygen, nitrogen, sulfur processing and compressed dry air and other products purchased from third parties by the nitrogen fertilizer and petroleum businesses;
•risks associated with third party operation of or control over important facilities necessary for operation of our refineries and nitrogen fertilizer facilities;
•risks of terrorism, cybersecurity attacks, and the security of chemical manufacturing facilities and other matters beyond our control;
•our lack of diversification of assets or operating and supply areas;
•the petroleum business’ and the nitrogen fertilizer business’ dependence on significant customers and the creditworthiness and performance by counterparties;
•the potential loss of the nitrogen fertilizer business’ transportation cost advantage over its competitors;
•the potential inability to successfully implement our business strategies, including the completion of significant capital programs or projects;
December 31, 2019 | 4
•our ability to continue to license the technology used for our operations;
•our petroleum business’ ability to purchase RINs on a timely and cost effective basis;
•our businesses’ ability to obtain, retain or renew environmental and other governmental permits, licenses or authorizations necessary for the operation of its business;
•existing and proposed laws, rulings, and regulations, including but not limited to those relating to climate change, alternative energy or fuel sources, and existing and future regulations related to the end-use of our products or the application of fertilizers;
•refinery and nitrogen fertilizer facilities’ operating hazards and interruptions, including unscheduled maintenance or downtime and the availability of adequate insurance coverage;
•risks related to services provided by or competition among our subsidiaries, including conflicts of interests and control of CVR Partners’ general partner;
•instability and volatility in the capital and credit markets;
•restrictions in our debt agreements;
•the variable nature of CVR Partners’ distributions, including the ability of its general partner to modify or revoke its distribution policy, or to cease making cash distributions on its common units;
•changes in CVR Partners’ treatment as a partnership for U.S. federal income or state tax purposes; and
•our ability to recover under our insurance policies for damages or losses in full or at all.
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.
December 31, 2019 | 5
PART I
Part I should be read in conjunction with Management’s Discussion and Analysis in Item 7 and our consolidated financial statements and related notes thereto in Item 8.
Item 1. Business
Overview
CVR Energy, Inc. is a diversified holding company formed in September 2006 which is primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP (the “Petroleum Segment” or “CVR Refining”) and CVR Partners, LP (the “Nitrogen Fertilizer Segment” or “CVR Partners”). CVR Refining is an independent petroleum refiner and marketer of high value transportation fuels. CVR Partners produces and markets nitrogen fertilizers in the form of UAN and ammonia. As used in this Annual Report on Form 10-K, the terms “CVR Energy”, the “Company”, “we”, “us”, or “our” generally include CVR Refining, CVR Partners, the Company’s publicly traded limited partnership, and their respective subsidiaries, as consolidated subsidiaries of the Company with certain exceptions where there are transactions or obligations between and among CVR Refining, CVR Partners, and CVR Energy, including their subsidiaries. Refer to “Petroleum” and “Nitrogen Fertilizer” below for further details on our two business segments.
Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “CVI,” and CVR Partners’ common units are listed on the NYSE under the symbol “UAN.” As of December 31, 2019, Icahn Enterprises L.P. and its affiliates (“IEP”) owned approximately 71% of our outstanding common stock.
As of December 31, 2019, we owned the general partner and approximately 34% of the outstanding common units representing limited partner interests in CVR Partners, with the public owning the remaining outstanding common units of CVR Partners.
On January 17, 2019, the general partner of CVR Refining assigned to the Company its right to purchase all of the issued and outstanding CVR Refining common units not already owned by CVR Refining’s general partner or its affiliates. On January 29, 2019, the Company purchased all remaining CVR Refining common units not already owned by the Company or its affiliates (the “Public Unit Purchase”). In conjunction with the Public Unit Purchase, the Company purchased all CVR Refining common units owned by IEP and its subsidiary, American Entertainment Properties Corporation (“AEP”) (the “Affiliate Unit Purchase,” and together with the Public Unit Purchase, the “CVRR Unit Purchase”). As a result of the CVRR Unit Purchase, CVR Refining’s common units were delisted effective January 29, 2019, and its reporting obligations under Sections 13(a) and 15(d) of the Exchange Act were suspended as of February 8, 2019. Refer to Item 8, Note 1 (“Organization and Nature of Business”) for further discussion of the CVRR Unit Purchase.
Our History
The following graphic depicts the Company’s history and key events that have occurred since the Company’s formation.
Petroleum
Our Petroleum Segment is comprised of the assets and operations of CVR Refining, including two refineries located in Coffeyville, Kansas and Wynnewood, Oklahoma and supporting logistics assets in the region.
December 31, 2019 | 6
Facilities
Coffeyville Refinery - We own a complex full coking medium-sour crude oil refinery in southeast Kansas, approximately 100 miles from Cushing, Oklahoma (“Cushing”) with a name plate crude oil capacity of 132,000 bpd (the “Coffeyville Refinery”). The major operations of the Coffeyville Refinery include fractionation, catalytic cracking, hydrotreating, reforming, coking, isomerization, alkylation, sulfur recovery, and propane and butane recovery operating units. The 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 the Coffeyville Refinery to continue to receive and process crude oil even if one tower requires maintenance without having to shut down the entire refinery. In addition, the Coffeyville Refinery has a redundant supply of hydrogen pursuant to its feedstock and shared services agreement with a subsidiary of CVR Partners.
Wynnewood Refinery - We own a complex crude oil refinery in Wynnewood, Oklahoma approximately 65 miles south of Oklahoma City, Oklahoma and approximately 130 miles from Cushing with a name plate crude oil capacity of 74,500 bpd capable of processing 20,000 bpd of light sour crude oil (the “Wynnewood Refinery” and together with the Coffeyville Refinery, the “Refineries”). The major operations of the Wynnewood Refinery include fractionation, hydrotreating, hydrocracking, reforming, solvent deasphalting, alkylation, sulfur recovery, and propane and butane recovery operating units. Similar to the Coffeyville Refinery, the Wynnewood Refinery benefits from unit redundancies, including two crude oil distillation and vacuum towers and four hydrotreating units.
Throughput by Refinery
| Year Ended December 31, 2019 | |||||||||||||||||
| (in bpd) | Coffeyville | Wynnewood | Total | ||||||||||||||
| Total crude throughput | 129,878 | 73,180 | 203,058 | ||||||||||||||
| All other feedstock and blendstock | 9,160 | 3,753 | 12,913 | ||||||||||||||
| Total throughput | 139,038 | 76,933 | 215,971 | ||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||
| (in bpd) | Coffeyville | Wynnewood | Total | ||||||||||||||
| Total crude throughput | 124,489 | 74,669 | 199,158 | ||||||||||||||
| All other feedstock and blendstock | 8,369 | 5,068 | 13,437 | ||||||||||||||
| Total throughput | 132,858 | 79,737 | 212,595 | ||||||||||||||
Production by Refinery
| Year Ended December 31, 2019 | |||||||||||||||||
| (in bpd) | Coffeyville | Wynnewood | Total | ||||||||||||||
| Gasoline | 71,817 | 38,864 | 110,681 | ||||||||||||||
| Diesel fuels | 57,549 | 32,380 | 89,929 | ||||||||||||||
| Other refined products | 10,383 | 3,253 | 13,636 | ||||||||||||||
| Total production | 139,749 | 74,497 | 214,246 | ||||||||||||||
December 31, 2019 | 7
| Year Ended December 31, 2018 | |||||||||||||||||
| (in bpd) | Coffeyville | Wynnewood | Total | ||||||||||||||
| Gasoline | 67,091 | 40,291 | 107,382 | ||||||||||||||
| Diesel fuels | 56,307 | 33,442 | 89,749 | ||||||||||||||
| Other refined products | 10,927 | 4,066 | 14,993 | ||||||||||||||
| Total production | 134,325 | 77,799 | 212,124 | ||||||||||||||
Supply
The Coffeyville Refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, the Coffeyville Refinery crude oil slate consists of a blend of mid-continent domestic grades and various Canadian medium and heavy sours and other similarly sourced crudes. Other blendstocks include normal butane, natural gasoline, alkylation feeds, naphtha, gas oil, and vacuum tower bottoms. The Wynnewood Refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil. Isobutane, gasoline components, and normal butane blendstocks are also typically used.
December 31, 2019 | 8
In addition to the use of third-party pipelines, we have an extensive gathering system consisting of logistics assets that are owned, leased, or part of a joint venture operation. These assets include the following:
| As of December 31, 2019 | |||||||||||||||||
| Pipeline Segment | Length (miles) | Capacity (bpd) | |||||||||||||||
| Joint Ventures: | |||||||||||||||||
| Midway Pipeline LLC (“Midway JV”) (1)(4) | 100 | 120,000 | |||||||||||||||
| Enable South Central Pipeline (“Enable JV”) (1) | 26 | 115,000 | |||||||||||||||
| Owned Pipelines: | |||||||||||||||||
| Valley to Hooser 6” (2) | 46 | 9,600 | |||||||||||||||
| Valley to Hooser 8” | 20 | 9,600 | |||||||||||||||
| Hooser to Broome 8” | 43 | 22,800 | |||||||||||||||
| Broome to East Tank Farm 12” (3) | 19 | 52,000 | |||||||||||||||
| Broome to East Tank Farm 16” (3) | 18 | 120,000 | |||||||||||||||
| East Tank Farm to Refinery 16” (3) | 2 | 160,000 | |||||||||||||||
| Shidler to Hooser 4” | 23 | 6,500 | |||||||||||||||
| Plainville to Phillipsburg 6” | 36 | 6,000 | |||||||||||||||
| Plainville to Natoma 6” | 10 | 6,500 | |||||||||||||||
| Cushing to Payson 10” (Red River) | 30 | 40,000 | |||||||||||||||
| Payson to Enable tie 8” (Red River) | 73 | 40,000 | |||||||||||||||
| Leased Pipelines: | |||||||||||||||||
| Humboldt to Broome 8” | 62 | 7,000 | |||||||||||||||
| Kelley to Barnsdall 8” | 31 | 3,600 | |||||||||||||||
| Barnsdall to Caney 8” | 36 | 3,600 | |||||||||||||||
(1)CVR Refining owns a 50% interest in the Midway JV and a 40% interest in the Enable JV. CVR Refining has the ability to exercise influence through its participation on the board of directors of each of the Midway JV and the Enable JV and does not serve as the day-to-day operator. We have determined that these entities should not be consolidated and apply the equity method of accounting. Refer to Item 8, Note 3 (“Equity Method Investments”) for further discussion of these investments.
(2)This pipeline is in the process of being taken out of service.
(3)In support of our Coffeyville Refinery, we own and operate a tank storage facility in close proximity to the Coffeyville Refinery (the “East Tank Farm”).
(4)The Midway JV pipeline will have an estimated 150,000 bpd capacity resulting from expanded pumping capacity which is planned to be completed during the Coffeyville Refinery turnaround in the spring of 2020.
For the acquisition of crude oil within close proximity of the Refineries, we operate a fleet of approximately 140 trucks and have contracts with third-party trucking fleets to acquire and deliver crude oil to our pipeline system or directly to the Refineries for consumption or resale. For the year ended December 31, 2019, the gathering system, which includes the pipelines outlined above and our trucking operations, supplied approximately 53% and 85% of the Coffeyville and Wynnewood Refineries’ crude oil demand, respectively. Regionally-sourced crude oils delivered to the Refineries usually have a transportation cost advantage compared to other domestic or international crudes given the Refineries’ proximity to the producing areas. However, sometimes slightly heavier and more sour crudes may offer good economics to the Refineries, including the higher cost of transportation. The regionally-sourced crude oils we purchase are light and sweet enough to allow the Refineries to blend higher percentages of lower cost crude oils, such as heavy Canadian sour, to optimize economics within operational constraints.
Crude oils sourced outside of our gathering system are delivered to Cushing by various third-party pipelines, including the Keystone and Spearhead pipelines on which we can be subject to proration, and subsequently to the Broome Station facility via the Midway JV pipeline. Our current contracted capacity includes the Pony Express and White Cliffs pipelines, respectively. From the Broome Station facility, crude oil is delivered to the Coffeyville Refinery via the Petroleum Segment’s 170,000 bpd proprietary pipeline system. Crude oils are delivered to the Wynnewood Refinery through third-party and joint venture
December 31, 2019 | 9
pipelines and received into storage tanks at terminals located on or near the refinery. We also lease tank storage totaling 2.1 million barrels, including 1.9 million barrels at Cushing.
The Coffeyville Refinery is connected to the mid-continent natural gas liquid commercial hub at Conway, Kansas by the inbound Enterprise Pipeline Blue Line. Natural gas liquid blendstocks such as butanes and natural gasoline are sourced and delivered directly into the refinery. In addition, Coffeyville Refinery’s proximity to Conway provides access to the natural gas liquid and liquid petroleum gas fractionation and storage capabilities.
Through the crude oil and other feedstock supply operations outlined above, and the associated markets available to it, we are able to source and refine crude oils from different locations and of different compositions when it is economically advantageous to do so. The tables below present the total crude throughput by refinery for the years ended December 31, 2019 and 2018:
| Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||
| (in bpd) | Coffeyville | Wynnewood | Total | ||||||||||||||||||||||||||||||||
| Regional Crude | 49,093 | 38 | % | 53,848 | 74 | % | 102,941 | 51 | % | ||||||||||||||||||||||||||
| WTI | 67,382 | 52 | % | 3 | — | % | 67,385 | 33 | % | ||||||||||||||||||||||||||
| WTL | 473 | — | % | 668 | 1 | % | 1,141 | 1 | % | ||||||||||||||||||||||||||
| Midland WTI | 3,888 | 3 | % | 10,995 | 15 | % | 14,883 | 7 | % | ||||||||||||||||||||||||||
| Condensate | 4,331 | 3 | % | 7,666 | 10 | % | 11,997 | 6 | % | ||||||||||||||||||||||||||
| Heavy Canadian | 4,711 | 4 | % | — | — | % | 4,711 | 2 | % | ||||||||||||||||||||||||||
| Total crude throughput | 129,878 | 100 | % | 73,180 | 100 | % | 203,058 | 100 | % | ||||||||||||||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||||||||||||||||||||
| (in bpd) | Coffeyville | Wynnewood | Total | ||||||||||||||||||||||||||||||||
| Regional Crude | 31,350 | 25 | % | 54,746 | 73 | % | 86,096 | 43 | % | ||||||||||||||||||||||||||
| WTI | 66,952 | 54 | % | 2,354 | 3 | % | 69,306 | 35 | % | ||||||||||||||||||||||||||
| Midland WTI | 15,893 | 13 | % | 10,332 | 14 | % | 26,225 | 13 | % | ||||||||||||||||||||||||||
| Condensate | 4,992 | 4 | % | 7,237 | 10 | % | 12,229 | 6 | % | ||||||||||||||||||||||||||
| Heavy Canadian | 5,302 | 4 | % | — | — | % | 5,302 | 3 | % | ||||||||||||||||||||||||||
| Total crude throughput | 124,489 | 100 | % | 74,669 | 100 | % | 199,158 | 100 | % | ||||||||||||||||||||||||||
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Marketing and Distribution
Our Coffeyville product marketing efforts are focused in the central mid-continent area through rack marketing, which is the supply of product through tanker trucks and railcars directly to customers located in close geographic proximity to the refinery and to customers at terminals on third-party refined products distribution systems; and bulk sales into the mid-continent markets and other destinations utilizing third-party product pipeline networks.
The Wynnewood Refinery ships its finished product via pipeline, railcar, and truck, focusing its efforts in Oklahoma and parts of Arkansas, as well as eastern Missouri. The pipeline system is capable of multi-directional flow, providing access to Texas markets as well as adjoining states with pipeline connections. The Wynnewood Refinery also sells jet fuel to the U.S. Department of Defense via its segregated truck rack.
Customers
Customers for the Refineries’ petroleum products primarily include retailers, railroads, and farm cooperatives and other refiners/marketers in Group 3 of the PADD II region because of their relative proximity to the Refineries and pipeline access. We typically 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 (“OPIS”).
Rack sales are at posted prices that are influenced by the competitive forces in the Group 3 market. In addition, the Coffeyville Refinery sells hydrogen and by-products of its refining operations, such as pet coke, to an affiliate, CVR Partners, pursuant to multi-year agreements. For the year ended December 31, 2019, the top two customers accounted for 25% of the Petroleum Segment’s net sales.
Competition
Our Petroleum Segment competes primarily on the basis of price, reliability of supply, availability of multiple grades of products, and location. The principal competitive factors affecting its refining operations are cost of crude oil and other
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feedstocks, refinery complexity, refinery efficiency, refinery product mix, and product distribution and transportation costs. The location of the Refineries provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors. We primarily compete against five refineries 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, the Great Lakes, and the Texas panhandle region.
Seasonality
Our Petroleum Segment operations experience seasonal fluctuations 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, its results of operations for the first and fourth calendar quarters are generally lower compared to its 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 petroleum products can impact the demand for gasoline and diesel fuel.
Nitrogen Fertilizer
Our Nitrogen Fertilizer Segment is comprised of the assets and operations of CVR Partners, including two nitrogen fertilizer manufacturing facilities located in Coffeyville, Kansas and East Dubuque, Illinois.
Facilities
Coffeyville Fertilizer Facility - We own and operate a nitrogen fertilizer production facility in Coffeyville, Kansas that includes a gasifier complex having a capacity of 89 million standard cubic feet per day of hydrogen, a 1,300 ton per day capacity ammonia unit, and a 3,000 ton per day capacity UAN unit (the “Coffeyville Fertilizer Facility”). The Coffeyville Fertilizer Facility is the only nitrogen fertilizer plant in North America that utilizes a pet coke gasification process to produce nitrogen fertilizer. The Coffeyville Fertilizer Facility’s largest raw material expense used in the production of ammonia is pet coke, which it purchases from our Coffeyville Refinery and third parties. For the years ended December 31, 2019, 2018, and 2017, the Coffeyville Fertilizer Facility purchased approximately $20 million, $13 million, and $8 million, respectively, of pet coke, which equaled an average cost per ton of $37.47, $28.41, and $16.56, respectively. For the years ended December 31, 2019, 2018, and 2017, we upgraded approximately 90%, 93%, and 88%, respectively, of our ammonia production into UAN, a product that presently generates greater profit than ammonia. We upgrade substantially all of our ammonia production at the Coffeyville Facility into UAN and expect to continue to do so when the economics are favorable.
East Dubuque Fertilizer Facility - We own and operate a nitrogen fertilizer production facility in East Dubuque, Illinois that includes a 1,075 ton per day capacity ammonia unit and a 1,100 ton per day capacity UAN unit (the “East Dubuque Fertilizer Facility”). The East Dubuque Fertilizer Facility has the flexibility to vary its product mix enabling it to upgrade a portion of ammonia production into varying amounts of UAN, nitric acid, and liquid and granulated urea, depending on market demand, pricing, and storage availability. The East Dubuque Fertilizer Facility’s largest raw material expense used in the production of ammonia is natural gas, which it purchases from third parties. For the years ended December 31, 2019, 2018, and 2017, the East Dubuque Facility incurred approximately $21 million, $23 million, and $26 million for feedstock natural gas, respectively, which equaled an average cost of $3.08, $3.15, and $3.26 per MMBtu, respectively.
Commodities
The nitrogen products we produce are globally traded commodities and are subject to price competition. The customers for its products make their purchasing decisions principally on the basis of delivered price and, to a lesser extent, on customer service and product quality. The selling prices of its products fluctuate in response to global market conditions and changes in supply and demand.
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Agriculture
The three primary forms of nitrogen fertilizer used in the United States of America are ammonia, urea, and UAN. Unlike ammonia and urea, UAN can be applied throughout the growing season and can be applied in tandem with pesticides and herbicides, providing farmers with flexibility and cost savings. As a result of these factors, UAN typically commands a premium price to urea and ammonia, on a nitrogen equivalent basis.
Nutrients are depleted in soil over time and, therefore, must be replenished through fertilizer use. Nitrogen is the most quickly depleted nutrient and must be replenished every year, whereas phosphate and potassium can be retained in soil for up to three years. Plants require nitrogen in the largest amounts and it accounts for approximately 59% of primary fertilizer consumption on a nutrient ton basis, per the International Fertilizer Industry Association (“IFIA”).
Demand
Global demand for fertilizers is driven primarily by grain demand and prices, which, in turn, are driven by population growth, farmland per capita, dietary changes in the developing world and increased consumption of bio-fuels. According to the IFIA, from 1975 to 2017, global fertilizer demand grew 2% annually. Global fertilizer use, consisting of nitrogen, phosphate and potassium, is projected to increase by 34% between 2010 and 2030 to meet global food demand according to a study funded by the Food and Agricultural Organization of the United Nations. Currently, the developed world uses fertilizer more intensively than the developing world, but sustained economic growth in emerging markets is increasing food demand and fertilizer use. In addition, populations in developing countries are shifting to more protein-rich diets as their incomes increase, with such consumption requiring more grain for animal feed. As an example, China’s wheat and coarse grains production is estimated to have increased 36% between 2009 and 2019, but still failed to keep pace with increases in demand, prompting China to grow its wheat and coarse grain imports by more than 552% over the same period, according to the United States Department of Agriculture (“USDA”).
The United States is the world’s largest exporter of coarse grains, accounting for 25% of world exports and 27% of world production for the fiscal year ended September 30, 2019, according to the USDA. A substantial amount of nitrogen is consumed in production of these crops to increase yield. Based on Fertecon Limited’s (“Fertecon”) 2019 estimates, the United States is the world’s third largest consumer of nitrogen fertilizer and the world’s largest importer of nitrogen fertilizer. Fertecon is a reputable agency which provides market information and analysis on fertilizers and fertilizer raw materials for fertilizer and related industries, and international agencies. Fertecon estimates indicate that the United States represented 11% of total global nitrogen fertilizer consumption for 2019, with China and India as the top consumers representing 23% and 15% of total global nitrogen fertilizer consumption, respectively.
North American nitrogen fertilizer producers predominantly use natural gas as their primary feedstock. Over the last five years, U.S. oil and natural gas reserves have increased significantly due to, among other factors, advances in extracting shale oil and gas, as well as relatively high oil and gas prices. More recently, global demand has slowed with production staying steady even as oil and gas prices have declined substantially over the past two years. This has led to significantly reduced natural gas and oil prices as compared to historical prices. As a result, North America has become a low-cost region for nitrogen fertilizer production.
Raw Material Supply
Coffeyville Fertilizer Facility - During the past five years, just under 61% of the Coffeyville Fertilizer Facility’s pet coke requirements on average were supplied by our adjacent Coffeyville Refinery pursuant to a multi-year agreement. Historically, the Coffeyville Fertilizer Facility has obtained the remainder of its pet coke requirements through third-party contracts typically priced at a discount to the spot market. In 2019, our supply of pet coke from the Coffeyville refinery declined to approximately 40%, generally attributable to increased processing of shale crude oil, which reduced the amount of pet coke produced by the refinery and increased the amount of third-party purchases made at spot prices. Additionally, the Coffeyville Fertilizer Facility relies on a third-party air separation plant at its location that provides contract volumes of oxygen, nitrogen, and compressed dry air to the Coffeyville Fertilizer Facility gasifiers.
East Dubuque Fertilizer Facility - The East Dubuque Fertilizer Facility uses natural gas to produce nitrogen fertilizer. We are generally able to purchase natural gas at competitive prices due to the facilities’ connection to the Northern Natural Gas interstate pipeline system, which is within one mile of the facility, and a third-party owned and operated pipeline. The pipelines
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are connected to a third-party distribution system at the Chicago Citygate receipt point and at the Hampshire interconnect from which natural gas is transported to the East Dubuque Fertilizer Facility. As of December 31, 2019, we had commitments to purchase approximately 1 million MMBtus of natural gas supply for planned use in our East Dubuque Fertilizer Facility in both January and February of 2020 at a weighted average rate per MMBtu of approximately $2.67 and $2.66, respectively, exclusive of transportation cost.
Marketing and Distribution
Our Nitrogen Fertilizer Segment primarily markets UAN products to agricultural customers and ammonia products to agricultural and industrial customers. UAN and ammonia, including freight, accounted for approximately 70% and 24%, respectively, of our Nitrogen Fertilizer Segment’s net sales for the year ended December 31, 2019.
UAN and ammonia are primarily distributed by truck or by railcar. If delivered by truck, products are most commonly sold on a free-on-board (“FOB”) shipping point basis, and freight is normally arranged by the customer. We operate a fleet of railcars for use in product delivery. If delivered by railcar, the products are most commonly sold on a FOB destination point basis, and we typically arrange the freight.
The nitrogen fertilizer products leave the Coffeyville Fertilizer Facility either in railcars for destinations located principally on the Union Pacific or Burlington Northern Santa Fe railroads or in trucks for direct shipment to customers. The East Dubuque Fertilizer Facility primarily sells product to customers located within 200 miles of the facility. In most instances, customers take delivery of nitrogen products at the East Dubuque Fertilizer Facility and arrange to transport them to their final destinations by truck. Additionally, the East Dubuque Fertilizer Facility has direct access to a barge dock on the Mississippi River, as well as a nearby rail spur serviced by the Canadian National Railway Company.
Customers
We sell UAN products to retailers and distributors. In addition, we sell ammonia to agricultural and industrial customers. Given the nature of the nitrogen fertilizer business, and consistent with industry practice, most of our contracts with customers are for a term of 12-month or less. Some of our industrial sales include long-term purchase contracts. For the year ended December 31, 2019, the top two customers in the aggregate represented 28% of the Nitrogen Fertilizer Segment’s net sales.
Competition
Our Nitrogen Fertilizer Segment has experienced and expects to continue to meet significant levels of competition from current and potential competitors, many of whom have significantly greater financial and other resources. Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. We seasonally adjust inventory to enhance manufacturing and distribution operations.
Our major competitors in the nitrogen fertilizer business include CF Industries Holdings, Inc., including its majority owned subsidiary Terra Nitrogen Company, L.P.; LSB Industries, Inc.; Koch Fertilizer Company, LLC; and Nutrien Ltd. (formerly known as Agrium, Inc. and Potash Corporation of Saskatchewan, Inc.). Domestic competition is intense due to customers’ sophisticated buying tendencies and competitor strategies that focus on cost and service. We also encounter competition from producers of fertilizer products manufactured in foreign countries, including the threat of increased production capacity. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments.
Seasonality
Because the Nitrogen Fertilizer Segment primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers who make planting decisions based largely on the prospective profitability of a harvest. The specific varieties and amounts of fertilizer they apply depend on factors like crop prices, farmers’ current liquidity, soil conditions, weather patterns, and the types of crops planted. The Nitrogen Fertilizer Segment typically experiences higher net sales in the first half of the calendar year, which is referred to as the planting season, and its net sales tend to be lower during the second half of each calendar year, which is referred to as the fill season.
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Environmental Matters
Our petroleum and nitrogen fertilizer businesses are subject to extensive and frequently changing federal, state, and local, environmental, health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the transportation, storage, and disposal of waste, the treatment and discharge of waste water, the storage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline, diesel fuels, UAN and ammonia. These laws and regulations and the enforcement thereof impact our segments and their operations by imposing:
•restrictions on operations or the need to install enhanced or additional controls;
•liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and for off-site waste disposal locations; and
•specifications for the products marketed by the Petroleum and Nitrogen Fertilizer Segments, primarily gasoline, diesel fuel, UAN, and ammonia.
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 or could become more stringent or have or could become subject to more stringent interpretation or enforcement by federal or state agencies. These laws and regulations could result in increased capital, operating, and compliance costs.
The Federal Clean Air Act (“CAA”)
The CAA and its implementing regulations, as well as corresponding state laws and regulations governing air emissions, affect the Petroleum and Nitrogen Fertilizer Segments both directly and indirectly. Direct impacts may occur through the CAA’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 CAA affects the Petroleum and Nitrogen Fertilizer Segments 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 regulations promulgated pursuant to the CAA, or any future promulgations of regulations, may require the installation of controls or changes to the petroleum facilities and/or the nitrogen fertilizer facilities (collectively referred to as the “Facilities”) to maintain compliance. If new controls or changes to operations are needed, the costs could be material.
The regulation of air emissions under the CAA requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at our operations. Various standards and programs specific to our operations have been implemented, such as the National Emission Standard for Hazardous Air Pollutants, the New Source Performance Standards, and the New Source Review.
The Federal Clean Water Act (“CWA”)
The CWA and its implementing regulations, as well as the corresponding state laws and regulations that govern the discharge of pollutants into the water, affect the Petroleum and Nitrogen Fertilizer Segments. The CWA’s permitting requirements establish discharge limitations that may be based on technology standards, water quality standards, and restrictions on the total maximum daily load of pollutants allowed to enter a particular water body based on its use. In addition, water resources are becoming and in the future may become more scarce, and many refiners, including us, are subject to use restrictions in the event of low availability conditions. Our Refineries and the Coffeyville Fertilizer Facility have contracts in place to receive water during certain water shortage conditions, but these conditions could change over time depending on the scarcity of water.
Renewable Fuel Standards
Pursuant to the Energy Policy Act of 2005 and Energy Independence and Security Act of 2007 (“EISA”), the EPA has promulgated the Renewable Fuel Standard (“RFS”). The RFS requires refiners to either blend “renewable fuels,” such as ethanol and biofuels, into their transportation fuels or purchase renewable fuel credits, known as renewable identification numbers (“RINs”), in lieu of blending. Under the RFS, the volume of renewable fuels that refineries like Coffeyville and
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Wynnewood are obligated to blend into their finished transportation fuel is adjusted annually by the EPA based on fuel supply and other conditions to meet the statutory mandates that increase annually, but which may be waived by the EPA under certain conditions. The volume of renewable fuels required by EISA increased from 9 billion gallons in 2008 to 22 billion gallons in 2016 and increases to 36 billion gallons in 2022. The EPA has statutory authority to determine RFS volumes after 2022. In addition to the total renewable fuel volume mandate, there are sub-mandates for advanced biofuels, cellulosic biofuel, and biomass-based diesel. Under the cellulosic waiver authority provided to the EPA by the CAA, if the EPA’s projected volume of cellulosic biofuel for a calendar year is less than its statutory mandate, the EPA must reduce the required volume of cellulosic biofuel accordingly and provide obligated parties the opportunity to purchase cellulosic waiver credits. The EPA also has the discretion to reduce the total renewable fuel and advanced biofuel requirements by the same amount as it reduced the cellulosic biofuel volume. The Petroleum Segment (like many refiners) is not able to meet its annual renewable volume obligation (“RVO”) through blending, so it has had to purchase RINs on the open market as well as obtain cellulosic waiver credits from the EPA, in order to comply with the RFS. The cost of purchasing RINs and cellulosic waiver credits fluctuates and can be significant. The price of RINs has been extremely volatile as the EPA’s proposed renewable fuel volume mandates approached and exceeded the “blend wall.” The blend wall refers to the point at which the amount of ethanol blended into the transportation fuel supply exceeds the demand for transportation fuel containing such levels of ethanol. The blend wall is generally considered to be reached when more than 10% ethanol by volume (“E10 gasoline”) is blended into transportation fuel.
In May 2019, the EPA finalized regulatory changes to allow gasoline blended with up to 15 percent ethanol (“E15”) to take advantage of a waiver during the summer months that previously only applied to E10. Because E15 can now be sold year-round rather than just eight months of the year, a higher percentage of transportation fuels can be blended with renewable fuels. The E15 rule, however, is the subject of legal challenges in the District of Columbia Circuit (“D.C. Circuit”), which could lead to the rule being overturned. Also, in December 2019, the EPA published the final renewable fuel volumes for 2020, and the biomass-based diesel volume for 2021 (the “2020 RFS Final Rule”). As in past years, the volumes increased from the previous year, but with the exception of the volume for biomass-based diesel, are lower than the CAA statutory volume targets. The EPA set a lower volume for cellulosic biofuel based on the projected volume available for 2020 and used its cellulosic waiver authority under the CAA to set volumes below the statutory targets for advanced biofuel and total renewable fuel. In the rule, the EPA also finalized changes to the percentage standard calculations to account for volumes of gasoline and diesel that the EPA projects will be exempted from the renewable volume obligations moving forward.
Additional RFS-related rulemakings may occur in 2020. One relates to a lawsuit in the U.S. Court of Appeals for the D.C. Circuit in which several biofuels groups challenged the EPA’s final renewable fuels volumes for 2014 through 2016. In July 2017, the D.C. Circuit vacated the EPA’s decision to reduce the 2016 volumes under its “inadequate domestic supply” waiver authority and remanded the rule to the EPA for further reconsideration. In its proposed rule for the 2020 renewable fuel volumes, the EPA responded to the remand by proposing that the 2016 volume requirement for total renewable fuel should not be changed. In its final rule, however, the EPA noted that it was still actively considering this issue and did not expect to take final agency action until early 2020. When the EPA re-proposes the 2016 renewable volume obligations, there could be an increase in the volume mandates for 2016 and, as a result, the Coffeyville Refinery and the Wynnewood Refinery could be required to purchase more RINs for 2016 compliance.
Another rulemaking that was previously anticipated but has since been withdrawn involves the CAA “reset” provision. Under the reset provision, if the EPA waives the statutory volumes for any of the four fuel categories by at least 20% for two consecutive years or by at least 50% for a single year, then the EPA must modify the statutory volumes for all subsequent years for that fuel category. The reset has been triggered in previous years for both advanced biofuel and cellulosic biofuel and, most recently, the rules setting the 2019 renewable fuel volume requirements triggered the reset provision for total renewable fuel. In October 2018, the EPA reported that it would begin rulemaking in 2019 to reset the volumes for cellulosic biofuel, advanced biofuel, and total renewable fuel for compliance years 2020-2022. In May 2019, the EPA delivered its proposed “reset” rule to the Office of Management and Budget (“OMB”), which is the final step before the EPA can release a proposed rule for public review. Then, in December 2019, the agency withdrew its draft proposal. The EPA has not indicated how it will address the reset requirement moving forward, but if the EPA does pursue a reset rulemaking, it may modify the volumes, in either case impacting the Coffeyville Refinery’s and the Wynnewood Refinery’s obligations under the RFS.
Greenhouse Gas Emissions (“GHG”)
The EPA regulates GHG emissions under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of GHGs to inventory and report their GHG emissions to the EPA. In accordance with the rule, our Facilities monitor and report our GHG emissions to the EPA. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which established GHG emissions thresholds that determine when stationary sources, such as the Refineries and the nitrogen
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fertilizer facilities, must obtain permits under Prevention of Significant Deterioration (“PSD”) and Title V programs of the federal Clean Air Act. Under the rule, facilities already subject to the PSD and Title V programs that increase their emissions of GHGs by a significant amount are required to undergo PSD review and to evaluate and implement air pollution control technology, known as “best available control technology,” to reduce GHG emissions.
In December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate New Source Performance Standards (“NSPS”) to regulate GHG emissions from petroleum refineries and electric utilities by November 2012. In September 2014, the EPA indicated that the petroleum refining sector risk rule, proposed in June 2014 to address air toxics and volatile organic compounds from refineries, may make it unnecessary for the EPA to regulate GHG emissions from petroleum refineries at this time. The final rule, which was published in the Federal Register on December 1, 2015, addresses air toxics and volatile organic compounds and places additional emission control requirements and work practice standards on FCCUs, storage tanks, flares, coking units, and other equipment at petroleum refineries. Therefore, we do not currently expect the EPA to issue regulations on GHG emissions from petroleum refineries at this time, but that it may do so in the future.
In October 2015, the EPA published the Clean Power Plan, which established NSPS for carbon dioxide emissions from electric utilities. However, since the change in administration in 2017, the EPA has shifted its regulatory approach of GHG emissions. In December 2018, the EPA proposed amendments to the Clean Power Plan that, among other things, would replace the determination of the best system of emission reduction (“BSER”) with a less costly and burdensome BSER determination for new coal-fired units. In June 2019, the EPA issued the final Affordable Clean Energy (“ACE”) Rule to replace the 2015 Clean Power Plan, which represented the Obama administration’s signature policy to regulate GHGs. The ACE rule establishes new emission guidelines for states to address GHGs from existing coal-fired power plants and update the BSER for those facilities. The ACE rule is being challenged in the courts by multiple states and a coalition of environmental organizations.
The EPA’s approach to regulating GHG emissions may change again under future administrations. Therefore, the impact on our Facilities due to future GHG regulation is unknown.
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) and the Emergency Planning and Community Right-to-Know Act (“EPCRA”)
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 also periodically experience releases of hazardous and extremely hazardous substances from their equipment and periodically have excess emission 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 CERCLA and the EPCRA. If we fail to timely or properly report a release, or if a release violates the law or our permits, we could 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.
Resource Conservation and Recovery Act (“RCRA”)
Our facilities 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.
Impacts of Past Manufacturing - In March 2004, two of our subsidiaries entered into a Consent Decree (“2004 Consent Decree”) with the EPA and the Kansas Department of Health and Environment (the “KDHE”) which required us to assume two RCRA corrective action orders issued to Farmland, the prior owner of the Coffeyville Refinery. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville Refinery. In accordance with the order, we have conducted the required investigation and interim remediation projects and documented existing soil and groundwater conditions. In June 2017, the Coffeyville Refinery submitted an amended RCRA post-closure permit application to the KDHE to complete closure of former hazardous waste management units at the Coffeyville Refinery and to perform corrective action at the site. The KDHE approved the permit application report in July 2019, and we anticipate that the RCRA permit will be issued in 2020. The now-closed Phillipsburg terminal is subject to a
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1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. The Phillipsburg terminal investigation is complete and corrective measures are in place implementing the EPA’s Statement of Basis and Final Remedy Decision issued in July 2018. 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, Wynnewood Refining Company, LLC (“WRC”) entered into a consent order with the Oklahoma Department of Environmental Quality (“ODEQ”) requiring further investigations of groundwater conditions and enhancements of existing remediation systems. We have completed the groundwater investigation at the Wynnewood Refinery and the ODEQ has approved our ongoing corrective actions. The consent order was terminated by the ODEQ in July 2019.
Financial Assurance - We are required, under the 2004 Consent Decree, to establish financial assurance to secure the current projected clean-up costs of $6 million for the Coffeyville Refinery and $5 million for the now-closed Phillipsburg terminal 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 Coffeyville Resources Refining and Marketing, LLC (“CRRM”), Coffeyville Resources Terminal, LLC (“CRT”), the EPA, and the KDHE, this financial assurance is currently provided by a bond in the amount of $2 million for clean-up obligations at the Phillipsburg terminal and a letter of credit in the amount of $0.3 million for estimated costs to close regulated hazardous waste management units at the Coffeyville Refinery. Additional self-funded financial assurance of approximately $6 million and $3 million is required to meet our RCRA financial assistance obligations for the Coffeyville Refinery and Phillipsburg terminal, respectively. The $2 million bond amount is reduced each year based on actual expenditures for corrective actions and the letter of credit and the self-funded mechanisms are re-evaluated and adjusted on an annual basis. Current RCRA financial assurance requirements for the Wynnewood Refinery total $0.2 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.
Waste Management - There are two closed hazardous waste units at the Coffeyville Refinery and fourteen other solid waste management units in the process of being closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewood Refinery. In addition, one closed, interim status, hazardous waste landfarm located at the now-closed Phillipsburg terminal is under long-term post-closure care.
Environmental Remediation
As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination and personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of, or released. There is no assurance that we will not become involved in future proceedings related to the release of hazardous or extremely hazardous substances or crude oil for which we have potential liability 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 a site pollution legal liability insurance policy. The policy includes business interruption coverage. The policy insures any location owned, leased or rented or operated by the Company, including the Refineries and the nitrogen fertilizer facilities. 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 maintain umbrella and excess casualty insurance policies which include sudden and accidental pollution coverage. This insurance provides coverage due to named perils for claims involving pollutants where the discharge is sudden and accidental and first commences at a specific day and time during the policy period.
The site pollution legal liability policy and the pollution coverage provided in the casualty insurance policies are subject to retentions and deductibles and contain discovery requirements, reporting requirements, exclusions, definitions, conditions, and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.
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Health, Safety 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 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, consultants, and advisors 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 seek to continually improve our management systems.
Refer to Part II, Item 8, Note 11 (“Commitments and Contingencies”), “Wynnewood Refinery Incident” of this Report for further discussion of OSHA.
Employees
As of December 31, 2019, the Company had approximately 1,486 employees including those employed by CVR Refining, CVR Partners, and the Company and its other subsidiaries’ corporate support functions. Our Petroleum Segment had approximately 971 employees at December 31, 2019 across both of its refineries and its logistics operations, including approximately 511 employees covered by collective bargaining agreements that expire on various dates ranging from June 2021 to March 2023. Our Nitrogen Fertilizer Segment had approximately 286 employees at December 31, 2019 across both of its facilities and its marketing and logistics operations, including approximately 90 employees covered by collective bargaining agreements that expire in October 2023.
Available Information
Our website address is www.cvrenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are available free of charge through our website under “Investor Relations,” as soon as reasonably practicable after the electronic filing or furnishing of these reports is made with the Securities and Exchange Commission (the “SEC”) at www.sec.gov. In addition, our Corporate Governance Guidelines, Codes of Ethics and Business Conduct, and Charters of the Audit Committee, the Nominating and Corporate Governance Committee, and the Compensation Committee of the Board of Directors are available on our website. These guidelines, policies, and charters are also available in print without charge to any stockholder requesting them. We do not intend for information contained in our website to be part of this Report.
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Item 1A. Risk Factors
The following risks should be considered together with the other information contained in this Report and all of the information set forth in our filings with the SEC. If any of the following risks or uncertainties develops into actual events, our petroleum and/or nitrogen fertilizer businesses, financial conditions, or results of operations could be materially adversely affected. References to CVR Energy, the Company, “we”, “us”, and “our” may refer to consolidated subsidiaries of CVR Energy, including CVR Refining or CVR Partners, as the context may require.
Risks Related to Our Entire Business
Our petroleum and nitrogen fertilizer businesses are, and commodity prices are, cyclical and highly volatile, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Our Petroleum Segment’s financial results are primarily affected by margin between refined product prices and the prices for crude oil and other feedstocks. Historically, refining margins have been volatile, and we believe they will continue to be volatile in the future. Our cost to acquire feedstocks and the price at which we can ultimately sell refined products depend upon several factors beyond our control, including regional and global supply of and demand for crude oil, gasoline, diesel, and other feedstocks and refined products. These in turn depend on, among other things, the availability and quantity of imports, the production levels of U.S. and international suppliers, levels of refined petroleum product inventories, productivity and growth (or the lack thereof) of U.S. and global economies, U.S. relationships with foreign governments, political affairs, and the extent of governmental regulation.
Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects on refining and marketing margins, which are uncertain. We do not produce crude oil and must purchase all of the crude oil we refine long before we refine it and sell the refined products. Price level changes during the period between purchasing feedstocks and selling the refined petroleum products from these feedstocks could have a significant effect on our financial results. A decline in market prices may negatively impact the carrying value of our inventories.
Our Petroleum Segment profitability is also impacted by the ability to purchase crude oil at a discount to benchmark crude oils, such as WTI. Crude oil differentials can fluctuate significantly based upon overall economic and crude oil market conditions. Adverse changes in crude oil differentials can adversely impact refining margins, earnings and cash flows. In addition, the Petroleum Segment’s purchases of crude oil, although based on WTI prices, have historically been at a discount to WTI because of the proximity of the refineries to the sources, existing logistics infrastructure, and quality differences. Any changes to these factors could result in a reduction of the discount to WTI and may result in a reduction of the Petroleum Segment’s cost advantage.
Our Nitrogen Fertilizer Segment is exposed to fluctuations in nitrogen fertilizer demand in the agricultural industry. These fluctuations historically have had and could in the future have significant effects on prices across all nitrogen fertilizer products and, in turn, our results of operations, financial condition and cash flows.
Nitrogen fertilizer products are commodities, the price of which can be highly volatile. The prices of nitrogen fertilizer products depend on a number of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, governmental policies, and weather conditions, which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which we base our production levels, customers may acquire nitrogen fertilizer products from competitors, and our profitability may be negatively impacted. If seasonal demand is less than expected, we may be left with excess inventory that will have to be stored or liquidated.
Demand for nitrogen fertilizer products is dependent on demand for crop nutrients by the global agricultural industry. The international market for nitrogen fertilizers is influenced by such factors as the relative value of the U.S. dollar and its impact upon the cost of importing nitrogen fertilizers, foreign agricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign markets, changes in the hard currency demands of certain countries, and other regulatory policies of foreign governments, as well as the laws and policies of the United States affecting foreign trade and investment. Nitrogen-based fertilizers remain solidly in demand, driven by a growing world population, changes in dietary habits, and an expanded use of corn for the production of ethanol. Supply is affected by available capacity and operating rates, raw material costs, government policies, and global trade. A decrease in nitrogen fertilizer prices would have a material adverse effect on our nitrogen fertilizer business and cash flow, including CVR Partners’ ability to make distributions.
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Additionally, volatile prices for natural gas and electricity affect both segments’ 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.
Petroleum and nitrogen fertilizer products are global commodities, and our businesses face intense competition from other refining and marketing companies and nitrogen fertilizer producers, which may have more resources and scale.
The refining industry is highly competitive with respect to both crude oil and other feedstock supply and refined petroleum product markets. We compete with many companies for available supplies of crude oil and other feedstocks and for sites for our refined petroleum products. Our Petroleum Segment may be unable to compete effectively with competitors within and outside of the industry, which could result in reduced profitability. We do not have a retail business and therefore are dependent upon others for outlets for our refined products, and we do not have arrangements exceeding a twelve-month period for much of our petroleum output. Many of our competitors, however, obtain a significant portion of their feedstocks from company-owned production and some have extensive retail sites. Such competitors 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. Some of our competitors also have materially greater financial and other resources than we have. Such competitors have a greater ability to bear the economic risks inherent in all phases of our industry.
In addition, our Petroleum Segment competes with other industries that provide alternative means to satisfy the energy and fuel requirements of its industrial, commercial, and individual customers. There are presently significant governmental incentives and consumer pressures to increase the use of alternative fuels in the United States. The more successful these alternatives become as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing, or otherwise, the greater the negative impact on pricing and demand for our products and profitability.
Our Nitrogen Fertilizer Segment is subject to intense price competition from both U.S. and foreign sources. Fertilizers are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. Increased global supply or decreases in transportation costs for foreign sources of fertilizer may put downward pressure on fertilizer prices. Furthermore, in recent years, the price of nitrogen fertilizer in the United States has been substantially driven by pricing in the global fertilizer market. We compete with a number of U.S. producers and producers in other countries, including state-owned and government-subsidized entities. Some competitors have greater total resources and are less dependent on earnings from fertilizer sales, which make them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. Additionally, our competitors utilizing different corporate structures may be better able to withstand lower cash flows than our Nitrogen Fertilizer Segment can as a limited partnership. Our competitive position could suffer to the extent we are unable to expand resources either through investments in new or existing operations or through acquisitions, joint ventures, or partnerships. An inability to compete successfully could result in a loss of customers, which could adversely affect our sales, profitability, and cash flows and, therefore, have a material adverse effect on our results of operations, financial condition and cash flows.
Our businesses are geographically concentrated and are, therefore, subject to regional economic downturns and seasonal variations, which may affect our production levels, transportation costs, and inventory and working capital levels.
Our Refineries are both located in the southern portion of Group 3 of the PADD II region, and we primarily market refined products in a relatively limited geographic area. As a result, our Petroleum Segment is more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect its operating area could also materially adversely affect its revenues and cash flows. 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. In addition, if we deliver refined products to customers outside of the region, we may incur considerably higher transportation costs, resulting in lower refining margins, if any.
Our Nitrogen Fertilizer Segment’s sales to agricultural customers are concentrated in the Great Plains and Midwest states, and nitrogen fertilizer demand is seasonal. Our quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. Farmers tend to apply nitrogen fertilizer during two short application periods, one in the spring and the other in the fall. In contrast, we, along with other nitrogen fertilizer producers, generally produce products throughout the year. As a result, we and our customers generally build inventories during the low demand periods of the year to ensure timely product availability during peak sales seasons. Variations in the proportion of product sold through prepaid sales contracts and the terms of such contracts can increase the seasonal volatility of our cash
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flows and cause changes in the patterns of seasonal volatility from year-to-year. Additionally, the accumulation of inventory to be available for seasonal sales creates significant seasonal working capital and storage capacity requirements. The degree of seasonality can change significantly from year-to-year due to conditions in the agricultural industry and other factors. As a consequence of this seasonality, distributions by our Nitrogen Fertilizer Segment of available cash, if any, may be volatile and may vary quarterly and annually.
Both the Petroleum and Nitrogen Fertilizer Segments depend on significant customers, and the loss of several significant customers may have a material adverse impact on our results of operations, financial condition and cash flows.
The Petroleum and Nitrogen Fertilizer Segments both have a significant concentration of customers. The two largest customers of our Petroleum Segment represented 25% of its net sales for the year ended December 31, 2019. The two largest customers of the Nitrogen Fertilizer Segment represented approximately 28% of its net sales for the same period. Given the nature of our businesses, and consistent with industry practice, we do not have long-term minimum purchase contracts with our customers. The loss of several of these significant customers, or a significant reduction in purchase volume by several of them, could have a material adverse effect on our results of operations, financial condition and cash flows.
Compliance with and changes in environmental laws and regulations, including those related to climate change, could require us to make substantial capital expenditures and adversely affect our performance.
Our operations are subject to extensive 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 use and specifications, and the generation, treatment, storage, transportation, disposal, and remediation of solid and hazardous wastes.
Violations of applicable environmental laws and regulations or of the conditions of permits issued thereunder can result in substantial penalties, injunctive orders compelling installation of additional controls or other injunctive relief, civil and criminal sanctions, operating restrictions, permit revocations, and/or facility shutdowns, which may have a material adverse effect on our ability to operate our facilities and accordingly our financial performance. Capital expenditures and operating costs for current and future environmental compliance may be substantial and could have a material adverse effect on our segments’ results of operations, financial condition and profitability.
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. These laws and regulations are generally expected to impose increasingly stringent, and costly requirements over time. Various legislative and regulatory measures to address climate change and GHG emissions (including carbon dioxide, methane, and nitrous oxides) are in various phases of discussion or implementation and could affect our operations. They include proposed and enacted federal regulation and state actions to develop statewide, regional, or nationwide programs designed to control and reduce GHG emissions from fixed sources, such as our refineries and fertilizer facilities, and transportation fuels. Many states and regions have implemented, or are in the process of implementing, measures to reduce emissions of GHGs, but other than Kansas, we do not currently operate in states that have their own GHG reduction programs.
Although it is not possible to predict the requirements of any GHG legislation that may be enacted, any laws or regulations that have been or may be adopted to restrict or reduce GHG emissions will likely require us to incur increased operating and capital costs and/or increased taxes on GHG emissions. If we are unable to maintain sales of our products at a price that reflects such increased costs, there could be a material adverse effect on our business, financial condition and results of operations.
In addition, climate change legislation and regulations may result in increased costs not only for us but also users of our fertilizer products, thereby potentially decreasing demand for our products. Further, changes in environmental laws and regulations or their interpretation relating to the end-use and application of fertilizers could cause changes in demand for our products or limit our ability market and sell products to end users. From time to time, various state legislatures have proposed bans or other limitations on fertilizer products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.
Our facilities face 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
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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 facilities, logistics assets, 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. In addition, the risk exposures we have at the Coffeyville, Kansas plant complex are greater due to production facilities, as well as distribution and storage, for petroleum and nitrogen fertilizer being in relatively close proximity and potentially exposed to damage from one incident. Operations at either or both of the facilities 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 difficulties that result in a work stoppage or slowdown;
•cessation or suspension of a plant or specific operations dictated by environmental authorities;
•acts of terrorism or other deliberate malicious acts; 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 facilities, 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. We are insured under casualty, environmental, property, and business interruption insurance policies. The property and business interruption policies insure real and personal property, including property located at our facilities. There is potential for a common occurrence to impact both our Coffeyville Refinery and Coffeyville Fertilizer Facility, in which case the insurance limits and applicable sub-limits would apply to all damages combined. These policies are subject to limits, sub-limits, retention (financial and time-based), and deductibles. The application of these and other policy conditions could materially impact insurance recoveries and potentially cause us to assume losses which could impair earnings.
There is finite capacity in the commercial insurance industry engaged in underwriting energy industry risk, and there are risks associated with the commercial insurance industry reducing capacity, changing the scope of insurance coverage offered, and substantially increasing premiums, deductibles, or retainers, and/or waiting periods, resulting from highly adverse loss experience or other financial circumstances. Factors that impact insurance cost and availability include, but are not limited to: losses in our industries, natural disasters, specific losses incurred by us, and low or inadequate investment returns earned by the insurance industry. If the supply of commercial insurance is curtailed due to highly adverse financial results, we may not be able to continue our present limits of insurance coverage or obtain sufficient insurance capacity to adequately insure our risks for property damage or business interruption.
We could incur significant costs in cleaning up contamination at our refineries, terminals, fertilizer facilities, and off-site locations.
Our businesses handle petroleum and hazardous substances, and as a result, spills, discharges, or other releases of petroleum or hazardous substances into the environment may occur. Past or future spills related to any of our current or former operations, including refineries, pipelines, product terminals, and fertilizer facilities, 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 such contamination occurred prior to or during our ownership), facilities we formerly owned or operated, and facilities to which we transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal. If significant unknown contamination is identified at or migrating from any of our facilities,
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the associated liability could have a material adverse effect on our results of operations, financial condition and cash flows and may not be covered by insurance.
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 cash flows. 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.
Remedial activities to address known environmental contamination are underway at three of our facilities, including the Coffeyville Refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), and the Wynnewood Refinery. We also have assumed the previous owner’s responsibilities under certain administrative orders under RCRA related to contamination at or that originated from the Coffeyville Refinery and the Phillipsburg terminal. We continue to work with the applicable governmental authorities to implement remediation of these three sites on a timely basis. As of December 31, 2019, we have established an accrual of approximately $6 million for probable and reasonably estimable obligations associated with these sites.
We may incur future liability relating to the off-site disposal of solid and hazardous waste from our facilities. 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 associated with any such proceedings could be material.
New regulations concerning the transportation, storage, and handling of hazardous chemicals, risks of terrorism, and the security of refineries and chemical manufacturing facilities could result in higher operating costs.
The costs of complying with future regulations relating to the transportation, storage, and handling of hazardous chemicals and security associated with the refining and nitrogen fertilizer facilities may have a material adverse effect on our results of operations, financial condition and cash flows. Targets such as refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, the petroleum and chemical industries are subject to regulatory initiatives relating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition and cash flows.
We may be unable to obtain or renew permits or approvals necessary for our operations, which could inhibit our ability to do business.
Our businesses 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 and 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.
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, the proper design, operation, and maintenance of our equipment, and require us to provide information about hazardous materials used in our operations. Failure to comply with these requirements 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.
A significant 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.
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As of December 31, 2019, approximately 53% and 31% of our petroleum and nitrogen fertilizer employees, respectively, were represented by labor unions under collective bargaining agreements. 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.
We are subject to cybersecurity risks and other cyber incidents resulting in disruption.
We depend on internal and third-party information technology systems to manage and support our operations. In addition, we collect, process, and retain sensitive and confidential customer information in the normal course of business. Despite the security measures we have in place and any additional measures we may implement in the future, our facilities and these systems could be vulnerable to security breaches, computer viruses, lost or misplaced data, programming errors, human errors, acts of vandalism, or other events. Any disruption of these systems or security breach or event resulting in the misappropriation, loss, or other unauthorized disclosure of confidential information, whether by us directly or our third-party service providers, could damage our reputation, expose us to the risks of litigation and liability, disrupt our business, or otherwise affect our results of operations. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs. Any failure to comply with these laws and regulations, including as a result of a security or privacy breach, could result in significant penalties and liabilities for us.
The acquisition and expansion strategy of our businesses involves significant risks.
From time to time, we may consider pursuing acquisitions and expansion projects 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, including but not limited to new regulatory obligations and risks.
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 and the need to modify systems or to add management resources;
•Difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;
•Assumption of unknown material liabilities or regulatory non-compliance issues;
•Amortization of acquired assets, which would reduce future reported earnings;
•Possible adverse short-term effects on our cash flows or operating results; and
•Diversion of management’s attention from the ongoing operations of our business.
In addition, in connection with any potential acquisition or expansion project specific to CVR Partners (our Nitrogen Fertilizer Segment), we will need to consider whether a business we intend to acquire or expansion project we intend to pursue could affect CVR Partners’ tax treatment as a partnership for federal income tax purposes. If CVR Partners is otherwise unable to conclude that the activities of the business being acquired or the expansion project would not affect its treatment as a partnership for federal income tax purposes, it 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 the business in a competitive disadvantage compared to other potential acquirers who do not seek such a ruling. If CVR Partners is otherwise unable to conclude that an activity would not affect its treatment as a partnership for federal income tax purposes and is unable or unwilling to obtain an IRS ruling, we may choose to acquire such business or develop such expansion project in a corporate subsidiary of CVR Partners, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of
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cash available for distribution to CVR Partners’ common unitholders and could likely cause a substantial reduction in the value of its 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 cash flows. Our joint ventures involve similar risks. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.
Risks Related to the Petroleum Segment
If our Petroleum Segment is required to obtain its crude oil supply without the benefit of a crude oil supply agreement, its exposure to the risks associated with volatile crude oil prices may increase and its liquidity may be reduced.
Our Petroleum Segment obtains substantially all of its crude oil supply for the Coffeyville Refinery, other than the crude oil it gathers, through the Vitol Agreement. The Vitol Agreement also includes the provision of crude oil intermediation services to the Wynnewood Refinery. The agreement, which currently extends through December 31, 2020, 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 Petroleum Segment’s exposure to crude oil pricing risk may increase, despite any hedging activity in which it may engage, and its liquidity could be negatively impacted due to increased inventory, potential need to post letters of credit, and negative impacts of market volatility. There is no assurance that we will be able to renew or extend the Vitol Agreement beyond December 31, 2020.
Disruption of the Petroleum Segment’s ability to obtain an adequate supply of crude oil could reduce its liquidity and increase its costs.
In addition to the crude oil purchased under the Vitol Agreement, our Petroleum Segment gathered and purchased primarily in Kansas, Oklahoma, and Texas. The Wynnewood Refinery has historically acquired most of its crude oil from our gathering operations in Oklahoma and Texas, with smaller amounts purchased from other regions. In 2019, the Coffeyville Refinery obtained approximately 4% of its non-gathered crude oil from Canada. The actual amount of Canadian crude oil we purchase is dependent on market conditions and will vary from year-to-year. Disruption of production for any reason could have a material impact on the Petroleum Segment. In the event that one or more of its traditional suppliers becomes unavailable, we may be unable to obtain an adequate supply of crude oil, or we may only be able to obtain crude oil at unfavorable prices. As a result, we may experience a reduction in liquidity and our results of operations could be materially adversely affected.
If our access to the pipelines on which the Petroleum Segment relies for the supply of its crude oil and the distribution of its products is interrupted, its inventory and costs may increase and it may be unable to efficiently distribute its products.
If one of the pipelines on which either of the Refineries relies for supply of crude oil becomes inoperative, the Petroleum Segment would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase its 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 its customers through an alternative pipeline or by additional tanker trucks, which could increase the Petroleum Segment’s costs and result in a decline in profitability.
Compliance with the U.S. Environmental Protection Agency Renewable Fuel Standard could adversely affect our performance.
The U.S. Environmental Protection Agency (“EPA”) has promulgated and implemented a Renewable Fuel Standard (“RFS”) pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. Under the RFS program, a Renewable Identification Number (“RIN”) is assigned to each gallon of renewable fuel produced in or imported into the U.S. The RFS program sets annual mandates for the volume of renewable fuels (such as ethanol and biodiesel) that must be blended into a refiner’s transportation fuels. If a refiner of petroleum-based transportation fuels is unable to meet its renewable fuel mandate though blending, it must purchase RINs in the open market to meet its obligations under the RFS program.
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Our Petroleum Segment is exposed to the volatility in the market price of RINs, which can be extreme. We cannot predict the future prices of RINs. RIN prices are dependent upon a variety of factors, including EPA regulations, the availability of RINs for purchase, and levels of transportation fuels produced, the mix of the petroleum business’ petroleum products, as well as the fuel blending performed at the Refineries and downstream terminals, all of which can vary significantly from period to period. Additionally, because the petroleum business does not produce renewable fuels, increasing the volume of renewable fuels that must be blended into its products displaces an increasing volume of the Refineries’ product pool, potentially resulting in lower earnings and materially adversely affecting the petroleum business’ cash flows. If sufficient RINs are unavailable for purchase, if the Petroleum Segment has to pay a significantly higher price for RINs, or if the Petroleum Segment is otherwise unable to meet the EPA’s RFS mandates or is unable to participate in programs relieving compliance with RFS obligations, our business, financial condition and results of operations could be materially adversely affected. For the years ended December 31, 2019, 2018, and 2017, we recognized expense totaling $43 million, $60 million, and $249 million, respectively, to comply with RFS. Based upon recent market prices of RINs and current estimates related to the other variable factors, our estimated cost to comply with RFS in 2020 is $100 to $110 million.
Changes in CVR Refining’s credit profile may affect its relationship with its suppliers, which could have a material adverse effect on our liquidity and ability to operate the Refineries at full capacity.
Changes in CVR Refining’s 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 purchases or require it 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 liquidity and our ability to make payments to suppliers. This, in turn, could cause us to be unable to operate the Refineries at full capacity. A failure to operate at full capacity could adversely affect our profitability and cash flows.
The Petroleum Segment’s commodity derivative contracts may limit potential gains, exacerbate potential losses, and involve other risks.
We may enter into commodity derivatives contracts to mitigate crack spread risk with respect to a portion of expected refined products production. However, hedging arrangements, if we are able to procure them, may fail to fully achieve this objective for a variety of reasons, including its failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of hedging arrangements to produce the anticipated results. 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 its 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 a refinery, suppliers, or customers;
•the counterparties to its 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 cash flows.
Additionally, since we do not apply hedge accounting to its commodity derivative contracts, gains and losses are charged to its earnings based on the increase or decrease in the market value of derivative positions. Such gains and losses are reflected in its income statement in periods that differ from when the underlying hedged items (i.e., gross margin) 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 Petroleum Segment’s operational performance.
We must make substantial capital expenditures in the 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 project economics deteriorate, our financial condition, results of operations or cash flows could be adversely affected.
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Our Refineries have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep operating at optimum efficiency. These refineries generally require facility turnaround every four to five years. Delays or cost increases related to the engineering, procurement, and construction of new facilities, or improvements and repairs to existing facilities and equipment, could have a material adverse effect on our financial condition, results of operations or cash flows. 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 vendors and suppliers;
•shortages of sufficiently skilled labor or labor disagreements resulting in unplanned work stoppages;
•market-related increases in a project’s debt or equity financing costs; and/or
•non-performance or force majeure by, or disputes with, the Petroleum Segment’s vendors, suppliers, contractors, or sub-contractors.
Any one or more of these occurrences noted above could have a significant impact on our petroleum business. If we are unable to make up for the delays or to recover the related costs, or if market conditions change, we could materially and adversely affect our financial position, results of operations or cash flows.
More stringent trucking regulations may increase our petroleum business’ costs and negatively impact results of operations.
In connection with the trucking operations conducted by our crude gathering division, our petroleum business operates as a motor carrier and, therefore, is subject to regulation by federal and various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, and hazardous materials labeling, placarding, and marking. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry. Some of these possible changes include increasingly stringent fuel-economy 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 or electronic logging devices, or limits on vehicle weight and size.
To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. 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 our Petroleum Segment and its operations.
Risks Related to the Nitrogen Fertilizer Segment
Any decline in U.S. agricultural production or limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effect on the sales of nitrogen fertilizer, and on our results of operations, financial condition and cash flows.
Conditions in the U.S. agricultural industry significantly impact our operating results. The U.S. agricultural industry can be affected by a number of factors, including weather patterns and field conditions, current and projected grain inventories and prices, domestic and international population changes, demand for U.S. agricultural products, and U.S. and foreign policies regarding trade in agricultural products. For example, a major factor underlying the solid level of demand for nitrogen-based fertilizer products we produce is the use of corn for the production of ethanol in the U.S. Changes in governmental incentives for ethanol production could affect future ethanol demand and production.
State and federal governmental policies, including farm and biofuel subsidies and commodity support programs, as well as the prices of fertilizer products, may also directly or indirectly influence the number of acres planted, the mix of crops planted,
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and the use of fertilizers for particular agricultural applications. Developments in crop technology could also reduce the use of chemical fertilizers and adversely affect the demand for nitrogen fertilizer. In addition, from time to time various state legislatures have considered limitations on the use and application of chemical fertilizers due to concerns about the impact of these products on the environment. Unfavorable state and federal governmental policies could negatively affect nitrogen fertilizer prices and therefore have a material adverse effect on our results of operations, financial condition and cash flows.
Ethanol production in the United States is highly dependent upon a myriad of federal statutes and regulations, and is made significantly more competitive by various federal and state incentives and mandated usage of renewable fuels pursuant to the EPA’s RFS. To date, the RFS has been satisfied primarily with corn-based fuel ethanol blended into gasoline. However, a number of factors, including the continuing “food versus fuel” debate and studies showing that expanded ethanol usage may increase the level of GHGs in the environment, cause harmful conversion of uncultivated land for biofuel crop productions, and be unsuitable for small engine use, have resulted in calls to reduce subsidies for ethanol, allow increased ethanol imports, and to repeal or waive (in whole or in part) the current RFS. Changes within the RFS program also could affect future ethanol demand and production. Further, while most ethanol is currently produced from corn and other raw grains, such as milo or sorghum, the RFS requires that a portion of the overall RFS renewable fuel mandate come from advanced biofuels, including cellulose-based biomass, such as agricultural waste, forest residue, and municipal solid waste. In addition, there is a continuing trend to encourage the use of products other than corn and raw grains for ethanol production. The repeal of, or reduction in the benefits to ethanol producers under, ethanol incentive programs, an increase in ethanol imports, a substantial decrease in future RVOs under the RFS program, or a significant increase in the use of products other than corn and raw grains for ethanol production could affect the demand for corn-based ethanol and result in a decrease in planted corn acreage and in the demand for nitrogen fertilizer products and have a material adverse effect on our results of operations, financial condition and cash flows.
Our Coffeyville Facility may be adversely affected by the supply and price levels of pet coke. Failure by CVR Energy’s Coffeyville Refinery to continue to supply us with pet coke and the availability of third-party pet coke at higher prices could negatively impact our results of operations.
Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose costs are therefore largely variable, our Coffeyville Fertilizer Facility uses a pet coke gasification process to produce nitrogen fertilizer. Our profitability is directly affected by the price and availability of pet coke obtained from our Coffeyville Refinery pursuant to a long-term agreement. Our Coffeyville Fertilizer Facility has obtained the majority of its pet coke from our Coffeyville Refinery over the past five years, although has decreased to 40% in 2019. However, should our Coffeyville Refinery fail to perform in accordance with the existing agreement or to the extent pet coke from the Coffeyville Refinery is insufficient, we would need to purchase pet coke from third parties on the open market, which could negatively impact our results of operations to the extent third-party pet coke is unavailable or available only at higher prices. Currently, we purchase 100% of the pet coke our Coffeyville Refinery produces. However, we are still required to procure additional pet coke from third parties to maintain our production rates. We are currently party to pet coke supply agreements with multiple third-party refineries to provide a significant amount of pet coke at fixed prices. The terms of these agreements currently end in December 2020.
The market for natural gas has been volatile, and fluctuations in natural gas prices could affect our competitive position.
Low natural gas prices benefit our competitors that rely on natural gas as their primary feedstock and disproportionately impact our operations at our Coffeyville Fertilizer Facility by making us less competitive with natural gas-based nitrogen fertilizer manufacturers. Continued low natural gas prices could result in nitrogen fertilizer pricing drops and impair the ability of the Coffeyville Fertilizer Facility to compete with other nitrogen fertilizer producers who use natural gas as their primary feedstock, which, therefore, would have a material adverse impact on the Nitrogen Fertilizer Segment’s results of operations, financial condition and ability to make cash distributions.
The East Dubuque Fertilizer Facility uses natural gas as its primary feedstock, and as such, the profitability of operating the East Dubuque Fertilizer Facility is significantly dependent on the cost of natural gas. An increase in natural gas prices could make it less competitive with producers who do not use natural gas as their primary feedstock. In addition, an increase in natural gas prices in the United States relative to prices of natural gas paid by foreign nitrogen fertilizer producers may negatively affect our competitive position in the corn belt, and such changes could have a material adverse effect on our results of operations, financial condition and cash flows.
We expect to purchase a portion of our natural gas for use in the East Dubuque Fertilizer Facility on the spot market. As a result, we remain susceptible to fluctuations in the price of natural gas in general and in local markets in particular. We may use
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fixed supply, fixed price forward purchase contracts to lock in pricing for a portion of its natural gas requirements, but we may not be able to enter into such agreements on acceptable terms or at all. Without forward purchase contracts for the supply of natural gas, we would need to purchase natural gas on the spot market, which would impair its ability to hedge exposure to risk from fluctuations in natural gas prices. If we enter into forward purchase contracts for natural gas, and natural gas prices decrease, then its cost of sales could be higher than it would have been in the absence of the forward purchase contracts.
Any interruption in the supply of natural gas to our East Dubuque Fertilizer Facility could have a material adverse effect on our results of operations and financial condition.
Our East Dubuque Fertilizer Facility depends on the availability of natural gas. We have an agreement with Nicor Gas (“Nicor”) pursuant to which we access natural gas from the ANR Pipeline Company and Northern Natural Gas pipelines. Our access to satisfactory supplies of natural gas through Nicor could be disrupted due to a number of causes, including volume limitations under the agreement, pipeline malfunctions, service interruptions, mechanical failures or other reasons. The agreement currently extends through February 29, 2020. Upon expiration of the agreement, we may be unable to extend the service under the terms of the existing agreement or renew the agreement on satisfactory terms, or at all. Any disruption in the supply of natural gas to our East Dubuque Fertilizer Facility could restrict our ability to continue to make products at the facility. In the event we need to obtain natural gas from another source, we may need to build a new connection from that source to the East Dubuque Fertilizer Facility and negotiate related easement rights, which would be costly, disruptive and/or may be unfeasible. As a result, any interruption in the supply of natural gas through Nicor could have a material adverse effect on our results of operations and financial condition.
If licensed technology were no longer available, our business may be adversely affected.
We have licensed, and may in the future license, a combination of patent, trade secret, and other intellectual property rights of third parties for use in our plant operations. If any license agreement on which our operations rely were to be terminated, licenses to alternative technology may not be available, or may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently-licensed technology may require substantial changes to manufacturing processes or equipment and may have a material adverse effect on our results of operations, financial condition and cash flows.
Additionally, we may face claims of infringement that could interfere with our ability to use technology that is material to our plant operations. Any litigation of this type related to third-party intellectual property rights could result in substantial costs and diversions of resources, either of which could have a material adverse effect on our results of operations, financial condition and cash flows. In the event a claim of infringement against us is successful, we may be required to pay royalties or license fees for past or continued use of the infringing technology, or we may be prohibited from using the infringing technology altogether. If we are prohibited from using any technology as a result of such a claim, we may not be able to obtain licenses to alternative technology adequate to substitute for the technology we can no longer use, or licenses for such alternative technology may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently-licensed technology may require us to make substantial changes to its manufacturing processes or equipment or to our products, and could have a material adverse effect on our results of operations, financial condition and cash flows.
Our operations are dependent on third-party suppliers, which could have a material adverse effect on our results of operations, financial condition and cash flows.
Operations of our Coffeyville Fertilizer Facility depend in large part on the performance of third-party suppliers, and the operations of the Coffeyville Fertilizer Facility could be adversely affected if the operation of the third-party air separation plant located adjacent to it were disrupted. Additionally, this air separation plant has experienced numerous short-term interruptions in the past, causing interruptions in our gasifier operations. With respect to electricity, we are party to an electric services agreement with a third-party supplier through June 30, 2029.
Our East Dubuque Fertilizer Facility operations also depend in large part on the performance of third-party suppliers, including for the purchase of electricity. We entered into a utility service agreement, which terminates on June 1, 2022 and will continue year-to-year thereafter unless either party provides 12-month advance written notice of termination.
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Should any of our other third-party suppliers fail to perform in accordance with existing contractual arrangements, or should we otherwise lose the service of any third-party suppliers, our operations (or a portion thereof) could be forced to halt. Alternative sources of supply could be difficult to obtain. Any shutdown of our operations (or a portion thereof), even for a limited period, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
We rely on third-party providers of transportation services and equipment, which subjects the Nitrogen Fertilizer Segment to risks and uncertainties beyond its control that may have a material adverse effect on its results of operations, financial condition and ability to make distributions.
Our business relies on railroad and trucking companies to ship finished products to customers of the Coffeyville Fertilizer Facility. We also lease railcars from railcar owners to ship its finished products. Additionally, although customers of the East Dubuque Fertilizer Facility generally pick up products at the facility, the facility occasionally relies on barge, truck and railroad companies to ship products to customers. These transportation operations, equipment and services are subject to various hazards, including extreme weather conditions, work stoppages, delays, spills, derailments and other accidents, and other operating hazards. Further, the limited number of towing companies and barges available for ammonia transport may also impact the availability of transportation for our Nitrogen Fertilizer Segment’s products. These transportation operations, equipment and services are also subject to environmental, safety and other regulatory oversight. Due to concerns related to terrorism or accidents, local, state and federal governments could implement new regulations affecting the transportation of our finished products. In addition, new regulations could be implemented affecting the equipment used to ship its finished products.
Any delay in our ability to ship its finished products as a result of these transportation companies’ failure to operate properly, the implementation of new and more stringent regulatory requirements affecting transportation operations or equipment, or significant increases in the cost of these services or equipment could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving ammonia or other products we produce or transport that cause severe damage to property or injury to the environment and human health could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. In addition, the costs of transporting ammonia could increase significantly in the future.
Our business manufactures, processes, stores, handles, distributes and transports ammonia, which can be very volatile and extremely hazardous. Major accidents or releases involving ammonia could cause severe damage or injury to property, the environment, and human health, as well as a possible disruption of supplies and markets. Such an event could result in civil lawsuits, fines, penalties and regulatory enforcement proceedings, all of which could lead to significant liabilities. Any damage or injury to persons, equipment or property or other disruption of our ability to produce or distribute products could result in a significant decrease in operating revenues and significant additional costs to replace or repair and insure our assets, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. Our facilities periodically experience minor releases of ammonia related to leaks from our facilities’ equipment. Similar events may occur in the future.
In addition, we may incur significant losses or costs relating to the operation of railcars used for the purpose of carrying various products, including ammonia. Due to the dangerous and potentially hazardous nature of the cargo, in particular ammonia, a railcar accident may result in fires, explosions, and releases of material which could lead to sudden, severe damage or injury to property, the environment, and human health. In the event of contamination, under environmental law, we may be held responsible even if we are not at fault, and we complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidents involving ammonia and other products we produce or transport may result in us being named as a defendant in lawsuits asserting claims for substantial damages, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Risks Related to Our Capital Structure
Internally generated cash flows and other sources of liquidity may not be adequate for the capital needs of our businesses.
Our businesses 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
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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.
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 CVR Refining has sufficient liquidity under its Amended and Restated ABL Credit Facility to operate the Refineries and CVR Partners has sufficient liquidity under its AB Credit Facility to run the Nitrogen Fertilizer Segment, 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 CVR Partners’ common units, which may make it more difficult for us to raise additional capital and thereby limit its ability to grow, which could in turn cause CVR Energy’s stock and/or CVR Partners’ unit price to drop.
•Market conditions could result in significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure, or other reasons could result in decreased sales and earnings for us.
CVR Energy, CVR Refining, and CVR Partners’ level of indebtedness may increase and affect our ability to operate their respective businesses. In addition, this may have a material adverse effect on our and their financial flexibility, financial condition and results of operations.
As of December 31, 2019, we had total indebtedness outstanding of $1,195 million, including CVR Partners’ $647 million of senior notes and CVR Refining’s $500 million of senior notes. We had approximately $50 million in availability under CVR Partners’ AB Credit Facility and $393 million in availability under CVR Refining’s Amended and Restated ABL Credit Facility, which includes a $7 million reduction in availability for issued letters of credit. On January 27, 2020, CVR Energy issued $600 million and $400 million of senior notes due 2025 and 2028, respectively, and redeemed CVR Refining’s outstanding $500 million of senior notes due 2022. As of January 31, 2020, our total indebtedness was $1,691 million, including CVR Partners’ $647 million of senior notes and CVR Energy’s $1,000 million of senior notes.
We may be able to incur substantially more debt in the future, including secured indebtedness. Although existing credit facilities contain restrictions on the occurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions may not prevent incurring new obligations that do not constitute indebtedness. To the extent such new debt or new obligations are added to existing indebtedness, the risks described below could substantially increase. The level of indebtedness could have important consequences, including the following:
•limiting our ability to obtain additional financing to fund working capital needs, capital expenditures, debt service requirements, acquisitions, general corporate, or other purposes;
•requiring us to utilize a significant portion of cash flows to service indebtedness, thereby reducing our funds available for operations, future business opportunities, and distributions to us and public common unitholders of CVR Partners;
•limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt;
•limiting our ability to compete with other companies who are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions;
•limiting our ability to make certain payments on debt that is subordinated or secured on a junior basis;
•restricting us from making strategic acquisitions or investments, introducing new technologies or exploiting business opportunities;
•restricting the way in which we conduct business because of financial and operating covenants in the agreements governing existing and future indebtedness, including borrowing additional funds, disposing of assets, and in the case of certain indebtedness of subsidiaries, restricting the ability of subsidiaries to pay dividends or make distributions;
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•limiting our ability to enter into certain transactions with our affiliates;
•limiting our ability to designate our subsidiaries as unrestricted subsidiaries;
•exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in their or their respective subsidiaries’ debt instruments that could have a material adverse effect on our business, financial condition and operating results;
•increasing our vulnerability to general adverse economic and industry conditions or adverse pricing of products;
•increasing the likelihood for a reduction in the borrowing base under CVR Refining’s Amended and Restated ABL Credit Facility following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
•limiting our ability to react to changing market conditions in our industries and in respective customers’ industries.
Covenants in our debt agreements could limit our ability to incur additional indebtedness and engage in certain transaction, as well as limit the flexibility in operating the respective business, which could adversely affect our liquidity and ability to pursue our business strategies. In the case of CVR Partners, this may also limit the ability to make distributions to unitholders.
Our debt facilities and instruments contain, and any instruments governing future indebtedness would likely contain, a number of covenants that 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 the ability, among other things, to:
•incur, assume, or guarantee additional indebtedness or issue redeemable or preferred stock;
•pay dividends or distributions in respect of equity securities or make other restricted payments;
•prepay, redeem, or repurchase certain debt;
•enter into agreements that restrict distributions from restricted subsidiaries
•make certain payments on debt that is subordinated or secured on a junior basis;
•make certain investments;
•sell or otherwise dispose of assets, including capital stock of subsidiaries;
•create liens on certain assets;
•consolidate, merge, sell, or otherwise dispose of all or substantially all assets;
•enter into certain transactions with affiliates; and
•designate subsidiaries as unrestricted subsidiaries.
Any of these restrictions could limit our ability to plan for or react to market conditions and could otherwise restrict operating activities. Any failure to comply with these covenants could result in a default under existing debt facilities and instruments. Upon a default, unless waived, the lenders under such debt facilities and instruments would have all remedies available to a secured lender and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against assets, and force bankruptcy or liquidation, subject to any applicable intercreditor agreements. In addition, a default under existing debt facilities and instruments would trigger a cross default under other agreements and could trigger a cross default under the agreements governing future indebtedness. Our operating segments’ results may not be sufficient to service existing indebtedness or to fund other expenditures, and we may not be able to obtain financing to meet these requirements.
CVR Energy and the Nitrogen Fertilizer Segment may not be able to generate sufficient cash to service existing indebtedness and may be forced to take other actions to satisfy debt obligations that may not be successful.
CVR Energy’s and the Nitrogen Fertilizer Segment’s ability to satisfy existing debt obligations will depend upon, among other things:
•future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, many of which are beyond our control;
•future ability to borrow under CVR Refining’s Amended and Restated ABL Credit Facility and CVR Partners’ AB Credit Facility, the availability of which depends on, among other things, complying with the covenants in the applicable facility; and
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•future ability to obtain other financing.
We cannot offer any assurance that our businesses will generate sufficient cash flow from operations, that our Petroleum Segment will be able to draw under its Amended and Restated ABL Credit Facility or that our Nitrogen Fertilizer Segment will be able to draw under its AB Credit Facility or otherwise, or from other sources of financing, in an amount sufficient to fund respective liquidity needs. In addition, our board of directors may in the future elect to pursue other strategic options including acquisitions of other businesses or asset purchases, which would reduce cash available to service our debt obligations.
If cash flows and capital resources are insufficient to service existing indebtedness, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital, restructure or refinance existing indebtedness, or seek bankruptcy protection. These alternative measures may not be successful and may not permit the meeting of scheduled debt service and other obligations. Our ability to restructure or refinance debt will depend on the condition of the capital markets and our financial condition, including that of our operating segments, at such time. Any refinancing of existing debt could be at higher interest rates and may require compliance with more onerous covenants, which could further restrict business operations.
The borrowings under CVR Refining’s Amended and Restated ABL Credit Facility and CVR Partners’ AB Credit Facility bear interest at variable rates and other debt we or they incur could likewise be variable-rate debt. If market interest rates increase, variable-rate debt will create higher debt service requirements, which could adversely affect our cash flow and/or distributions to us. Although we may enter into agreements limiting exposure to higher interest rates, any such agreements may not offer complete protection from this risk.
We are authorized to issue up to a total of 350 million shares of our common stock and 50 million shares of preferred stock, potentially diluting equity ownership of current holders and the share price of our common stock.
We maintain a sufficient number of available authorized shares of our common stock and preferred stock to provide us with the flexibility to issue common stock or preferred stock for business purposes that may arise as deemed advisable by our board of directors, including (i) future stock dividends or stock splits, which may increase the liquidity of our shares; (ii) the sale of stock to obtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt, if needed; (iii) for use in additional stock incentive programs; and (iv) for other bona fide purposes. Our board of directors may authorize us to issue the available authorized shares of common stock or preferred stock without notice to, or further action by, our stockholders, unless stockholder approval is required by law or the rules of the NYSE. The issuance of additional shares of common stock or preferred stock may significantly dilute the equity ownership of the current holders of our common stock.
Our ability to pay dividends on our common stock is subject to market conditions and numerous other factors.
In January 2013, our board of directors adopted a quarterly dividend policy. We began paying regular quarterly dividends in the second quarter of 2013. Dividends are subject to change at the discretion of the board of directors and may change from quarter to quarter. Our ability to continue paying dividends is subject to our ability to continue to generate sufficient cash flow from our operating segments, and the amount of dividends we are able to pay each year may vary, possibly substantially, based on market conditions, crack spreads, our capital expenditure and other business needs, covenants contained in any debt agreements we may enter into in the future, covenants contained in existing debt agreements, and the amount of distributions we receive from CVR Partners. We may not be able to continue paying dividends at the rate we currently pay dividends or at all. If the amount of our dividends decreases, the trading price of our common stock could be materially adversely affected as a result.
Risks Related to Our Corporate Structure
We are a holding company and depend upon our subsidiaries for our cash flow.
We are a holding company, and our subsidiaries conduct substantially 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 dividends or make other 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. The ability of CVR Partners to make any payments to us will depend on, among other things, their earnings, the terms of existing indebtedness (including the terms of any debt facilities and instruments), tax considerations, and legal restrictions.
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Mr. Carl C. Icahn exerts significant influence over the Company, and his interests may conflict with the interests of the Company’s other stockholders.
Mr. Carl C. Icahn indirectly controls approximately 71% of the voting power of our common stock and, by virtue of such stock ownership, is able to control or exert substantial influence over the Company, including:
•the election and appointment of directors;
•business strategy and policies;
•mergers or other business combinations;
•acquisition or disposition of assets;
•future issuances of common stock, common units, or other securities;
•occurrence of debt or obtaining other sources of financing; and
•the payment of dividends on the Company’s common stock and distributions on the common units of CVR Partners.
The existence of a controlling stockholder may have the effect of making it difficult for, or may discourage or delay, a third-party from seeking to acquire a majority of the Company’s outstanding common stock, which may adversely affect the market price of the Company’s common stock.
Mr. Icahn’s interests may not always be consistent with the Company’s interests or with the interests of the Company’s other stockholders. 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 Company and Mr. Icahn and his affiliates, those conflicts may be resolved in a manner adverse to the Company or its other stockholders.
In addition, if Mr. Icahn were to sell, or otherwise transfer, some or all of his interests in us to an unrelated party or group, a change of control could be deemed to have occurred under the terms of the indenture governing CVR Energy’s 5.250% and 5.750% Senior Notes, which would require it to offer to repurchase all outstanding notes at 101% of their principal amount plus accrued interest to the date of repurchase, and an event of default could be deemed to have occurred under CVR Refining’s Amended and Restated ABL Credit Facility, which would allow lenders to accelerate indebtedness owed to them. However, it is possible that we will not have sufficient funds at the time of the change of control to make the required repurchase of notes or repay amounts outstanding under CVR Refining’s Amended and Restated ABL Credit Facility, if any.
Our stock price may decline due to sales of shares by Mr. Carl C. Icahn.
Sales of substantial amounts of the Company’s common stock, or the perception that these sales may occur, may adversely affect the price of the Company’s common stock and impede its ability to raise capital through the issuance of equity securities in the future. Mr. Icahn could elect in the future to request that the Company file a registration statement to him to sell shares of the Company’s common stock. If Mr. Icahn were to sell a large number of shares into the public markets, Mr. Icahn could cause the price of the Company’s common stock to decline.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for, and are relying on, exemptions from certain corporate governance requirements.
A company of which more than 50% of the voting power is held by an individual, a group, or another company is a “controlled company” within the meaning of the NYSE rules and may elect not to comply with certain corporate governance requirements of the NYSE, including:
•the requirement that a majority of our board of directors consist of independent directors;
•the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors; and
•the requirement that we have a compensation committee that is composed entirely of independent directors.
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We are relying on all of these exemptions as a controlled company. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. In addition, CVR Partners is relying on exemptions from the same NYSE corporate governance requirements described above.
We have various mechanisms in place to discourage takeover attempts, which may reduce or eliminate our stockholders’ ability to sell their shares for a premium in a change of control transaction.
Various provisions of our amended certificate of incorporation and second amended and restated bylaws and of Delaware corporate law may discourage, delay, or prevent a change in control or takeover attempt of our Company by a third-party that our management and board of directors determines is not in the best interest of our Company and its stockholders. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions include:
•preferred stock that could be issued by our board of directors to make it more difficult for a third-party to acquire, or to discourage a third-party from acquiring, a majority of our outstanding voting stock;
•limitations on the ability of stockholders to call special meetings of stockholders;
•limitations on the ability of stockholders to act by written consent in lieu of a stockholders’ meeting; and
•advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted upon by our stockholders at stockholder meetings.
Compliance with and changes in the tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including United States and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise, and withholding taxes. New tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future.
Risks Related to Our Ownership in CVR Partners
If CVR Partners were to be treated as a corporation for U.S. federal income tax purposes or if it becomes subject to entity-level taxation for state tax purposes, its cash available for distribution to its common unitholders, including to us, would be substantially reduced, likely causing a substantial reduction in the value of its common units, including the common units held by us.
The anticipated after-tax economic benefit of an investment in common units of CVR Partners depends largely on it being treated as a partnership for U.S. federal income tax purposes. Despite the fact that CVR Partners is organized as a limited partnership under Delaware law, it would be treated as a corporation for U.S. federal income tax purposes unless it satisfies a “qualifying income” requirement. CVR Partners may not find it possible to meet this qualifying income requirement, may inadvertently fail to meet this qualifying income requirement, or a change in current law could cause CVR Partners to be treated as a corporation for U.S. federal income tax purposes or otherwise subject CVR Partners to entity-level taxation.
If CVR Partners were to be treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on all of its taxable income at the corporate tax rate. Distributions to its common unitholders (including us) would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to such common unitholders. Because a tax would be imposed upon CVR Partners as a corporation, its cash available for distribution to its common unitholders would be substantially reduced. Therefore, treatment of CVR Partners as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to its common unitholders (including us), likely causing a substantial reduction in the value of such common units.
We may have liability to repay distributions that are wrongfully distributed to us.
Under certain circumstances, we may, as a holder of common units in CVR Partners, have to repay amounts wrongfully returned or distributed to us. Under the Delaware Revised Uniform Limited Partnership Act, a partnership may not make distributions to its unitholders if the distribution would cause its liabilities to exceed the fair value of its assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the
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distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the company for the distribution amount.
Public investors own approximately 66% of the Nitrogen Fertilizer Segment through CVR Partners. Although we own the general partner of CVR Partners, the general partner owes a duty of good faith to public unitholders, which could cause them to manage their respective businesses differently than if there were no public unitholders.
Public investors own approximately 66% of CVR Partners’ common units. We are not entitled to receive all of the cash generated by CVR Partners or freely transfer money to finance operations at the Petroleum Segment. Furthermore, although we own the general partner of CVR Partners, the general partner is subject to certain fiduciary duties, which may require the general partner to manage its business in a way that may differ from our best interests.
CVR Partners is managed by the executive officers of its general partner, some of whom are employed by and serve as part of the senior management team of the Company. Conflicts of interest could arise as a result of this arrangement.
CVR Partners is managed by the executive officers of its general partner, some of whom are employed by and serve as part of the senior management team of the Company. Furthermore, although CVR Partners has entered into services agreements with the Company under which it compensates the Company for the services of its management, our management is not required to devote any specific amount of time to the Nitrogen Fertilizer Segment and may devote a substantial majority of their time to other business of the Company. Moreover, the Company may terminate the services agreement with CVR Partners at any time, in each case subject to a 180-day notice period. In addition, key executive officers of the Company, including its president and chief executive officer, chief financial officer, and general counsel, will face conflicts of interest if decisions arise in which CVR Partners and the Company have conflicting points of view or interests.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Refer to Item 1, “Petroleum” and “Nitrogen Fertilizer” for more information on our core business properties. We also lease property for our executive office which is located in Sugar Land, Texas.
Item 3. Legal Proceedings
In the ordinary course of business, we may become party to lawsuits, administrative proceedings, and governmental investigations, including environmental, regulatory, and other matters. Large, and sometimes unspecified, damages or penalties may be sought from us in some matters and certain matters may require years to resolve. Although we cannot provide assurance, we believe that an adverse resolution of the matters described below would not have a material impact on our liquidity, consolidated financial position, or consolidated results of operations.
Unresolved Matters
The U.S. Attorney’s office for the Southern District of New York contacted CVR Energy in September 2017 seeking production of information pertaining to CVR Refining’s, CVR Energy’s and Mr. Carl C. Icahn’s activities relating to the RFS and Mr. Icahn’s former role as an advisor to the President. CVR Energy cooperated with the request and provided information in response to the subpoena. The U.S. Attorney’s office has not made any claims or allegations against CVR Energy or Mr. Icahn. CVR Energy believes it maintains a strong compliance program and, while no assurances can be made, CVR Energy does not believe this inquiry will have a material impact on its business, financial condition, results of operations or cash flows.
On August 21, 2018, CRRM received a letter from the United States Department of Justice (“DOJ”) on behalf of the EPA and KDHE alleging violations of the CAA and a 2012 Consent Decree between CRRM, the United States (on behalf of EPA) and KDHE at CRRM’s Coffeyville refinery. In September 2018, CRRM executed a tolling agreement with the DOJ and KDHE extending time for negotiation regarding the agencies’ allegations through April 30, 2020. At this time the Company cannot reasonably estimate the potential penalties, costs, fines or other expenditures that may result from this matter or any subsequent
December 31, 2019 | 37
enforcement or litigation relating thereto and, therefore, the Company cannot determine if the ultimate outcome of this matter will have a material impact on the Company’s financial position, results of operations or cash flows.
During 2019, the Company, CVR Refining and its general partner, CVR Refining Holdings, IEP, and certain directors and affiliates have been named in at least one of nine lawsuits filed in the Court of Chancery of the State of Delaware by purported former unitholders of CVR Refining, on behalf of themselves and an alleged class of similarly situated unitholders (the “Call Option Lawsuits”). The Call Option Lawsuits primarily allege breach of contract, tortious interference and breach of the implied covenant of good faith and fair dealing and seek monetary damages and attorneys’ fees, among other remedies, relating to the Company’s exercise of the call option under the CVR Refining Amended and Restated Agreement of Limited Partnership assigned to it by CVR Refining’s general partner. In January 2020, the court dismissed CVR Holdings and certain former directors of CVR Refining’s general partner from the Call Option Lawsuits, though permitted some or all of the claims to proceed against each remaining defendant. The Company believes the Call Option Lawsuits are without merit and intends to vigorously defend against them. The Call Option Lawsuits remain in the early stages of litigation. Accordingly the Company cannot determine at this time the outcome of the Call Option Lawsuits, including whether the outcome of this matter would have a material impact on the Company’s financial position, results of operations, or cash flows.
During 2019, WRC intervened in a lawsuit filed by four ethanol and biofuels trade associations against the EPA, claiming the EPA exceeded its authority in granting Wynnewood’s 2017 small refinery exemption (“SRE”) under the RFS program under the CAA, as well as the SREs of two other unrelated refineries. In January 2020, the 10th Circuit Court of Appeals vacated the three SREs and remanded the matter to the EPA for further proceedings, holding, in part, that the “extension” language in the CAA requires a small refinery to have received an SRE continuously in every year since inception of the program to be eligible. As the EPA has not yet acted following remand by the court, and as Wynnewood intends to appeal this ruling, we cannot currently estimate the outcome, impact, or timing of the resolution of this matter.
Resolved Matters
In September 2018, the Kansas Court of Appeals upheld property tax determinations by the Kansas Board of Tax Appeals in connection with Coffeyville Resources Nitrogen Fertilizer, LLC’s (“CRNF”) dispute with Montgomery County, Kansas (the “County”) over prior year property tax payments as previously disclosed. On October 29, 2018, the County petitioned the Kansas Supreme Court to review the Court of Appeals’ determination. Subsequent briefs were filed by CRNF and the County. In April 2019, CRNF and the County executed an agreement which the County agrees to withdraw its petition to the Kansas Supreme Court and CRNF is expected to recover approximately $8 million through favorable property tax assessments from 2019 through 2028, subject to the terms of the settlement agreement.
Item 4. Mine Safety Disclosures
Not applicable.
December 31, 2019 | 38
PART II
Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Performance Graph
The performance graph below compares the cumulative total return of our common stock to (a) the cumulative total return of the S&P 500 Composite Index and (b) a composite peer group (“Peer Group”) consisting of Delek US Holdings, Inc., HollyFrontier Corporation, Marathon Petroleum Corp., PBF Energy and Valero Energy Corporation. The graph assumes that the value of the investment in common stock and each index was $100 on December 31, 2014 and that all dividends were reinvested. Investment is weighted on the basis of market capitalization.
The share price performance shown on the graph is not necessarily indicative of future price performance. Information used in the graph was obtained from Yahoo! Finance (finance.yahoo.com). The performance graph above is furnished and not filed for purposes of the Securities Act and the Exchange Act. The performance graph is not soliciting material subject to Regulation 14A.
Market Information
Our common stock is listed under the symbol “CVI” on the New York Stock Exchange.
CVR Energy, Inc. - Exchange Offer
In August 2018, CVR Energy completed an exchange offer whereby public unitholders tendered a total of 21,625,106 CVR Refining common units in exchange for a total of 13,699,549 shares of CVR Energy common stock. Following the exchange offer, Icahn Enterprises L.P. and its affiliates (“IEP”) owned approximately 71% of the Company’s outstanding shares. Refer to Note 1 (“Organization and Nature of Business”) in Item 8 for further information.
Purchases of Equity Securities by the Issuer
On October 23, 2019, the Board of Directors of the Company authorized a stock repurchase program (the “Stock Repurchase Program”). The Stock Repurchase Program would enable the Company to repurchase up to $300 million of the Company’s common stock. Repurchases under the Stock Repurchase Program may be made from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise in accordance with applicable securities laws.
December 31, 2019 | 39
The timing, price and amount of repurchases (if any) will be made at the discretion of management and are subject to market conditions as well as corporate, regulatory and other considerations. While the Stock Repurchase Program currently has a duration of four years, it does not obligate the Company to acquire any stock and may be terminated by the Company’s Board of Directors at any time.
We did not repurchase any of our common stock during the year ended December 31, 2019.
Item 6. Selected Financial Data
The following table sets forth certain selected consolidated financial data as of and for each year in the five-year period ended December 31, 2019. The selected consolidated financial information presented below has been derived from our historical consolidated financial statements. The following table should be read in conjunction with Item 7 and our consolidated financial statements and related notes thereto in Item 8.
| Year Ended December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||||||||||
| Statements of Operations | |||||||||||||||||||||||||||||
| Net sales | $ | 6,364 | $ | 7,124 | $ | 5,988 | $ | 4,782 | $ | 5,433 | |||||||||||||||||||
| Net income attributable to CVR Energy stockholders | 380 | 259 | 263 | 25 | 197 | ||||||||||||||||||||||||
| Basic and diluted earnings per share | $ | 3.78 | $ | 2.80 | $ | 3.03 | $ | 0.29 | $ | 2.27 | |||||||||||||||||||
| Dividends declared per share | $ | 3.05 | $ | 2.50 | $ | 2.00 | $ | 2.00 | $ | 2.00 | |||||||||||||||||||
| December 31, | |||||||||||||||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||||||||||
| Balance Sheet | |||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 652 | $ | 668 | $ | 482 | $ | 736 | $ | 765 | |||||||||||||||||||
| Total assets | 3,905 | 4,000 | 3,953 | 4,159 | 3,413 | ||||||||||||||||||||||||
| Long-term debt and finance lease obligations, net of current portion | 1,190 | 1,167 | 1,164 | 1,165 | 667 | ||||||||||||||||||||||||
| Total liabilities | 2,237 | 2,057 | 2,130 | 2,371 | 1,736 | ||||||||||||||||||||||||
| Total CVR stockholders’ equity | 1,393 | 1,286 | 988 | 899 | 1,025 | ||||||||||||||||||||||||
| Total equity | 1,668 | 1,943 | 1,823 | 1,788 | 1,677 | ||||||||||||||||||||||||
December 31, 2019 | 40
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Report. References to CVR Energy, the Company, “we,” “us,” and “our” may refer to consolidated subsidiaries of CVR Energy, including CVR Refining or CVR Partners, as the context may require.
This discussion and analysis generally discusses the years ended December 31, 2019 and 2018 and year-to-year comparisons between such periods. The discussions of the year ended December 31, 2017 and year-to-year comparisons between the years ended December 31, 2018 and 2017 that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of Exhibit 99.1 to the Company’s Current Report on Form 8-K filed on June 12, 2019, and such discussion are incorporated by reference into this Report.
Strategy and Goals
Mission and Core Values
Our mission is to be a top tier North American petroleum refining and nitrogen-based fertilizer company as measured by safe and reliable operations, superior performance and profitable growth. The foundation of how we operate is built on five core values:
•Safety - We always put safety first. The protection of our employees, contractors and communities is paramount. We have an unwavering commitment to safety above all else. If it’s not safe, then we don’t do it.
•Environment - We care for our environment. Complying with all regulations and minimizing any environmental impact from our operations is essential. We understand our obligation to the environment and that it’s our duty to protect it.
•Integrity - We require high business ethics. We comply with the law and practice sound corporate governance. We only conduct business one way—the right way with integrity.
•Corporate Citizenship - We are proud members of the communities where we operate. We are good neighbors and know that it’s a privilege we can’t take for granted. We seek to make a positive economic and social impact through our financial donations and the contributions of time, knowledge and talent of our employees to the places where we live and work.
•Continuous Improvement - We believe in both individual and team success. We foster accountability under a performance-driven culture that supports creative thinking, teamwork and personal development so that employees can realize their maximum potential. We use defined work practices for consistency, efficiency and to create value across the organization.
Our core values are driven by our people, inform the way we do business each and every day and enhance our ability to accomplish our mission and related strategic objectives.
Strategic Objectives
We have outlined the following strategic objectives to drive the accomplishment of our mission:
Safety - We aim to achieve continuous improvement in all environmental, health and safety areas through ensuring our people’s commitment to environmental, health and safety comes first, the refinement of existing policies, continuous training, and enhanced monitoring procedures.
Reliability - Our goal is to achieve industry-leading utilization factors at our facilities through safe and reliable operations. We are focusing on improvements in day-to-day plant operations, identifying alternative sources for plant inputs to reduce lost
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time due to third-party operational constraints, and optimizing our commercial and marketing functions to maintain plant operations at their highest level.
Market Capture - We continuously evaluate opportunities to improve the facilities’ netbacks and reduce variable costs incurred in production to maximize our capture of market opportunities.
Financial Discipline - We strive to be as efficient as possible by maintaining low operating costs and a disciplined deployment of capital.
Achievements
We successfully executed a number of achievements in support of our strategic objectives shown below through the date of this filing:
| Safety | Reliability | Market Capture | Financial Discipline | ||||||||||||||||||||
| Corporate: | |||||||||||||||||||||||
| Achieved year over year environment, health, and safety improvements related to total recordable incident rate, environmental events, and project safety management of 11%, 14%, and 50%, respectively. | ü | ||||||||||||||||||||||
Declared cash dividends of $3.05 per share in 2019. | ü | ||||||||||||||||||||||
Announced $300 million share repurchase authorization. | ü | ||||||||||||||||||||||
| Issued $1.0 billion in Senior Notes due 2025 and 2028 and the associated funding of the redemption of the CVR Refining Senior Notes due 2022 in January 2020. | ü | ||||||||||||||||||||||
| Petroleum Segment: | |||||||||||||||||||||||
| Completed the Wynnewood turnaround safely, on time and under budget. | ü | ü | ü | ||||||||||||||||||||
| Increased throughput of regional crudes and condensate by 37% and 58%, respectively, while reducing reliance on WTI Cushing common crude oil by 35% for the fourth quarter 2019 as compared to the fourth quarter 2018. | ü | ü | |||||||||||||||||||||
| Completed the Wynnewood refinery’s BenFree repositioning project enabling increased premium gasoline production. | ü | ü | ü | ü | |||||||||||||||||||
| Completed the sale of the Cushing, Oklahoma crude oil terminal. | ü | ||||||||||||||||||||||
Maintained high utilization at both facilities through the fourth quarter of 2019. | ü | ü | ü | ||||||||||||||||||||
| Received Board approval for the Isomerization project at the Wynnewood Refinery, intended to improve liquid yields. | ü | ü | ü | ||||||||||||||||||||
| Nitrogen Fertilizer: | |||||||||||||||||||||||
| Safely completed the East Dubuque turnaround. | ü | ü | |||||||||||||||||||||
Maintained high asset reliability and utilization at both facilities through the fourth quarter of 2019 (adjusted for turnaround at East Dubuque). | ü | ü | ü | ||||||||||||||||||||
Paid cash distributions of 40 cents per unit in 2019. | ü | ||||||||||||||||||||||
December 31, 2019 | 42
Industry Factors and Market Conditions
Petroleum Segment
The earnings and cash flows of the Petroleum Segment are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond the Petroleum Segment’s 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 the Petroleum Segment applies first-in first-out accounting to value its inventory, crude oil price movements may impact net income in the short term because of changes in the value of its unhedged inventory. The effect of changes in crude oil prices on the Petroleum Segment results of operations is partially influenced by the rate at which the process 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, system inventory 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 competitors’ facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for volatile seasonal exports of diesel from the United States Gulf Coast markets.
In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations and increased mileage standards for vehicles. The petroleum business is also subject to the renewable fuel standards (“RFS”) of the EPA, which requires blending “renewable fuels” with transportation fuels or purchase renewable identification numbers (“RINs”), in lieu of blending, by March 31, 2019 or otherwise be subject to penalties. Our cost to comply with RFS is dependent upon a variety of factors, which include the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our products, as well as the fuel blending performed at our refineries and downstream terminals, all of which can vary significantly from period to period. Based upon recent market prices of RINs and current estimates related to the other variable factors, our estimated cost to comply with RFS is $100 to $110 million for 2020.
2019 Market Conditions
NYMEX WTI crude oil is an industry wide benchmark that is utilized in the market pricing of a barrel of crude oil. Other crude oils that are compared to WTI, known as differentials, show how the market for other crude oils such as WCS, White Cliffs (“Condensate”), Brent Crude (“Brent”), and Midland WTI (“Midland”) are trending. During 2019, there were price fluctuations within these differentials due to the continued curtailments imposed by the Alberta government, therefore, tightening the WCS to WTI differential. Additionally, there have been start-up and line fill of new pipelines from West Texas to the Gulf Coast further tightening the domestic differentials against WTI.
As a performance benchmark and a comparison with other industry participants, we utilize the NYMEX and the Mid-Continent crack spreads. These crack spreads are a measure of the difference between market prices for crude oil and refined products and is a commonly used proxy within the industry to estimate or identify trends in refining margins. Crack spreads can fluctuate significantly over time as a result of market conditions and supply and demand balances. The NYMEX 2-1-1 crack spread is calculated using two barrels of WTI producing one barrel of NYMEX RBOB Gasoline (“RBOB”) and one barrel of NYMEX NY Harbor ULSD (“HO”). The Mid-Continent 2-1-1 crack spread is calculated using two barrels of WTI crude oil producing one barrel of Group 3 gasoline and one barrel of Group 3 diesel.
NYMEX 2-1-1 crack spreads increased during 2019 compared to 2018 while the Mid-Continent 2-1-1 crack spreads showed a reduction. The NYMEX 2-1-1 crack spread averaged $19.93 per barrel in 2019 compared to $19.42 per barrel in 2018. The Mid-Continent 2-1-1 crack spread averaged $18.22 per barrel in 2019 compared to $18.63 per barrel in 2018.
December 31, 2019 | 43
The tables below are presented, on a per barrel basis, for the years ended December 31, 2019, 2018, and 2017:
(1)For December 2019, the average differentials for Midland and Condensate were $0.97 and $(0.15), respectively.
December 31, 2019 | 44
(2)The change over time in NYMEX - WTI, as reflected in the charts above, is illustrated below.
| (in $/bbl) | Average 2017 | Average December 2017 | Average 2018 | Average December 2018 | Average 2019 | Average December 2019 | |||||||||||||||||||||||||||||
| WTI | $ | 50.95 | $ | 57.95 | $ | 64.77 | $ | 48.98 | $ | 57.03 | $ | 61.06 | |||||||||||||||||||||||
(3)Information used within these charts was obtained from MarketView.
Nitrogen Fertilizer Segment
Within the Nitrogen Fertilizer Segment, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, utilization rates, and operating costs and expenses, including pet coke and natural gas feedstock costs.
The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets.
Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors’ facilities, new facility development, political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer 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 industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.
2019 Market Conditions
While there is risk of short-term volatility given the inherent nature of the commodity cycle, the Company believes the long-term fundamentals for the U.S. nitrogen fertilizer industry remain intact. The Nitrogen Fertilizer Segment views the anticipated combination of (i) increasing global population, (ii) decreasing arable land per capita, (iii) continued evolution to more protein-based diets in developing countries, (iv) sustained use of corn as feedstock for the domestic production of ethanol and (v) positioning at the lower end of the global cost curve should continue to provide a solid foundation for nitrogen fertilizer producers in the U.S. over the longer term.
During 2019, weather significantly impacted the demand for UAN and ammonia due to lack of extended dry conditions required for planting, caused by excessive rain delaying planting of corn and soybean crops. However, as a result of this delay, there was additional demand for UAN and ammonia due to the catch up from the late start to 2019 application season, but the fall season also had excessive moisture, which limited the ability to apply nitrogen. Consistent with the past 18 months,
December 31, 2019 | 45
customers have been purchasing fertilizers more ratably and the expectations that harvest will be later than normal has led customers to stage their buying. Weather (i.e., heavy rains, flooding, etc.) is going to dictate the timing of harvest and the available window for ammonia application.
Corn and soybean are two major crops planted by farmers in the U.S. Corn crop has shown to deplete the amount of nitrogen and ammonia within the soil it is grown in, which in turn, results in a need for these nutrients to be replenished after each growing cycle. Unlike corn, soybean is able to obtain its own nitrogen through a process known as “N fixation”. As such, upon harvesting of soybean, the soil retains a certain amount of nitrogen which results in lower demand for nitrogen for the pursuing corn planting cycle. Due to these factors, nitrogen fertilizer consumers generally follow a balanced corn-soybean rotational planting cycle as evident through the chart presented below for 2018 and 2017. Due to the significant weather conditions discussed above, the 2019 planting cycle relied more heavily on corn planting to obtain sufficient crop harvests, which slightly adjusted this balance.
The relationship between the total acres planted for both corn and soybean has a direct impact on the overall demand for UAN and ammonia products. As the number of “corn” acres increases, the market and demand for UAN and ammonia also increases. Correspondingly, as the number of “soybean” acres increases the market and demand for UAN and ammonia decreases.
The table below shows relevant market indicators for the Nitrogen Fertilizer Segment by month through December 31, 2019:
(1)Information used within this chart was obtained from the United States Department of Agriculture, National Agricultural Statistics Service.
December 31, 2019 | 46
(2)Information used within these charts was obtained from various third-party sources including Green Markets (a Bloomberg Company), Pace Petroleum Coke Quarterly, and the U.S. Energy Information Administration (“EIA”), amongst others.
Results of Operations
Consolidated
The following sections should be read in conjunction with the information outlined within the previous sections of this Part II, Item 7, and the consolidated financial statements and related notes thereto in Part II, Item 8 of this Report. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of the Petroleum and Nitrogen Fertilizer Segments.
Consolidated Financial Highlights
(1)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.
Overview - The Petroleum Segment’s operating income and net income were $574 million and $559 million, respectively, for the year ended December 31, 2019. The increases of $30 million and $48 million, respectively, are driven primarily by higher refining margins when compared to the year ended December 31, 2018. Refining margin was $1,203 million, or $15.26 per throughput barrel, for the year ended December 31, 2019, as compared to $1,178 million, or $15.18 per throughput barrel for the year ended December 31, 2018. The increase in refining margin of $25 million is primarily due to increased throughput volumes and lower RINs expense due to a reduction in market prices. Further, there was a gain on the sale of the Cushing, Oklahoma crude oil terminal of $9 million (occurred in the second quarter of 2019), positively impacting the Petroleum Segment. For the year ended December 31, 2019, the Nitrogen Fertilizer Segment net sales increased by $53 million to $404
December 31, 2019 | 47
million as a result of favorable pricing and higher volumes. The increase in volumes was primarily attributable to a shift in demand from the fourth quarter 2018 to the second quarter of 2019 due to inclement weather.
Income Tax Expense - Income tax expense for the year ended December 31, 2019 was $129 million, or 26.2% of income before income taxes, as compared to income tax expense for the year ended December 31, 2018 of $79 million, or 17.8% of income before income taxes. The fluctuation in income tax expense was due primarily to the decrease in non-controlling interest from the year ended December 31, 2018 to the year ended December 31, 2019. The decrease in non-controlling interest is due to the Company’s January 29, 2019 purchase of all issued and outstanding CVR Refining common units not already owned by the Company. Refer to Note 1 (“Organization and Nature of Business”) for a further discussion of this transaction. The effective income tax rate varies from the federal statutory income tax rate primarily as a result of the decrease in non-controlling interest and the benefits of state income tax credits.
Segment Financial Highlights and Results of Operations
Petroleum Segment
The Petroleum Segment utilizes certain inputs within its refining operations. These inputs include crude oil, butanes, natural gasoline, ethanol, and bio-diesel (these are also known as “throughputs”).
Refining Throughput and Production Data by Refinery
| Throughput Data | Year Ended December 31, | ||||||||||||||||
| (in bpd) | 2019 | 2018 | 2017 | ||||||||||||||
| Coffeyville | |||||||||||||||||
| Regional crude | 49,093 | 31,350 | 34,805 | ||||||||||||||
| WTI | 67,382 | 66,952 | 84,460 | ||||||||||||||
| WTL | 473 | — | — | ||||||||||||||
| Midland WTI | 3,888 | 15,893 | — | ||||||||||||||
| Condensate | 4,331 | 4,992 | 2,169 | ||||||||||||||
| Heavy Canadian | 4,711 | 5,302 | 10,135 | ||||||||||||||
| Other feedstocks and blendstocks | 9,160 | 8,369 | 9,921 | ||||||||||||||
| Wynnewood | |||||||||||||||||
| Regional crude | 53,848 | 54,746 | 27,750 | ||||||||||||||
| WTI | 3 | 2,354 | 15,251 | ||||||||||||||
| WTL | 668 | — | — | ||||||||||||||
| Midland WTI | 10,995 | 10,332 | 29,045 | ||||||||||||||
| Condensate | 7,666 | 7,237 | 1,134 | ||||||||||||||
| Other feedstocks and blendstocks | 3,753 | 5,068 | 3,511 | ||||||||||||||
| Total throughput | 215,971 | 212,595 | 218,181 | ||||||||||||||
December 31, 2019 | 48
| Production Data | Year Ended December 31, | ||||||||||||||||
| (in bpd) | 2019 | 2018 | 2017 | ||||||||||||||
| Coffeyville | |||||||||||||||||
| Gasoline | 71,817 | 67,091 | 72,778 | ||||||||||||||
| Distillate | 57,549 | 56,307 | 59,593 | ||||||||||||||
| Other liquid products | 5,810 | 5,737 | 4,704 | ||||||||||||||
| Solids | 4,573 | 5,190 | 6,631 | ||||||||||||||
| Wynnewood | |||||||||||||||||
| Gasoline | 38,864 | 40,291 | 38,311 | ||||||||||||||
| Distillate | 32,380 | 33,442 | 30,816 | ||||||||||||||
| Other liquid products | 3,223 | 4,025 | 5,429 | ||||||||||||||
| Solids | 30 | 41 | 54 | ||||||||||||||
| Total production | 214,246 | 212,124 | 218,316 | ||||||||||||||
| Liquid volume yield | 97.1 | % | 97.3 | % | 96.9 | % | |||||||||||
Financial Highlights
Overview - Petroleum Segment operating income and net income for the year ended December 31, 2019 was $574 million and $559 million, a $30 million and $48 million increase respectively over the year ended December 31, 2018, driven primarily by higher refining margins and increased throughput volumes.
December 31, 2019 | 49
(1)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.
Net sales for the Petroleum Segment decreased by $812 million for the year ended December 31, 2019, when compared to the year ended December 31, 2018, primarily due to lower gasoline and distillate prices. However, the Petroleum Segment's EBITDA improved by $40 million from 2018 mainly due to decreased raw materials costs and favorable inventory impact.
(2)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.
Refining Margin - Refining margin was $1,203 million, or $15.26 per throughput barrel, for the year ended December 31, 2019, as compared to $1,178 million, or $15.18 per throughput barrel, for the year ended December 31, 2018, primarily due to increased throughput volumes and lower RINs expense resulting from a reduction in market prices, partially offset by decreased gains on derivatives in the current period. Total throughput averaged 215,971 bpd for the year ended December 31, 2019 as compared to 212,595 bpd for the same period in 2018. Derivative gains decreased by $127 million during 2019 compared to 2018.
December 31, 2019 | 50
(1)Exclusive of depreciation and amortization expense.
Direct Operating Expenses (Exclusive of Depreciation and Amortization) - Direct operating expenses on a total throughput barrel basis decreased to $4.56 per barrel from $4.62 per barrel largely due to the increased throughput volumes. Direct operating expenses (exclusive of depreciation and amortization) were $359 million for the year ended December 31, 2019 compared to $356 million for the year ended December 31, 2018. The increase of approximately $3 million was primarily due to increased personnel costs, partially offset by lower natural gas prices.
Depreciation and Amortization Expense - Depreciation and amortization expense increased approximately $6 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, as a result of net additions during the current year. Capitalization of turnaround expense along with adoption of ASC 842 also contributed to this increase.
Selling, General, and Administrative Expenses, and Other - Selling, general and administrative expenses and other was $68 million for the year ended December 31, 2019 compared to $82 million for the year ended December 31, 2018. The $14 million decrease was primarily a result of a $9 million gain on the sale of the Cushing, Oklahoma crude oil terminal in the second quarter of 2019 and a decrease in project write-offs in 2019 compared to 2018.
Nitrogen Fertilizer Segment
The following tables summarize the ammonia utilization at the Coffeyville and East Dubuque facilities. Utilization is an important measure used by management to assess operational output at each of the Nitrogen Fertilizer Segment’s facilities. Utilization is calculated as actual tons produced divided by capacity adjusted for planned maintenance and turnarounds.
December 31, 2019 | 51
The presentation of our utilization is on a two-year rolling average which takes into account the impact of our planned and unplanned outages on any specific period. We believe the two-year rolling average is a more useful presentation of the long-term utilization performance of the Nitrogen Fertilizer Segment’s facilities.
Utilization is presented solely on ammonia production, rather than each nitrogen product, as it provides a comparative baseline against industry peers and eliminates the disparity of facility configurations for upgrade of ammonia into other nitrogen products. With efforts primarily focused on ammonia upgrade capabilities, we believe this measure provides a meaningful view of how well we operate.
On a consolidated basis, the Nitrogen Fertilizer Segment’s utilization decreased 2% to 93% for the two years ended December 31, 2019 compared to the two years ended December 31, 2018. This decrease was primarily a result of ammonia storage capacity constraints at the East Dubuque Facility in the first quarter of 2019 due to inclement weather impacting customers’ ability to apply ammonia and the turnaround at the East Dubuque Facility in the fourth quarter of 2019.
Sales and Pricing per Ton - Two of the Nitrogen Fertilizer Segment’s key operating metrics are total sales for ammonia and UAN along with the product pricing per ton realized at the gate. Product pricing at gate represents net sales less freight revenue divided by product sales volume in tons and is shown in order to provide a pricing measure comparable across the fertilizer industry.
Production Volumes - Gross tons produced for ammonia represent the total ammonia produced, including ammonia produced, that was upgraded into other fertilizer products. Net tons available for sale represent the ammonia available for sale that was not upgraded into other fertilizer products. The table below presents these Nitrogen Fertilizer Segment metrics for the years ended December 31, 2019, 2018 and 2017:
December 31, 2019 | 52
| Year Ended December 31, | |||||||||||||||||
| (in thousands of tons) | 2019 | 2018 | 2017 | ||||||||||||||
| Ammonia (gross produced) | 766 | 794 | 815 | ||||||||||||||
| Ammonia (net available for sale) | 223 | 246 | 268 | ||||||||||||||
| UAN | 1,255 | 1,276 | 1,268 | ||||||||||||||
Feedstock - Our Coffeyville Facility utilizes a pet coke gasification process to produce nitrogen fertilizer. Our East Dubuque Facility uses natural gas in its production of ammonia. The table below presents these feedstocks for both facilities within the Nitrogen Fertilizer Segment for the years ended December 31, 2019, 2018, and 2017:
| Year Ended December 31, | |||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||
| Petroleum coke used in production (thousand tons) | 535 | 463 | 488 | ||||||||||||||
| Petroleum coke (dollars per ton) | $ | 37.47 | $ | 28.41 | $ | 16.56 | |||||||||||
| Natural gas used in production (thousands of MMBtu) (1) | 6,856 | 7,933 | 7,620 | ||||||||||||||
| Natural gas used in production (dollars per MMBtu) (1) | $ | 2.88 | $ | 3.28 | $ | 3.24 | |||||||||||
| Natural gas cost of materials and other (thousands of MMBtu) (1) | 6,961 | 7,122 | 8,052 | ||||||||||||||
| Natural gas cost of materials and other (dollars per MMBtu) (1) | $ | 3.08 | $ | 3.15 | $ | 3.26 | |||||||||||
(1)The feedstock natural gas shown above does not include natural gas used for fuel. The cost of fuel natural gas is included in Direct operating expenses (exclusive of depreciation and amortization).
Financial Highlights
Overview - For the year ended December 31, 2019, Nitrogen Fertilizer Segment operating income and net loss were $27 million and $35 million, a $21 million increase and $15 million decrease, respectively, over the year ended December 31, 2018 driven primarily by increased sales volumes and pricing.
December 31, 2019 | 53
(1)See “Non-GAAP Reconciliations” section below for reconciliations of the non-GAAP measures shown below.
Net Sales - The Nitrogen Fertilizer Segment’s net sales increased by $53 million to $404 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. This increase was primarily due to favorable pricing conditions which contributed $49 million in higher revenues coupled with increased sales volumes contributing $8 million as compared to the year ended December 31, 2018. The increase in net sales was partially offset by a $3 million decrease in Urea sales. For the years ended December 31, 2019 and 2018, net sales included $33 million and $34 million in freight revenues, respectively, and $8 million and $8 million in other revenue, respectively.
The following table demonstrates the impact of changes in sales volumes and pricing for the primary components of net sales, excluding freight, for the year ended December 31, 2019 as compared to the year ended December 31, 2018:
| (in millions) | Price Variance | Volume Variance | |||||||||
| UAN | $ | 34 | $ | (5) | |||||||
| Ammonia | 15 | 13 | |||||||||
The increase in UAN and ammonia sales pricing for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to a shift in the timing of demand from the fourth quarter of 2018 to the second quarter of 2019, as customers delayed receipt of nitrogen products due to continued inclement weather. As a result, customer demand for ammonia increased in the second quarter of 2019 as customers attempted to make up for the missed application. In addition, the aforementioned ammonia application, coupled with freezing temperatures and flooding throughout the Midwest and Southern Plains in 2019, shifted the demand for ammonia, resulting in increased sales volumes for the year ended December 31, 2019 compared to the year ended December 31, 2018. The decrease in Urea sales for the year ended December 31, 2019 compared to the year ended December 31, 2018 was a result of the turnaround at our East Dubuque Facility.
December 31, 2019 | 54
(1)Exclusive of depreciation and amortization expense.
Cost of Materials and Other - Cost of materials and other for the year ended December 31, 2019 was $94 million, compared to $88 million for the year ended December 31, 2018. The $6 million increase was comprised primarily of a $5 million increase in pet coke costs at our Coffeyville Facility and a $6 million increase related to a draw in our ammonia and UAN inventories offset by decreased natural gas costs at our East Dubuque facility contributing $5 million.
Direct Operating Expenses (exclusive of depreciation and amortization) - For the year ended December 31, 2019, direct operating expenses (exclusive of depreciation and amortization) were $174 million as compared to $159 million for the year ended December 31, 2018. The $15 million increase was primarily due to increased turnaround costs of $3 million, increased repairs and maintenance costs of $1 million, and an inventory draw contributing $10 million.
Depreciation and Amortization Expense - Depreciation and amortization expense increased $8 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, as a result of accelerated depreciation of certain assets, coupled with additions to property, plant, and equipment during the current year.
Selling, General, and Administrative Expenses, and Other - Selling, general and administrative expenses and other increased approximately $4 million for the year ended December 31, 2019 compared to the year ended December 31, 2018. The increase was primarily related to asset write offs in the period contributing $3 million, coupled with increased personnel costs contributing $1 million.
December 31, 2019 | 55
Non-GAAP Measures
Our management uses certain non-GAAP performance measures to evaluate current and past performance and prospects for the future to supplement our GAAP financial information presented in accordance with U.S. GAAP. These non-GAAP financial measures are important factors in assessing our operating results and profitability and include the performance and liquidity measures defined below.
Effective January 1, 2019, the Company revised its accounting policy method for the costs of planned major maintenance activities (turnarounds) specific to the Petroleum Segment from being expensed as incurred (the direct expensing method) to the deferral method. Refer to Part II, Item 8, Note 2 (“Summary of Significant Accounting Policies”) for a further discussion of the impacts of this change in accounting policy. As a result of this change in accounting policy, the non-GAAP measures of Adjusted EBITDA, Petroleum Adjusted EBITDA, Nitrogen Fertilizer Adjusted EBITDA, Adjusted Net Income (Loss), and Direct Operating Expenses per Total Throughput Barrel net of Turnaround Expense are no longer being presented.
The following are non-GAAP measures we present for the year ended December 31, 2019:
EBITDA - Consolidated net income (loss) before (i) interest expense, net, (ii) income tax expense (benefit) and (iii) depreciation and amortization expense.
Petroleum EBITDA and Nitrogen Fertilizer EBITDA - Segment net income (loss) before segment (i) interest expense, net, (ii) income tax expense (benefit), and (iii) depreciation and amortization.
Refining Margin - The difference between our Petroleum Segment net sales and cost of materials and other.
Refining Margin adjusted for Inventory Valuation Impacts - Refining Margin adjusted to exclude the impact of current period market price and volume fluctuations on crude oil and refined product inventories recognized in prior periods. We record our commodity inventories on the first-in-first-out basis. As a result, significant current period fluctuations in market prices and the volumes we hold in inventory can have favorable or unfavorable impacts on our refining margins as compared to similar metrics used by other publicly-traded companies in the refining industry.
Refining Margin and Refining Margin adjusted for Inventory Valuation Impacts, per Throughput Barrel - Refining Margin divided by the total throughput barrels during period, which is calculated as total throughput barrels per day times the number of days in the period.
Direct Operating Expenses per Throughput Barrel - Direct operating expenses for our Petroleum Segment divided by total throughput barrels for the period, which is calculated as total throughput barrels per day times the number of days in the period.
We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S. GAAP results, including but not limited to our operating performance as compared to other publicly-traded companies in the refining industry, without regard to historical cost basis or financing methods and our ability to incur and service debt and fund capital expenditures. Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings and operating income. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures. See “Non-GAAP Reconciliations” included herein for reconciliation of these amounts. Due to rounding, numbers presented within this section may not add or equal to numbers or totals presented elsewhere within this document.
December 31, 2019 | 56
Factors Affecting Comparability of Our Financial Results
Refer to the “Non-GAAP Measures” section above for discussion of the changes made to the Company’s definition of certain non-GAAP measures.
Petroleum Segment
Coffeyville Refinery - During the fourth quarter of 2019, our Coffeyville Refinery incurred costs of $15 million related to preparations for the planned turnaround scheduled to be completed in the spring of 2020. During the first quarter of 2018, our Coffeyville Refinery experienced an outage with its fluid catalytic cracking unit (“FCCU”) lasting 48 days. The FCCU outage had a significant negative impact on production and sales during that period.
Wynnewood Refinery - During the first quarter of 2017, the Wynnewood Refinery underwent a turnaround on its hydrocracking unit at a cost of $13 million. In addition, the first phase of its planned facility turnaround was completed in the fourth quarter of 2017 at a cost of $43 million. The second phase of this turnaround was completed in the first quarter of 2019 at a cost of $24 million.
Nitrogen Fertilizer Segment
During the fourth quarter of 2018, the Partnership recognized a $6 million business interruption insurance recovery associated with an outage at its Coffeyville Fertilizer Facility during 2017. The recovery is recorded in Other income, net.
Coffeyville Fertilizer Facility - During 2018, the Coffeyville Fertilizer Facility had a planned, full facility turnaround lasting 15 days and incurred approximately $6 million in turnaround expense in the second quarter of 2018. During 2017, the Coffeyville Fertilizer Facility’s third-party air separation unit experienced a shut down. Paired with this shut down and subsequent operational challenges, the Coffeyville Fertilizer Facility experienced unplanned UAN downtime of 11 days during the second quarter of 2017.
East Dubuque Fertilizer Facility - During 2019, the East Dubuque Fertilizer Facility had a planned, full facility turnaround lasting 32 days and cost approximately $10 million in the third and fourth quarters of 2019. During 2017, the East Dubuque Fertilizer Facility had a planned, full facility turnaround lasting 14 days and incurred approximately $3 million in turnaround expense in the third quarter of 2017. Additionally, during the fourth quarter of 2017, the East Dubuque Fertilizer Facility experienced unplanned downtime totaling 12 days.
Non-GAAP Reconciliations
Reconciliation of Net Income to EBITDA
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Net income | $ | 362 | $ | 366 | $ | 258 | |||||||||||
| Add: | |||||||||||||||||
Interest expense, net | 102 | 102 | 109 | ||||||||||||||
Income tax expense (benefit) | 129 | 79 | (220) | ||||||||||||||
Depreciation and amortization | 287 | 274 | 258 | ||||||||||||||
| EBITDA | $ | 880 | $ | 821 | $ | 405 | |||||||||||
December 31, 2019 | 57
Reconciliation of Petroleum Segment Net Income to EBITDA
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Petroleum net income | $ | 559 | $ | 511 | $ | 127 | |||||||||||
| Add: | |||||||||||||||||
| Interest expense, net | 27 | 41 | 47 | ||||||||||||||
| Depreciation and amortization | 202 | 196 | 177 | ||||||||||||||
| Petroleum EBITDA | $ | 788 | $ | 748 | $ | 351 | |||||||||||
Reconciliation of Petroleum Segment Gross Profit to Refining Margin and Refining Margin Adjusted for Inventory Valuation Impact
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Net sales | $ | 5,968 | $ | 6,780 | $ | 5,664 | |||||||||||
| Cost of materials and other | 4,765 | 5,602 | 4,875 | ||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 359 | 356 | 361 | ||||||||||||||
| Depreciation and amortization | 199 | 192 | 173 | ||||||||||||||
Gross profit | 645 | 630 | 255 | ||||||||||||||
| Add: | |||||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 359 | 356 | 361 | ||||||||||||||
| Depreciation and amortization | 199 | 192 | 173 | ||||||||||||||
Refining margin | 1,203 | 1,178 | 789 | ||||||||||||||
| Inventory valuation impact, unfavorable (favorable) (1) | (43) | 33 | (29) | ||||||||||||||
Refining margin, excluding inventory valuation impacts | $ | 1,160 | $ | 1,211 | $ | 760 | |||||||||||
(1)The Petroleum Segment’s basis for determining inventory value under GAAP is First-In, First-Out (“FIFO”). 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 inventory valuation impact when crude oil prices increase and an unfavorable inventory valuation impact when crude oil prices decrease. The inventory valuation impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the inventory valuation impact per total throughput barrel, we utilize the total dollar figures for the inventory valuation impact and divide by the number of total throughput barrels for the period.
Reconciliation of Petroleum Segment Total Throughput Barrels
| Year Ended December 31, | |||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||
| Total throughput barrels per day | 215,971 | 212,595 | 218,181 | ||||||||||||||
| Days in the period | 365 | 365 | 365 | ||||||||||||||
Total throughput barrels | 78,829,441 | 77,597,175 | 79,636,065 | ||||||||||||||
Reconciliation of Petroleum Segment Refining Margin per Total Throughput Barrel
| Year Ended December 31, | |||||||||||||||||
| (in millions, except per total throughput barrel) | 2019 | 2018 | 2017 | ||||||||||||||
| Refining margin | $ | 1,203 | $ | 1,178 | $ | 789 | |||||||||||
| Divided by: total throughput barrels | 79 | 78 | 80 | ||||||||||||||
Refining margin per total throughput barrel | $ | 15.26 | $ | 15.18 | $ | 9.98 | |||||||||||
December 31, 2019 | 58
Reconciliation of Petroleum Segment Refining Margin Adjusted for Inventory Valuation Impact per Total Throughput Barrel
| Year Ended December 31, | |||||||||||||||||
| (in millions, except per total throughput barrel) | 2019 | 2018 | 2017 | ||||||||||||||
| Refining margin, excluding inventory valuation impact | $ | 1,160 | $ | 1,211 | $ | 760 | |||||||||||
| Divided by: total throughput barrels | 79 | 78 | 80 | ||||||||||||||
Refining margin per total throughput barrel | $ | 14.71 | $ | 15.60 | $ | 9.61 | |||||||||||
Reconciliation of Petroleum Segment Direct Operating Expenses per Total Throughput Barrel
| Year Ended December 31, | |||||||||||||||||
| (in millions, except per total throughput barrel) | 2019 | 2018 | 2017 | ||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) | $ | 359 | $ | 356 | $ | 361 | |||||||||||
| Divided by: total throughput barrels | 79 | 78 | 80 | ||||||||||||||
| Direct operating expenses per total throughput barrel | $ | 4.56 | $ | 4.62 | $ | 4.55 | |||||||||||
Reconciliation of Nitrogen Fertilizer Segment Net Loss to EBITDA
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Nitrogen fertilizer net loss | $ | (35) | $ | (50) | $ | (73) | |||||||||||
| Add: | |||||||||||||||||
| Interest expense, net | 62 | 62 | 63 | ||||||||||||||
| Depreciation and amortization | 80 | 72 | 74 | ||||||||||||||
| Nitrogen fertilizer EBITDA | $ | 107 | $ | 84 | $ | 64 | |||||||||||
Liquidity and Capital Resources
Our principal source of liquidity has historically been cash from operations. Our principal uses of cash are for working capital, capital expenditures, funding our debt service obligations and paying dividends to our stockholders, as further discussed below.
We believe that our cash from operations and existing cash and cash equivalents, along with borrowings, as necessary, under CVR Partners’ AB Credit Facility and CVR Refining’s Amended and Restated ABL Credit Facility, will be sufficient to satisfy anticipated cash requirements associated with our existing operations for at least the next 12 months. However, our 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 and secure additional financing depends on our future operational performance, which is subject to general economic, political, financial, competitive, and other factors, some of which may be beyond our control.
Depending on the needs of our business, contractual limitations, and market conditions, we may from time to time seek to issue equity securities, incur additional debt, issue debt securities, or otherwise refinance our existing debt. There can be no assurance that we will seek to do any of the foregoing or that we will be able to do any of the foregoing on terms acceptable to us or at all.
The Company, and its subsidiaries, were in compliance with all covenants under their respective debt instruments as of December 31, 2019, as applicable.
December 31, 2019 | 59
Cash Balances and Other Liquidity
As of December 31, 2019, we had consolidated cash and cash equivalents of $652 million, $393 million available under CVR Refining’s Amended and Restated ABL Credit Facility and $50 million available under CVR Partners’ AB Credit Facility.
| (in millions) | December 31, 2019 | December 31, 2018 | |||||||||
CVR Partners: | |||||||||||
9.25% Senior Secured Notes due June 2023 | $ | 645 | $ | 645 | |||||||
6.50% Senior Notes due April 2021 | 2 | 2 | |||||||||
| Unamortized discount and debt issuance costs | (15) | (18) | |||||||||
Total CVR Partners debt | $ | 632 | $ | 629 | |||||||
CVR Refining: | |||||||||||
6.50% Senior Notes due November 2022 (1) | $ | 500 | $ | 500 | |||||||
Unamortized debt issuance cost | (3) | (3) | |||||||||
| Total CVR Refining debt | 497 | 497 | |||||||||
| Total long-term debt | $ | 1,129 | $ | 1,126 | |||||||
(1)On January 27, 2020, the Company redeemed all of the 6.50% Senior Notes due November 2022 for a redemption price equal to 101.083%, plus accrued and unpaid interest, on the redeemed notes.
CVR Partners
The Nitrogen Fertilizer Segment has a 9.25% Senior Secured Notes due 2023, 6.50% Senior Notes due 2021, and an AB Credit Facility, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes. Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion.
CVR Refining
As of December 31, 2019, the Petroleum Segment had a 6.50% Senior Secured Notes due 2022 (the “2022 Notes”) and an Amended and Restated ABL Credit Facility, the proceeds of which may be used to fund working capital, capital expenditures, and for other general corporate purposes. As discussed above, the Company redeemed all of the 2022 Notes in January 2020. Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion.
CVR Energy
On January 27, 2020, CVR Energy issued $600 million in aggregate principal amount of 5.25% senior unsecured notes due 2025, (the “2025 Notes”), which mature on February 15, 2025, and $400 million in aggregate principal amount of 5.75% senior unsecured notes due 2028 (the “2028 Notes”), which mature on February 15, 2028. A portion of the net proceeds from the 2025 Notes and 2028 Notes were used to fund the redemption of the 2022 Notes. The remaining net proceeds will be used for general corporate purposes, which may include funding (i) acquisitions, (ii) capital projects, and/or (iii) share repurchases or other distributions to our stockholders. Refer to Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion of the issuance of these new notes and the redemption of the 2022 Notes.
Capital Spending
We divide capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes non-discretionary maintenance projects and projects required to comply with environmental, health, and safety regulations. Growth capital projects generally involve an expansion of existing capacity and/or a reduction in direct operating expenses. We undertake growth capital spending based on the expected return on incremental capital employed.
December 31, 2019 | 60
Our total capitalized costs for the year ended December 31, 2019, along with our estimated expenditures for 2020, by segment, are as follows:
| (in millions) | 2019 Actual | 2020 Estimate (1) | ||||||||||||||||||||||||||||||
| Maintenance | Growth | Total | Maintenance | Growth | Total | |||||||||||||||||||||||||||
| Low | High | Low | High | Low | High | |||||||||||||||||||||||||||
| Petroleum | $ | 79 | $ | 10 | $ | 89 | $ | 55 | $ | 60 | $ | 50 | $ | 55 | $ | 105 | $ | 115 | ||||||||||||||
| Nitrogen Fertilizer | 18 | 2 | 20 | 19 | 21 | 4 | 6 | 23 | 27 | |||||||||||||||||||||||
| Other | 5 | — | 5 | 5 | 8 | — | — | 5 | 8 | |||||||||||||||||||||||
| Total | $ | 102 | $ | 12 | $ | 114 | $ | 79 | $ | 89 | $ | 54 | $ | 61 | $ | 133 | $ | 150 | ||||||||||||||
(1)Total 2020 estimated capitalized costs include approximately $45 to 55 million of growth related projects that will require additional approvals before commencement.
Our estimated capital expenditures are subject to change due to unanticipated changes in the cost, scope, and completion time for capital projects. For example, we may experience unexpected changes in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of the refineries or nitrogen fertilizer facilities. We may also accelerate or defer some capital expenditures from time to time. Capital spending for CVR Partners is determined by the board of directors of its general partner.
In the Petroleum Segment, we capitalized $38 million and $8 million of turnaround expenditures incurred during the years ended December 31, 2019 and 2018, respectively. The next planned major turnaround within the Petroleum Segment is at the Coffeyville refinery commencing in the first quarter of 2020 with total estimated expenditures of $145 million to $155 million, of which $130 million to $140 million is expected to be incurred and capitalized in the spring of 2020. As to the Nitrogen Fertilizer Segment, the East Dubuque facility began a major scheduled turnaround on September 14, 2019, which was completed in October. We incurred $10 million during the year ended December 31, 2019 related to this turnaround.
Dividends to CVR Energy Stockholders
IEP, through its ownership of the Company’s common shares, is entitled to receive dividends that are declared and paid by the Company based on the number of shares held at each record date. The following presents dividends paid to the Company's stockholders, including IEP, during the years ended December 31, 2019:
| Dividends Paid (in millions) | ||||||||||||||||||||||||||||||||
| Related Period | Date Paid | Dividend Per Share | Stockholders | IEP | Total | |||||||||||||||||||||||||||
| 2018 - 4th Quarter | March 11, 2019 | $ | 0.75 | $ | 22 | $ | 53 | $ | 75 | |||||||||||||||||||||||
| 2019 - 1st Quarter | May 13, 2019 | $ | 0.75 | 21 | 54 | 75 | ||||||||||||||||||||||||||
| 2019 - 2nd Quarter | August 12, 2019 | $ | 0.75 | 21 | 54 | 75 | ||||||||||||||||||||||||||
| 2019 - 3rd Quarter | November 11, 2019 | $ | 0.80 | 24 | 57 | 81 | ||||||||||||||||||||||||||
| Total | $ | 3.05 | $ | 88 | $ | 218 | $ | 306 | ||||||||||||||||||||||||
On February 19, 2020, the Company’s Board of Directors declared a cash dividend for the fourth quarter of 2019 to the Company’s stockholders of $0.80 per share, or $80 million in the aggregate. The dividend will be paid on March 9, 2020 to stockholders of record at the close of business on March 2, 2020. IEP will receive approximately $57 million in respect of its ownership interest in the Company’s shares.
Dividends, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the Company’s Board of Directors.
During the years ended December 31, 2018 and 2017, the Company paid dividends totaling $2.50 and $2.00 per common unit, or $238 million and $174 million, respectively. Of these dividends, IEP received $179 million and $142 million, respectively, for the same periods.
December 31, 2019 | 61
Distributions to CVR Partners’ Unitholders
The following table presents distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, as of December 31, 2019.
| Distributions Paid (in millions) | ||||||||||||||||||||||||||||||||
| Related Period | Date Paid | Distribution Per Common Unit | Public Unitholders | CVR Energy | Total | |||||||||||||||||||||||||||
| 2018 - 4th Quarter | March 11, 2019 | $ | 0.12 | $ | 9 | $ | 5 | $ | 14 | |||||||||||||||||||||||
| 2019 - 1st Quarter | May 13, 2019 | 0.07 | 5 | 3 | 8 | |||||||||||||||||||||||||||
| 2019 - 2nd Quarter | August 12, 2019 | 0.14 | 11 | 5 | 16 | |||||||||||||||||||||||||||
| 2019 - 3rd Quarter | November 11, 2019 | 0.07 | 5 | 3 | 8 | |||||||||||||||||||||||||||
| Total | $ | 0.40 | $ | 30 | $ | 16 | $ | 46 | ||||||||||||||||||||||||
Distributions, if any, including the payment, amount, and timing thereof, are subject to change at the discretion of the board of directors of CVR Partners’ general partner. No distributions were declared for the fourth quarter of 2019.
The Partnership did not pay distributions during the year ended December 31, 2018, while during the year ended December 31, 2017, it paid a distribution of $0.02 per common unit, or $2 million. Of this distribution, CVR Energy received $1 million.
Capital Structure
On October 23, 2019, the Board of Directors of the Company authorized a stock repurchase program (the “Stock Repurchase Program”). The Stock Repurchase Program would enable the Company to repurchase up to $300 million of the Company’s common stock. Repurchases under the Stock Repurchase Program may be made from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise in accordance with applicable securities laws. The timing, price and amount of repurchases (if any) will be made at the discretion of management and are subject to market conditions as well as corporate, regulatory and other considerations. While the Stock Repurchase Program currently has a duration of four years, it does not obligate the Company to acquire any stock and may be terminated by the Company’s Board of Directors at any time. We did not repurchase any of our common stock during the year ended December 31, 2019.
Cash Flows
The following table sets forth our consolidated cash flows for the periods indicated below:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | $ | 747 | $ | 628 | $ | 248 | |||||||||||
| Investing activities | (121) | (108) | (276) | ||||||||||||||
| Financing activities | (642) | (334) | (226) | ||||||||||||||
| Net (decrease) increase in cash and cash equivalents | $ | (16) | $ | 186 | $ | (254) | |||||||||||
Operating Activities
The change in operating activities for the year ended December 31, 2019, as compared to the year ended December 31, 2018, was primarily due to favorable changes in working capital of $152 million, partially offset by a reduction in operating results, excluding non-cash items, of $22 million and unfavorable changes in non-current assets and liabilities of $11 million.
Investing Activities
The change in investing activities for the year ended December 31, 2019, as compared to the year ended December 31, 2018, was primarily due to the receipt of $36 million of proceeds from the sale of Cushing assets net of carrying value of inventory sold as part of the divestment. These net proceeds were partially offset by capital expenditures of $19 million and an increase in turnaround expenditures of $30 million primarily relating to preparations in the fourth quarter of 2019 for the
December 31, 2019 | 62
Coffeyville refinery turnaround scheduled for completion in 2020 and completion of the Wynnewood refinery turnaround in the second quarter of 2019.
Financing Activities
The change in financing activities for the year ended December 31, 2019, as compared to the year ended December 31, 2018, was primarily due to $301 million in funds used to acquire the remaining CVR Refining common units not otherwise owned by us, along with increases in CVR Energy dividends and CVR Partners distributions paid to public unitholders of $68 million and $30 million, respectively, compared to 2018, partially offset by a decrease in distributions to CVR Refining public unitholders of $93 million.
Long-Term Commitments
In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of December 31, 2019 relating to contractual obligations and other commercial commitments for the five-year period following December 31, 2019 and thereafter.
| Payments Due by Period | |||||||||||||||||||||||||||||||||||||||||
| (in millions) | 2020 | 2021 | 2022 | 2023 | 2024 | Thereafter | Total | ||||||||||||||||||||||||||||||||||
| Contractual Obligations | |||||||||||||||||||||||||||||||||||||||||
| Long-term debt (1) | $ | — | $ | 2 | $ | 500 | $ | 645 | $ | — | $ | — | $ | 1,147 | |||||||||||||||||||||||||||
| Operating leases (2) | 16 | 14 | 11 | 7 | 4 | — | 52 | ||||||||||||||||||||||||||||||||||
| Finance lease obligations (3) | 5 | 6 | 6 | 6 | 7 | 35 | 65 | ||||||||||||||||||||||||||||||||||
| Unconditional purchase obligations (4) | 95 | 80 | 77 | 75 | 71 | 375 | 773 | ||||||||||||||||||||||||||||||||||
| Interest payments (5) | 100 | 99 | 93 | 34 | 3 | 8 | 337 | ||||||||||||||||||||||||||||||||||
| Other long-term liabilities (6) | 1 | 1 | 2 | — | — | 2 | 6 | ||||||||||||||||||||||||||||||||||
| Total contractual obligations | $ | 217 | $ | 202 | $ | 689 | $ | 767 | $ | 85 | $ | 420 | $ | 2,380 | |||||||||||||||||||||||||||
(1)Consists of the 2021 Notes, 2022 Notes and 2023 Notes. Subsequent to December 31, 2019, and excluded from the table above, the Company issued the 2025 Notes and 2028 Notes and redeemed the 2022 Notes. Refer to Part II, Item 8, Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further discussion of the issuance of the 2025 Notes and 2028 Notes and the associated redemption of the 2022 Notes.
(2)We lease railcars, pipelines, storage, real estate, and other assets.
(3)The amount includes commitments under finance lease arrangements for three leases which include a pipeline lease, a storage and terminal equipment lease, and a bundled truck lease.
(4)The amount includes (i) commitments for petroleum products storage and petroleum transportation, (ii) electricity supply agreement, (iii) a product supply agreement, (iv) a pet coke supply agreement, (v) commitments related to our biofuels blending obligation, and (vi) various agreements for gas and gas transportation.
(5)Interest payments for our long-term debt outstanding and finance lease obligations as of December 31, 2019 and commitment fees on the unutilized commitments of the AB Credit Facility.
(6)The amount includes environmental liabilities. Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies. See Part I, Item 1, “Environmental Matters.”
Off-Balance Sheet Arrangements
We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.
Recent Accounting Pronouncements
Refer to Part II, Item 8, Note 2 (“Summary of Significant Accounting Policies”), of this Report for a discussion of recent accounting pronouncements applicable to us.
Critical Accounting Policies
We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions, and estimates based on the best available information at the time. Actual
December 31, 2019 | 63
results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited consolidated financial statements included elsewhere in this Report. Our critical accounting policies, which are listed below, could materially affect the amounts recorded in our consolidated financial statements.
•Derivative instruments and fair value of financial instruments;
•Goodwill impairment;
•Impairment of long-lived assets;
•Income taxes;
•Inventory finished goods valuation; and
•Lease standard adopted by the Company for ASC 842, Leases.
Refer to Part II, Item 8, Note 2 (“Summary of Significant Accounting Policies”), of this Report for a discussion of these, and other, accounting policies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Our market risk sensitive instruments and positions have inherent risks including potential loss from adverse changes in commodity prices, RINs prices, and interest rates.
Commodity Price Risk
The Petroleum Segment, as a manufacturer of refined petroleum products, and the nitrogen fertilizer segment, as a manufacturer of nitrogen fertilizer products, all of which are commodities, have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, a positive spread between the cost of raw materials and the value of finished products must be achieved (i.e., gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.
The Petroleum Segment uses a crude oil purchasing intermediary, Vitol, to purchase the majority of its non-gathered crude oil inventory for the refineries, which allows it to take title to and price its crude oil at locations in close proximity to the refineries, as opposed to the crude oil origination point, reducing its 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, the Petroleum Segment seeks to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margin as forecasted in the annual operating plan. With regard to its hedging activities, the Petroleum Segment may enter into, or has entered into, derivative instruments which serve to (1) 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, (2) hedge the value of inventories in excess of minimum required inventories, and (3) manage existing derivative positions related to a change in anticipated operations and market conditions.
Compliance Program Price Risk
As a producer of transportation fuels from petroleum, the Petroleum Segment is required to blend biofuels into the products it produces or to purchase RINs in the open market in lieu of blending to meet the mandates established by the EPA. The Petroleum Segment is exposed to market risk related to volatility in the price of RINs needed to comply with the RFS that are not otherwise generated through blending of renewable fuels in our refining and marketing operations. To mitigate the impact of this risk on the Petroleum Segment’s results of operations and cash flows, the Petroleum Segment purchases RINs when prices are deemed favorable. Refer to Part II, Item 8, Note 11 (“Commitments and Contingencies”), of this Report for further discussion about compliance with the RFS.
December 31, 2019 | 64
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CVR Energy, Inc.
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of CVR Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, 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, 2020 expressed an unqualified opinion.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Petroleum Segment’s Inventory Finished Goods Valuation
As described in Note 2 to the consolidated financial statements, the Company utilizes the ability-to-bear process to determine the valuation of its Petroleum Segment’s finished goods inventories, which was $160 million at December 31, 2019. Management makes certain estimates based on observable inputs, including monthly sales prices and current market prices to determine how much raw materials and production costs are capitalized into Inventories. Changes in these estimates could have a significant impact on the Company’s valuation of finished goods inventory.
We identified the Company’s Petroleum Segment’s finished goods inventory valuation process as a critical audit matter. The principal consideration for our determination that the inventory valuation process is a critical audit matter is the degree of complexity and subjectivity inherent in determining management’s estimates.
December 31, 2019 | 65
Our audit procedures to evaluate the valuation of the Company’s valuation of finished goods inventory, included the following procedures to test management’s process, among others:
•We tested the design and operating effectiveness of management’s processes and controls for determining the valuation of finished goods inventory.
•We obtained a sample of invoices to verify the accuracy of the production costs used in estimates.
•We tested or evaluated the reasonableness of inputs including sales volumes, monthly sales prices and current market prices for each product by obtaining third-party market prices and a sample of sales transactions by product to verify the accuracy of the information used by management.
Change in the Petroleum Segment’s Turnaround Activities Accounting
As described in Note 2 to the consolidated financial statements, effective January 1, 2019, the accounting policy for turnaround activities was changed to the deferral method for the Petroleum Segment due to its preferability as compared to the direct-expense method. This accounting policy was changed on a retrospective basis. Management made certain assumptions in determining that the deferral method was preferable; such assumptions had a significant impact on the Petroleum Segment’s determination of which accounting method was preferable for its turnaround activities.
We identified the change in accounting policy for turnaround activities as a critical audit matter. The principal consideration for our determination that the change in the Petroleum Segment’s turnaround accounting policy is a critical audit matter is due to the degree of auditor subjectivity given the limited authoritative guidance and the nature of evidence obtained in determining which method is preferable.
Our audit procedures to evaluate the Company’s determination that the deferral method was preferable, included the following procedures, among others:
•We evaluated management’s assumptions in their preferability determination, including analysis of consistency to its peer companies and management’s conclusion that the deferral method better reflects the economic substance of the benefits earned from turnaround activities. Such evaluation included consultations with our national office resources.
•We analyzed the applicable accounting guidance in assessing whether the deferral method was preferable.
•We tested the design and operating effectiveness of management’s process and controls for evaluating unique accounting conclusions and the impact to the Company’s financial statements.
•We selected a sample of turnaround invoices from current and historical periods that were used in management’s retrospective application of the change in accounting policy and inspected the invoices to determine the amounts were accurately recorded and subsequently amortized in accordance with the change to the deferral method.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2013.
Houston, Texas
February 20, 2020
December 31, 2019 | 66
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of CVR Energy, Inc.
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of CVR Energy, Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control - Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated February 20, 2020 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
February 20, 2020
December 31, 2019 | 67
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
| ASSETS | |||||||||||
| Current assets: | |||||||||||
Cash and cash equivalents (including $37 and $415, respectively, of consolidated variable interest entities (VIEs)) | $ | 652 | $ | 668 | |||||||
Accounts receivable (including $34 and $169, respectively, of VIEs) | 182 | 169 | |||||||||
Inventories (including $54 and $380, respectively, of VIEs) | 390 | 380 | |||||||||
Prepaid expenses and other current assets (including $5 and $56, respectively, of VIEs) | 67 | 76 | |||||||||
| Total current assets | 1,291 | 1,293 | |||||||||
Property, plant and equipment, net (including $952 and $2,414, respectively, of VIEs) | 2,336 | 2,430 | |||||||||
Other long-term assets (including $55 and $270, respectively, of VIEs) | 278 | 277 | |||||||||
| Total assets | $ | 3,905 | $ | 4,000 | |||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities: | |||||||||||
Note payable and finance lease obligations (including $0 and $3, respectively, of VIEs) | $ | 5 | $ | 3 | |||||||
Accounts payable (including $24 and $317, respectively, of VIEs) | 412 | 320 | |||||||||
Other current liabilities (including $52 and $154, respectively, of VIEs) | 179 | 173 | |||||||||
| Total current liabilities | 596 | 496 | |||||||||
| Long-term liabilities: | |||||||||||
Long-term debt and finance lease obligations, net of current portion (including $632 and $1,167, respectively of VIEs) | 1,190 | 1,167 | |||||||||
| Deferred income taxes | 396 | 380 | |||||||||
Other long-term liabilities (including $10 and $7, respectively, of VIEs) | 55 | 14 | |||||||||
| Total long-term liabilities | 1,641 | 1,561 | |||||||||
| Commitments and contingencies (See Note 11) | |||||||||||
| Equity: | |||||||||||
| CVR stockholders’ equity: | |||||||||||
Common stock $0.01 par value per share, 350,000,000 shares authorized, 100,629,209 and 100,629,209 shares issued as of December 31, 2019 and 2018, respectively | 1 | 1 | |||||||||
| Additional paid-in-capital | 1,507 | 1,474 | |||||||||
| Retained deficit | (113) | (187) | |||||||||
Treasury stock, 98,610 shares at cost | (2) | (2) | |||||||||
| Total CVR stockholders’ equity | 1,393 | 1,286 | |||||||||
| Noncontrolling interest | 275 | 657 | |||||||||
| Total equity | 1,668 | 1,943 | |||||||||
| Total liabilities and equity | $ | 3,905 | $ | 4,000 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
December 31, 2019 | 68
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, | |||||||||||||||||
| (in millions, except per share data) | 2019 | 2018 | 2017 | ||||||||||||||
| Net sales | $ | 6,364 | $ | 7,124 | $ | 5,988 | |||||||||||
| Operating costs and expenses: | |||||||||||||||||
| Cost of materials and other | 4,851 | 5,683 | 4,953 | ||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization as reflected below) | 533 | 517 | 516 | ||||||||||||||
| Depreciation and amortization | 278 | 263 | 247 | ||||||||||||||
| Cost of sales | 5,662 | 6,463 | 5,716 | ||||||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization as reflected below) | 117 | 112 | 113 | ||||||||||||||
| Depreciation and amortization | 9 | 11 | 11 | ||||||||||||||
| (Gain) loss on asset disposals | (4) | 6 | 3 | ||||||||||||||
| Operating income | 580 | 532 | 145 | ||||||||||||||
| Other (expense) income: | |||||||||||||||||
| Interest expense, net | (102) | (102) | (109) | ||||||||||||||
| Other income, net | 13 | 15 | 2 | ||||||||||||||
| Income before income taxes | 491 | 445 | 38 | ||||||||||||||
| Income tax expense (benefit) | 129 | 79 | (220) | ||||||||||||||
| Net income | 362 | 366 | 258 | ||||||||||||||
| Less: Net (loss) income attributable to non-controlling interest | (18) | 107 | (5) | ||||||||||||||
| Net income attributable to CVR Energy stockholders | $ | 380 | $ | 259 | $ | 263 | |||||||||||
| Basic and diluted earnings per share | $ | 3.78 | $ | 2.80 | $ | 3.03 | |||||||||||
| Dividends declared per share | $ | 3.05 | $ | 2.50 | $ | 2.00 | |||||||||||
| Weighted-average common shares outstanding: | |||||||||||||||||
| Basic and Diluted | 100.5 | 92.5 | 86.8 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
December 31, 2019 | 69
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
| Common Stockholders | |||||||||||||||||||||||||||||||||||||||||||||||
| (in millions, except share data) | Shares Issued | Common Stock | Additional Paid-In Capital | Retained Deficit | Treasury Stock | Total CVR Stockholders’ Equity | Noncontrolling Interest | Total Equity | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2016 | 86,929,660 | $ | 1 | $ | 1,197 | $ | (297) | $ | (2) | $ | 899 | $ | 889 | $ | 1,788 | ||||||||||||||||||||||||||||||||
| Dividends paid to CVR Energy stockholders | — | — | — | (174) | — | (174) | — | (174) | |||||||||||||||||||||||||||||||||||||||
| Distributions from CVR Partners to public unitholders | — | — | — | — | — | — | (2) | (2) | |||||||||||||||||||||||||||||||||||||||
| Distributions from CVR Refining to public unitholders | — | — | — | — | — | — | (47) | (47) | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 263 | — | 263 | (5) | 258 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2017 | 86,929,660 | 1 | 1,197 | (208) | (2) | 988 | 835 | 1,823 | |||||||||||||||||||||||||||||||||||||||
| Exchange offer impact | 13,699,549 | — | 276 | — | — | 276 | (192) | 84 | |||||||||||||||||||||||||||||||||||||||
| Dividends paid to CVR Energy stockholders | — | — | — | (238) | — | (238) | — | (238) | |||||||||||||||||||||||||||||||||||||||
| Distributions from CVR Refining to public unitholders | — | — | — | — | — | — | (93) | (93) | |||||||||||||||||||||||||||||||||||||||
| Other | — | — | 1 | — | — | 1 | — | 1 | |||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | 259 | — | 259 | 107 | 366 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 100,629,209 | 1 | 1,474 | (187) | (2) | 1,286 | 657 | 1,943 | |||||||||||||||||||||||||||||||||||||||
| Dividends paid to CVR Energy stockholders | — | — | — | (306) | — | (306) | — | (306) | |||||||||||||||||||||||||||||||||||||||
| Distributions from CVR Partners to public unitholders | — | — | — | — | — | — | (30) | (30) | |||||||||||||||||||||||||||||||||||||||
| Acquisition of CVR Refining non-controlling interest | — | — | (2) | — | — | (2) | (334) | (336) | |||||||||||||||||||||||||||||||||||||||
| Effect of turnaround accounting change | — | — | 35 | — | — | 35 | — | 35 | |||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | 380 | — | 380 | (18) | 362 | |||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 100,629,209 | $ | 1 | $ | 1,507 | $ | (113) | $ | (2) | $ | 1,393 | $ | 275 | $ | 1,668 | ||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
December 31, 2019 | 70
CVR Energy, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net income | $ | 362 | $ | 366 | $ | 258 | |||||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||||||||
| Depreciation and amortization | 287 | 274 | 258 | ||||||||||||||
| Deferred income taxes | 24 | 49 | (220) | ||||||||||||||
| (Gain) loss on asset disposals | (4) | 6 | 3 | ||||||||||||||
| Share-based compensation | 17 | 16 | 19 | ||||||||||||||
| Other non-cash items | 6 | 3 | 7 | ||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||
| Accounts receivable | (40) | 56 | (27) | ||||||||||||||
| Inventories | (10) | (9) | (40) | ||||||||||||||
| Prepaid expenses and other current assets | 16 | (29) | 34 | ||||||||||||||
| Due to (from) parent | 4 | 2 | (16) | ||||||||||||||
| Accounts payable | 94 | (21) | 85 | ||||||||||||||
| Deferred revenue | (15) | 11 | 1 | ||||||||||||||
| Other current liabilities | 9 | (104) | (113) | ||||||||||||||
| Other long-term assets and liabilities | (3) | 8 | (1) | ||||||||||||||
| Net cash provided by operating activities | 747 | 628 | 248 | ||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Capital expenditures | (121) | (102) | (120) | ||||||||||||||
| Turnaround expenditures | (38) | (8) | (80) | ||||||||||||||
| Proceeds from sale of assets | 37 | 1 | — | ||||||||||||||
| Investment in affiliates, net of return of investment | — | — | (76) | ||||||||||||||
| Other investing activities | 1 | 1 | — | ||||||||||||||
| Net cash used in investing activities | (121) | (108) | (276) | ||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||
| Acquisition of CVR Refining common units | (301) | — | — | ||||||||||||||
| Dividends to CVR Energy’s stockholders | (306) | (238) | (174) | ||||||||||||||
| Distributions to CVR Refining’s noncontrolling interest holders | — | (93) | (47) | ||||||||||||||
| Distributions to CVR Partners’ noncontrolling interest holders | (30) | — | (2) | ||||||||||||||
| Other financing activities | (5) | (3) | (3) | ||||||||||||||
| Net cash used in financing activities | (642) | (334) | (226) | ||||||||||||||
| Net (decrease) increase in cash and cash equivalents | (16) | 186 | (254) | ||||||||||||||
| Cash and cash equivalents, beginning of period | 668 | 482 | 736 | ||||||||||||||
| Cash and cash equivalents, end of period | $ | 652 | $ | 668 | $ | 482 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
December 31, 2019 | 71
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Organization and Nature of Business
Organization
CVR Energy, Inc. (“CVR Energy,” “CVR,” “we,” “us,” “our,” or the “Company”) is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP (the “Petroleum Segment” or “CVR Refining”) and CVR Partners, LP (the “Nitrogen Fertilizer Segment” or “CVR Partners”). CVR Refining is an independent petroleum refiner and marketer of high value transportation fuels. CVR Partners produces and markets nitrogen fertilizers in the form of urea ammonium nitrate (“UAN”) and ammonia. CVR’s common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “CVI.” Icahn Enterprises L.P. and its affiliates (“IEP”) owned approximately 71% of the Company’s outstanding common shares as of December 31, 2019.
CVR Refining, LP
On January 17, 2019, the general partner of CVR Refining assigned to the Company its right to purchase all of the issued and outstanding CVR Refining common units not already owned by CVR Refining’s general partner or its affiliates. On January 29, 2019, the Company purchased all remaining CVR Refining common units not already owned by the Company or its affiliates for a cash purchase price of $10.50 per unit (the “Call Price”), or approximately $241 million in the aggregate (the “Public Unit Purchase”). In conjunction with the exercise of its call right for all CVR Refining common units not already owned by the Company or its affiliates, the Company entered into a purchase agreement with American Entertainment Properties Corporation (“AEP”) and IEP, pursuant to which, on January 29, 2019, all of the Common Units held by AEP and IEP were purchased by the Company for a cash price per unit equal to the Call Price, or approximately $60 million in the aggregate (the “Affiliate Unit Purchase” together with the Public Unit Purchase, the “CVRR Unit Purchase”). The total purchase price of $301 million was funded with approximately $105 million in borrowings under a new credit agreement entered into by the Company on January 29, 2019, with the remaining amount being funded from the Company’s cash on hand. Amounts drawn under the new credit agreement were fully repaid in February 2019. See Note 6 (“Long-Term Debt and Finance Lease Obligations”) for further information on the credit agreement. The consolidated results of operations and financial position of CVR Refining are reflected as CVR’s Petroleum Segment. Following this transaction, CVR Refining became a wholly-owned subsidiary of the Company and, therefore, is no longer accounted for as a variable interest entity (“VIE”). Effective February 8, 2019, CVR Refining’s reporting obligations under the Exchange Act were suspended.
CVR Partners, LP
As of December 31, 2019, public security holders held approximately 66% of CVR Partners’ outstanding common units, and Coffeyville Resources, LLC (“CRLLC”), a wholly-owned subsidiary of CVR Energy, held approximately 34% of CVR Partners’ outstanding common units. In addition, CRLLC owns 100% of CVR Partners’ general partner, CVR GP, LLC, which holds a non-economic general partner interest in CVR Partners. Following the acquisition of the non-controlling interest in CVR Refining in January 2019, the non-controlling interest reflected on the consolidated balance sheets of CVR is only impacted by the net income of, and distributions from, CVR Partners.
Stock Repurchase Program
On October 23, 2019, the Board of Directors of the Company authorized a stock repurchase program (the “Stock Repurchase Program”). The Stock Repurchase Program would enable the Company to repurchase up to $300 million of the Company’s common stock. Repurchases under the Stock Repurchase Program may be made from time-to-time through open market transactions, block trades, privately negotiated transactions or otherwise in accordance with applicable securities laws. The timing, price and amount of repurchases (if any) will be made at the discretion of management and are subject to market conditions as well as corporate, regulatory and other considerations. While the Stock Repurchase Program currently has a duration of four years, it does not obligate the Company to acquire any stock and may be terminated by the Company’s Board of Directors at any time. We did not repurchase any of our common stock during the year ended December 31, 2019.
December 31, 2019 | 72
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Subsequent Events
The Company evaluated subsequent events, if any, that would require an adjustment to the Company’s consolidated financial statements or require disclosure in the notes to the consolidated financial statements through the date of issuance of the consolidated financial statements. Where applicable, the notes to these consolidated financial statements have been updated to discuss all significant subsequent events which have occurred.
(2) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of the Company and its majority-owned direct and indirect subsidiaries. All intercompany accounts and transactions have been eliminated. The ownership interests of noncontrolling investors in the Company’s subsidiaries are recorded as noncontrolling interests. CVR Energy has not recognized any other comprehensive income for the periods ended December 31, 2019, 2018, and 2017.
CVR Partners is considered a VIE. As the 100% owner of the general partner of CVR Partners, the Company has the sole ability to direct the activities that most significantly impact the economic performance of the partnership and is considered to be the primary beneficiary. In January 2019, following the CVRR Unit Purchase, CVR Refining was no longer considered a VIE and is accounted for as a wholly-owned subsidiary.
Investments in entities over which the Company has significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents CVR Energy’s proportionate share of net income generated by the equity method investees and is recorded in Other income, net on the Company’s Consolidated Statements of Operations.
Reclassifications
Certain reclassifications have been made within the consolidated financial statements for the years ended December 31, 2018 and 2017 to conform with current presentation.
Use of Estimates
These consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”), which requires management to make estimates and assumptions that affect the reported amounts and disclosure of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates are reviewed on an ongoing basis, based on currently available information. Changes in facts and circumstances may result in revised estimates, and actual results could differ from those estimates.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand and on deposit, investments in highly liquid money market accounts, and debt instruments with original maturities of three months or less.
Accounts Receivable, net
Accounts receivable primarily consist of customer accounts receivable recorded at the invoiced amounts and generally do not bear interest. Also included within accounts receivable of the Nitrogen Fertilizer Segment are unbilled fixed price contracts which is further discussed within Note 7 (“Revenue”).
Allowances for doubtful accounts are generally recorded when it becomes probable the receivable will not be collected and is booked to bad debt expense. The largest concentration of credit for any one customer at December 31, 2019 and 2018 was approximately 11% and 12%, respectively, of the net accounts receivable balance. As of December 31, 2019 and 2018, the allowance for doubtful accounts balances were immaterial.
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CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Inventories
Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress, fertilizer products, and refined fuels and by-products. All inventories are valued at the lower of the first-in, first-out (“FIFO”) cost, or net realizable value. The Petroleum Segment’s unfinished and finished products inventory values were determined using the ability-to-bear methodology. Other inventories in the Petroleum and Nitrogen Fertilizer Segments, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or net realizable value. The cost of inventories includes inbound freight costs. At December 31, 2019 and 2018, inventories related to the Nitrogen Fertilizer Segment included depreciation of approximately $5 million and $6 million, respectively.
Inventories consisted of the following:
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
| Raw materials | $ | 112 | $ | 101 | |||||||
| In-process inventories | 18 | 12 | |||||||||
| Finished goods | 177 | 186 | |||||||||
| Parts and supplies | 83 | 81 | |||||||||
| Total Inventories | $ | 390 | $ | 380 | |||||||
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. Expenditures for improvements that increase economic benefit or returns and/or extend useful life are capitalized. Depreciation is computed using the straight-line method over the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for significant asset classes are as follows:
| Asset | Range of Useful Lives, in Years | |||||||
| Land and improvements | 15 to 30 | |||||||
| Buildings and improvements | 20 to 30 | |||||||
| Machinery and equipment | 5 to 30 | |||||||
| Furniture and fixtures | 3 to 10 | |||||||
| ROU finance leases | 1 to 25 | |||||||
| Other | 5 to 30 | |||||||
Property, plant and equipment consisted of the following:
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
| Machinery and equipment (1) | $ | 3,859 | $ | 3,785 | |||||||
| Buildings and improvements | 87 | 87 | |||||||||
| Land and improvements | 46 | 43 | |||||||||
| Furniture and fixtures | 35 | 33 | |||||||||
| ROU finance leases | 27 | — | |||||||||
| Construction in progress | 95 | 102 | |||||||||
| Other | 14 | 17 | |||||||||
| 4,163 | 4,067 | ||||||||||
| Less: Accumulated depreciation | 1,827 | 1,637 | |||||||||
| Total Property, plant and equipment, net | $ | 2,336 | $ | 2,430 | |||||||
(1) Includes $29 million in leases classified as finance leases under ASC Topic 842 (Leases) as of December 31, 2019 and $32 million in leases classified as capital leases under the superseded ASC Topic 840 (Leases) as of December 31, 2018.
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CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Leasehold improvements and assets held under finance leases are depreciated or amortized on the straight-line method over the shorter of the contractual lease term or the estimated useful life of the asset. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses are reported in Direct operating expenses (exclusive of depreciation and amortization) in the Company’s Consolidated Statements of Operations.
On May 21, 2019, a subsidiary of CVR Energy sold its crude oil storage terminal located in Cushing, Oklahoma and related assets (the "Terminal"). As part of this transaction, the Company received cash consideration of $43 million for the Terminal and related crude oil inventories resulting in a recognition of a gain on sale of $9 million. The carrying value of the inventory sold as part of this transaction has been presented on a net basis, with the proceeds on sale, within the net cash used in investing section of the Consolidated Statements of Cash Flows.
Leases
At inception, the Company determines whether an arrangement is a lease and the appropriate lease classification. Operating leases are included as operating lease right-of-use (“ROU”) assets within Other long-term assets and lease liabilities within Other current liabilities and Other long-term liabilities on our Consolidated Balance Sheets. Finance leases are included as ROU finance leases within Property, plant, and equipment, net, and finance lease liabilities within Other current liabilities and Long-term debt and finance lease obligations, net of current portion on our Consolidated Balance Sheets. Leases with an initial expected term of 12 months or less are considered short-term and are not recorded on our Consolidated Balance Sheets. The Company recognizes lease expense for these leases on a straight-line basis over the expected lease term.
ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make lease payments arising from the lease. ROU assets and liabilities are recognized at the commencement date based on the present value of minimum lease payments over the lease term. The lease term is modified to reflect options to extend or terminate the lease when it is reasonably certain we will exercise such option. The depreciable life of assets and leasehold improvements is limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise, in which case the depreciation policy in the “Property, Plant and Equipment” section above is applicable. The periodic lease payments are treated as payments of the lease obligation and interest is recorded as interest expense. See “Recent Accounting Pronouncements - Adoption of Lease Standard” within this Note for a further discussion on the impacts of adopting the lease standard.
Deferred Financing Costs
Lender and other third-party costs associated with debt issuances are deferred and amortized to interest expense and other financing costs using the effective-interest method over the life of the debt. Deferred financing costs related to line-of-credit arrangements are amortized using the straight-line method through the termination date of the facility. The deferred financing costs are included net within long-term debt and in other long-term assets for the line-of-credit arrangements where no debt balance exists.
Impairment of Long-Lived Assets
Long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) are reviewed 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 asset 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.
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized, while intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. The Company uses November 1 of each year as its annual valuation date for its goodwill impairment test.
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CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company performed its annual impairment review of goodwill for 2019, 2018, and 2017 associated with CVR Partners’ Coffeyville, Kansas Nitrogen Fertilizer (the “Coffeyville Fertilizer Facility”) reporting unit and concluded there were no impairments. For the period ended December 31, 2019, no events or circumstances were identified which would trigger the performance of a quantitative analysis after reviewing all qualitative factors impacting the reporting unit including improved market conditions, financial results, and financial forecasts from those used in the fair value analysis at December 31, 2018. For the periods ended December 31, 2018 and 2017, the fair value of the Coffeyville Fertilizer Facility reporting unit exceeded its carrying value by approximately 36% and 12%, respectively, based upon the results of the reporting unit’s goodwill impairment test.
Loss Contingencies
In the ordinary course of business, the Company may become party to lawsuits, administrative proceedings, and governmental investigations, including environmental, regulatory, and other matters. The outcome of these matters cannot always be predicted accurately, but the Company accrues liabilities for these matters if the Company has determined that it is probable a loss has been incurred and the loss can be reasonably estimated.
Environmental, Health & Safety (“EHS”) Matters
The Petroleum and Nitrogen Fertilizer Segments are subject to various 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, internal and third-party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.
Revenue Recognition
The Company recognizes revenue based on consideration specified in contracts or agreements with customers when performance obligations are satisfied by transferring control over products or services to a customer. The Company’s revenue recognition patterns are described below by reportable segment:
•Petroleum Segment - The vast majority of Petroleum Segment contracts contain pricing that is based on the market price for the product at the time of delivery. Obligations to deliver product volumes are typically satisfied and revenue is recognized when control of the product transfers to customers. Concurrent with the transfer of control, the right to payment for the delivered product is received, the customer accepts the product, and the customer has significant risks and rewards of ownership of the product. Payment terms require customers to pay shortly after delivery and do not contain significant financing components. Any pass-through finished goods delivery costs reimbursed by customers are reported in Net sales, while an offsetting expense is included in Cost of materials and other. Non-monetary product exchanges and certain buy/sell transactions which are entered into in the normal course of business are included on a net cost basis in Cost of materials and other on the Consolidated Statements of Operations.
•Nitrogen Fertilizer Segment - Revenue is recognized when our customers receive control of the product. The adoption of ASC 606 resulted in the recognition of deferred revenue and related receivables, on a gross basis, associated with contracts that guarantee a price and supply of nitrogen fertilizer products in quantities expected to be delivered in the normal course of business.
Other considerations - For both segments, excise and other taxes collected from customers and remitted to governmental authorities are excluded from reported revenues.
December 31, 2019 | 76
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Cost Classifications
Cost of materials and other includes cost of crude oil, other feedstocks, blendstocks, purchased refined products, pet coke expenses, Renewable Identification Number (“RIN”) expenses, derivative gains or losses, and freight and distribution costs. Direct operating expenses (exclusive of depreciation and amortization) consist primarily of energy and other utility costs, direct costs of labor, including applicable share-based compensation expense, property taxes, plant-related maintenance services, and environmental and safety compliance costs, as well as catalyst and chemical costs. Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of labor and other direct expenses associated with the Company’s corporate activities, including accounting, finance, information technology, human resources, legal, and other related administrative functions. For the Company’s Nitrogen Fertilizer Segment, each of these financial statement line items are also impacted by changes in inventory balances.
Derivatives and Fair Value of Financial Instruments
The Petroleum Segment uses futures contracts, swaps, and forward contracts primarily to reduce exposure to changes in crude oil and finished goods product prices to provide economic hedges of inventory positions. These derivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging, and accordingly are recorded at fair value at the end of each reporting period based on quoted market prices. The Nitrogen Fertilizer Segment may enter into forward contracts with fixed delivery prices to purchase portions of its natural gas requirements. These natural gas contracts are not treated as derivatives under normal purchase and normal sale exclusions. Accordingly, the fair value of these contracts are not recorded at the end of each reporting period. Refer to Note 8 (“Derivative Financial Instruments”) for further discussion of the Company’s derivative activity.
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. Refer to Note 8 (“Derivative Financial Instruments”) for further fair value disclosures.
Turnaround Expenses
Turnarounds represent major maintenance activities that require the shutdown of significant parts of a plant to perform necessary inspection, cleaning, repairs, and replacements of assets. Costs incurred for routine repairs and maintenance or unplanned outages at our facilities are expensed as incurred. Planned turnaround activities for the Petroleum Segment vary in frequency dependent on refinery units, but generally occur every to five years, while the frequency of turnarounds in the Nitrogen Fertilizer Segment is every to three years. Further details of each segment’s turnaround expensing method are discussed below.
Petroleum Segment - Effective January 1, 2019, the Company revised its accounting policy method for the costs of planned major maintenance activities (turnarounds) specific to the Petroleum Segment from being expensed as incurred (the direct-expense method) to the deferral method. Under the deferral method, the costs of turnarounds are deferred and amortized on a straight-line basis over a -year period of time, which represents the estimated time until the next turnaround occurs. The new method of accounting for turnarounds is considered preferable as it is more consistent with the accounting policy of our peer companies and better reflects the economic substance of the benefits earned from turnaround expenditures. The Consolidated Balance Sheets for the period ended December 31, 2018, the related Consolidated Statements of Operations, Consolidated Statements of Changes in Equity, and Consolidated Statements of Cash Flows for each of the two years in the period ended December 31, 2018 have been recast to reflect our new accounting policy. Turnaround costs, and related accumulated amortization, are included in the Consolidated Balance Sheets as Other long-term assets. The amortization expense related to turnaround costs is included in Depreciation and amortization in the Consolidated Statements of Operations. During the years ended December 31, 2019, 2018, and 2017, the Petroleum Segment capitalized $38 million, $8 million, and $87 million, respectively.
Nitrogen Fertilizer Segment - The Nitrogen Fertilizer Segment follows the direct-expense method of accounting for turnaround activities. Costs associated with these turnaround activities were included in Direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations. During the years ended December 31, 2019, 2018, and 2017, the Nitrogen Fertilizer Segment incurred turnaround expenses of $10 million, $6 million, and $3 million, respectively.
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CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The following presents the financial statement line items impacted by the Petroleum Segment turnaround accounting change for each of the periods presented within these consolidated financial statements.
Effect of Turnaround Accounting Change on Consolidated Balance Sheet as of December 31, 2018
| December 31, 2018 | |||||||||||||||||
| (in millions) | As Previously Reported | Effect of Turnaround Accounting Change | As Stated | ||||||||||||||
| Property, plant and equipment, net of accumulated depreciation | $ | 2,445 | $ | (15) | $ | 2,430 | |||||||||||
| Other long-term assets (1) | 169 | 108 | 277 | ||||||||||||||
| Total assets | $ | 3,907 | $ | 93 | $ | 4,000 | |||||||||||
| Long-term liabilities: | |||||||||||||||||
| Deferred income taxes (2) | $ | 362 | $ | 18 | $ | 380 | |||||||||||
| Total long-term liabilities | 1,543 | 18 | 1,561 | ||||||||||||||
| Equity: | |||||||||||||||||
| CVR stockholders’ equity: | |||||||||||||||||
| Additional paid-in-capital | $ | 1,473 | $ | 1 | $ | 1,474 | |||||||||||
| Retained deficit | (226) | 39 | (187) | ||||||||||||||
| Total CVR stockholders’ equity | 1,246 | 40 | 1,286 | ||||||||||||||
| Noncontrolling interest | 622 | 35 | 657 | ||||||||||||||
| Total equity | 1,868 | 75 | 1,943 | ||||||||||||||
| Total liabilities and equity | $ | 3,907 | $ | 93 | $ | 4,000 | |||||||||||
(1) This represents the capitalized turnaround asset recognized due to the turnaround policy change.
(2) This represents the increase in deferred tax liability due to the recognition of the capitalized turnaround asset.
Effect of Turnaround Accounting on Consolidated Statement of Operations and Consolidated Statement of Cash Flows for the Years Ended December 31, 2018 and 2017
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2018 | 2017 | ||||||||||||||||||||||||||||||||||
| (in millions) | As Previously Reported | Effect of Turnaround Accounting Change | As Stated | As Previously Reported | Effect of Turnaround Accounting Change | As Stated | |||||||||||||||||||||||||||||
| Consolidated Statement of Operations | |||||||||||||||||||||||||||||||||||
| Direct operating expenses | $ | 523 | $ | (6) | $ | 517 | $ | 598 | $ | (82) | $ | 516 | |||||||||||||||||||||||
| Depreciation and amortization | 202 | 61 | 263 | 203 | 44 | 247 | |||||||||||||||||||||||||||||
| Income tax expense (benefit) | 89 | (10) | 79 | (217) | (3) | (220) | |||||||||||||||||||||||||||||
| Net income (loss) | $ | 411 | $ | (45) | $ | 366 | $ | 217 | $ | 41 | $ | 258 | |||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interest | 122 | (15) | 107 | (18) | 13 | (5) | |||||||||||||||||||||||||||||
| Net income attributable to CVR Energy stockholders | $ | 289 | $ | (30) | $ | 259 | $ | 235 | $ | 28 | $ | 263 | |||||||||||||||||||||||
| Consolidated Statement of Cash Flows | |||||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 620 | $ | 8 | $ | 628 | $ | 168 | $ | 80 | $ | 248 | |||||||||||||||||||||||
| Net cash used by investing activities | $ | (100) | $ | (8) | $ | (108) | $ | (196) | $ | (80) | $ | (276) | |||||||||||||||||||||||
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CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Share-Based Compensation
The Company accounts for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation (“ASC 718”). Currently, all of the Company’s share-based compensation awards, including those issued by CVR Refining and CVR Partners, are liability-classified and are measured at fair value at the end of each reporting period based on the applicable closing unit price. Compensation expense will fluctuate based on changes in the applicable share or unit prices and expense reversals resulting from employee terminations prior to award vesting. Additionally, the Company has issued certain performance unit awards. The fair value of these performance unit awards is recognized as compensation expense only if the attainment of the performance conditions is considered probable. Uncertainties involved in this estimate include continued employment requirements and whether or not the performance conditions will be attained. The performance objectives are set in accordance with approved levels of the business plan for the fiscal year during the performance cycle and, therefore, are considered reasonably possible of being achieved. If this assumption proves not to be true and the awards do not vest, compensation expense recognized during the performance cycle will be reversed. See Note 9 (“Share-Based Compensation”) for further discussion.
Income Taxes
Income taxes are accounted for utilizing the asset and liability approach. Under this method, deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. In assessing the realizability of the deferred income tax assets, including net operating loss and state tax credit carryforwards, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred income tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Further, the Company recognizes interest expense (income) and penalties on uncertain tax positions and income tax deficiencies (refunds) in Income tax expense (benefit).
Earnings Per Share
There were no dilutive awards outstanding during the years ended December 31, 2019, 2018, and 2017.
Recent Accounting Pronouncements - Adoption of Lease Standard
In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases” (“ASU 2016-02”), creating a new topic, FASB ASC Topic 842, “Leases” (“Topic 842”), which supersedes lease requirements in FASB ASC Topic 840, “Leases.” The new standard revises accounting for operating leases by a lessee, among other changes, and requires a lessee to recognize a liability related to future lease payments and a right-of-use (“ROU”) asset representing its right to use of the underlying asset for the lease term on the consolidated balance sheets.
We adopted Topic 842 as of January 1, 2019, electing the option to apply the transition provisions at the adoption date instead of the earliest comparative period presented in the financial statements. In connection with the adoption of Topic 842, we made the following elections:
•Only ROU assets and related lease liabilities for leases with an initial term greater than one year were and will be recognized;
•The accounting treatment for existing land easements was carried forward;
•Lease and non-lease components were and will not be bifurcated for all of the Company’s asset groups, respectively; and
•The portfolio approach was, and will be, used in the selection of the discount rate used to calculate minimum lease payments and the related ROU asset and operating lease liability amounts.
The Company’s adoption of Topic 842 resulted in the recognition of additional ROU assets and lease liabilities of approximately $56 million as of January 1, 2019, in addition to the recognition of a finance lease asset of $26 million with an
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
obligation of $23 million. There were no impacts to our consolidated statements of operations or cash flows. See Note 4 (“Leases”) for further discussion.
| (in millions) | December 31, 2018 As Stated (1) | Effect of Adoption of Topic 842 | January 1, 2019 As Adjusted | ||||||||||||||
| Current assets: | |||||||||||||||||
| Prepaid expenses and other current assets | $ | 76 | $ | (3) | (2) | $ | 73 | ||||||||||
| Total currents assets | 1,293 | (3) | 1,290 | ||||||||||||||
| Property, plant and equipment, net | 2,430 | 26 | (3) | 2,456 | |||||||||||||
| Other long-term assets | 277 | 56 | (4) | 333 | |||||||||||||
| Total assets | $ | 4,000 | $ | 79 | $ | 4,079 | |||||||||||
| Current liabilities: | |||||||||||||||||
| Other current liabilities | $ | 176 | $ | 16 | (5) | $ | 192 | ||||||||||
| Total current liabilities | 496 | 16 | 512 | ||||||||||||||
| Long-term debt and finance lease obligations | 1,167 | 23 | (3) | 1,190 | |||||||||||||
| Other long-term liabilities | 14 | 40 | (5) | 54 | |||||||||||||
| Total long-term liabilities | 1,561 | 63 | 1,624 | ||||||||||||||
| Equity: | |||||||||||||||||
| Total liabilities and equity | $ | 4,000 | $ | 79 | $ | 4,079 | |||||||||||
(1)Represents the retrospectively adjusted balance sheet amounts upon reflection of the turnaround accounting change, for which the Recast Form 8-K for 2018 was filed on June 12, 2019, prior to the adoption of Topic 842.
(2)Represents lease prepayments reclassified to ROU assets.
(3)The additional $26 million ROU asset and $23 million in lease liability represents a lease with a third-party that met the definition of a finance lease under ASC 842 as compared to an operating lease under ASC 840.
(4)Represents recognition of initial ROU assets for operating leases, including the reclassification of certain lease prepayments as noted above.
(5)Represents the initial recognition of lease liabilities.
Recent Accounting Pronouncements - Adoption of Internal-Use Software Standard
In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40). This ASU better aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is also a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. Effective January 1, 2019, we adopted this ASU and chose to apply the prospective approach for all implementation costs incurred after the date of adoption. We evaluated the effects of adopting this new accounting guidance and concluded it did not have a material impact on the Company’s consolidated financial position or results of operations.
Recent Accounting Pronouncements - New Accounting Standards Issued But Not Yet Implemented
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). The ASU replaces the incurred loss model with a current expected credit loss model for more timely recognition of expected impairment losses for most financial assets and certain other instruments that are not measured at fair value through net income. Effective January 1, 2020, the Company adopted this ASU and evaluated the effects of adopting this new accounting guidance. The adoption will not have a material impact on the Company’s consolidated financial position or results of operations.
In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820). The ASU eliminates such disclosures as the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. Effective January 1, 2020, we adopted this ASU and evaluated the effects of adopting this new accounting guidance. The adoption did not have a material impact on the Company’s disclosures.
In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740). The ASU simplifies the accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and modifies other areas of the topic to clarify the application of GAAP. Certain amendments within the standard are required to be applied on a retrospective basis
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and others on a prospective basis. This standard is effective for the company beginning January 1, 2021, with early adoption permitted. The Company is evaluating the effect of adopting this new accounting guidance on its consolidated financial statements, but does not currently expect adoption will have a material impact on the Company’s consolidated financial position or results of operations.
(3) Equity Method Investments
For each of the following investments, CVR Refining has the ability to exercise influence through its participation in the management committees, which make all significant decisions. However, since CVR Refining has equal or proportionate influence over each committee as a joint partner without regard to its economic interest and does not serve as the day-to-day operator, we have determined that these entities should not be consolidated and have applied the equity method of accounting.
•Enable South Central Pipeline, LLC (“Enable JV”, formerly Velocity Pipeline Partners, LLC) - CVR Refining owns a 40% interest in Enable JV, which operates a 12-inch 26-mile crude oil pipeline with a capacity of approximately 115,000 barrels per day that is connected to the Wynnewood Refinery. The remaining interest in Enable JV is owned by Enable Midstream Partners, LP.
•Midway Pipeline, LLC (“Midway JV”) - CVR Refining owns a 50% interest in Midway JV, which operates a 16-inch 100 mile crude oil pipeline with a capacity of approximately 120,000 barrels per day which connects the Coffeyville Refinery to the Cushing Oklahoma oil hub.
| (in millions) | Enable JV | Midway JV | Total | ||||||||||||||
| Balance at December 31, 2017 | 6 | 77 | 83 | ||||||||||||||
| Cash Distributions | (2) | (5) | (7) | ||||||||||||||
| Equity income | 2 | 6 | 8 | ||||||||||||||
| Balance at December 31, 2018 | 6 | 78 | 84 | ||||||||||||||
| Cash Distributions | (4) | (9) | (13) | ||||||||||||||
| Equity income | 4 | 6 | 10 | ||||||||||||||
| Balance at December 31, 2019 | $ | 6 | $ | 75 | $ | 81 | |||||||||||
(4) Leases
Lease Overview
We lease certain pipelines, storage tanks, railcars, office space, land, and equipment across our refining, fertilizer, and corporate operations. Most leases include one or more options to renew, with renewal terms that can extend the lease term from to 20 years or more. The exercise of lease renewal options is at our sole discretion. Certain leases also include options to purchase the leased property. The depreciable life of assets and leasehold improvements is limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. Certain of our lease agreements include rental payments which are adjusted periodically for factors such as inflation. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants. Additionally, we do not have any material lessor or sub-leasing arrangements.
The adoption of Topic 842 impacted our January 1, 2019 consolidated balance sheet, as shown below, only for those line items impacted.
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Effect of Initial Adoption of Topic 842 - January 1, 2019
ROU Assets. Upon initial recognition, our ROU assets for operating and finance leases were comprised of the following:
| (in millions) | January 1, 2019 (initial recognition) | ||||
| Pipeline and storage agreements (1) | $ | 29 | |||
| Railcar leases (2) | 15 | ||||
| Real Estate and other leases (3) | 35 | ||||
| Total ROU assets | $ | 79 | |||
(1) Includes finance leased assets of $1 million as of January 1, 2019.
(2) Includes $14 million of railcar leases recognized by CVR Partners.
(3) Includes finance leased assets of $25 million recognized upon adoption of Topic 842 as of January 1, 2019.
Lease Liabilities. Upon initial recognition, our lease liabilities for operating and finance leases were comprised of the following:
| (in millions) | January 1, 2019 (initial recognition) | |||||||
| Current liabilities: | ||||||||
| Operating leases | $ | 14 | ||||||
| Finance leases | 2 | |||||||
| Long-term liabilities: | ||||||||
| Operating leases | 40 | |||||||
| Finance leases | 23 | |||||||
| Total lease liabilities | $ | 79 | ||||||
Balance Sheet Summary as of December 31, 2019
The following tables summarize the right of use asset and lease liability balances for the Company’s operating and finance leases at December 31, 2019:
| (in millions) | December 31, 2019 | ||||
| Operating Leases: | |||||
| ROU assets, net | |||||
| Pipeline and storage | $ | 20 | |||
| Railcars | 12 | ||||
| Real estate and other | 16 | ||||
| Lease liability | |||||
| Pipelines and storage | $ | 22 | |||
| Railcars | 12 | ||||
| Real estate and other | 14 | ||||
| (in millions) | December 31, 2019 | ||||
| Finance Leases: | |||||
| ROU assets, net | |||||
| Pipeline and storage | $ | 29 | |||
| Real estate and other | 24 | ||||
| Lease liability | |||||
| Pipelines and storage | $ | 40 | |||
| Real estate and other | 25 | ||||
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Lease Expense Summary for the Year Ended December 31, 2019
We recognize lease expense on a straight-line basis over the lease term. For the year ended December 31, 2019, we recognized lease expense comprised of the following components:
| (in millions) | December 31, 2019 | ||||
| Operating lease expense | $ | 12 | |||
| Finance lease expense: | |||||
| Amortization of ROU | $ | 7 | |||
| Interest expense on lease liability | 6 | ||||
Short-term lease expense, recognized within Direct operating expenses (exclusive of depreciation and amortization), was $8 million for the year ended December 31, 2019.
Lease Terms and Discount Rates
The following outlines the remaining lease terms and discount rates used in the measurement of the Company’s ROU assets and liabilities:
| December 31, 2019 | January 1, 2019 (initial recognition) | ||||||||||
| Weighted-average remaining lease term (years) | |||||||||||
| Operating Leases | 3.7 | 4.4 | |||||||||
| Finance Leases | 9.0 | 10.3 | |||||||||
| Weighted-average discount rate | |||||||||||
| Operating Leases | 5.6 | % | 5.8 | % | |||||||
| Finance Leases | 8.9 | % | 9.8 | % | |||||||
Maturities of Lease Liabilities
The following summarizes the remaining minimum lease payments through maturity of the Company’s right-of-use assets and liabilities at December 31, 2019:
| (in millions) | Operating Leases | Finance Leases | |||||||||
| 2020 | $ | 16 | $ | 11 | |||||||
| 2021 | 14 | 11 | |||||||||
| 2022 | 11 | 11 | |||||||||
| 2023 | 7 | 10 | |||||||||
| 2024 | 4 | 10 | |||||||||
| Thereafter | — | 43 | |||||||||
| Total lease payments | 52 | 96 | |||||||||
| Less: imputed interest | (4) | (31) | |||||||||
| Total lease liability | $ | 48 | $ | 65 | |||||||
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(5) Other Current Liabilities
Other current liabilities were as follows:
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
| Personnel accruals | $ | 47 | $ | 40 | |||||||
| Accrued taxes other than income taxes | 28 | 28 | |||||||||
| Deferred revenue | 28 | 69 | |||||||||
| Accrued income taxes | 24 | — | |||||||||
| Operating lease liabilities (1) | 14 | — | |||||||||
| Accrued interest | 9 | 9 | |||||||||
| Accrued derivatives | 7 | — | |||||||||
| Accrued Renewable Fuel Standards (“RFS”) obligation | 7 | 4 | |||||||||
| Share-based compensation | 6 | 5 | |||||||||
| Other accrued expenses and liabilities | 9 | 18 | |||||||||
| Total other current liabilities | $ | 179 | $ | 173 | |||||||
(1) The lease standard was adopted on January 1, 2019 on a prospective basis. Therefore, only 2019 disclosures are applicable to be included within the table above.
(6) Long-Term Debt and Finance Lease Obligations
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
CVR Partners: | |||||||||||
9.25% Senior Secured Notes due June 2023 (1) | $ | 645 | $ | 645 | |||||||
6.50% Senior Notes due April 2021 | 2 | 2 | |||||||||
| Unamortized discount and debt issuance costs | (15) | (18) | |||||||||
Total CVR Partners debt | $ | 632 | $ | 629 | |||||||
CVR Refining: | |||||||||||
6.50% Senior Notes due November 2022 (2) | $ | 500 | $ | 500 | |||||||
| Finance lease obligations, net of current portion (3) | 61 | 41 | |||||||||
Unamortized debt issuance cost | (3) | (3) | |||||||||
| Total CVR Refining debt | 558 | 538 | |||||||||
| Total long-term debt and finance lease obligations | $ | 1,190 | $ | 1,167 | |||||||
(1)This debt was issued at a $16 million discount which is being amortized, as interest expense, over the remaining term of the debt. Debt issuance costs associated with this debt totaled $9 million.
(2)Debt issuance costs associated with this debt totaled $9 million. On January 29, 2019, the 2022 Notes were amended such that CVR Energy was included as the primary guarantor, on a senior unsecured basis, of the 2022 Notes. The CVR Energy guarantee is full and unconditional and joint and several. On January 27, 2020, the Company redeemed all of the 2022 Notes for a redemption price equal to 101.083%, plus accrued and unpaid interest, on the redeemed notes.
(3)Current portion of finance lease obligations was approximately $5 million and $3 million as of December 31, 2019 and 2018, respectively.
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Credit Facilities
| (in millions) | Total Capacity | Amount Borrowed as of December 31, 2019 | Outstanding Letters of Credit | Available Capacity as of December 31, 2019 | Maturity Date | ||||||||||||||||||||||||
CVR Partners: | |||||||||||||||||||||||||||||
Asset Based (“AB”) Credit Facility (1) | 50 | — | — | 50 | September 30, 2021 | ||||||||||||||||||||||||
| CVR Refining: | |||||||||||||||||||||||||||||
Amended and Restated Asset Based (“Amended and Restated ABL”) Credit Facility (2) | $ | 400 | $ | — | $ | 7 | $ | 393 | November 14, 2022 | ||||||||||||||||||||
(1)Loans under the AB Credit Facility initially bear interest at an annual rate equal to (i) 2.00% plus LIBOR or (ii) 1.00% plus a base rate, subject to a 0.50% step-down based on the previous quarter’s excess availability.
(2)Loans under the Amended and Restated ABL Credit Facility initially bear interest at an annual rate equal to (i) 1.50% plus LIBOR or (ii) 0.50% plus a base rate, subject to quarterly excess availability.
The Company is in compliance with all covenants of the AB credit facilities, Amended and Restated ABL, and the senior notes as of December 31, 2019.
CVR Partners
AB Credit Facility - On September 30, 2016, CVR Partners entered into a senior secured asset based revolving credit facility (the “AB Credit Facility”) with a group of lenders and UBS AG (“UBS”), as administrative agent and collateral agent. The AB Credit Facility has an aggregate principal amount of availability of up to $50 million with an incremental facility, which permits an increase in borrowings of up to $25 million in the aggregate subject to additional lender commitments and certain other conditions. The AB Credit Facility is scheduled to mature on September 30, 2021.
2023 Notes - On June 10, 2016, CVR Partners and CVR Nitrogen Finance Corporation (“CVR Nitrogen Finance”), an indirect wholly-owned subsidiary of CVR Partners (together the “2023 Notes Issuers”), certain subsidiary guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral trustee, completed a private offering of $645 million aggregate principal amount of 9.25% Senior Secured Notes due 2023 (the “2023 Notes”). The 2023 Notes mature on June 15, 2023, unless earlier redeemed or repurchased by the issuers. Interest on the 2023 Notes is payable semi-annually in arrears on June 15 and December 15 of each year. The 2023 Notes are guaranteed on a senior secured basis by all of the Nitrogen Fertilizer Partnership’s existing subsidiaries.
On or after June 15, 2019, the 2023 Notes Issuers may on any one or more occasions, redeem all or part of the 2023 Notes at the redemption prices set forth below expressed as a percentage of the principal amount of the 2023 Notes plus accrued and unpaid interest to the applicable redemption date.
| 12-month period beginning June 15, | Percentage | |||||||
| 2019 | 104.625% | |||||||
| 2020 | 102.313% | |||||||
| 2021 and thereafter | 100.000% | |||||||
The 2023 Notes contain customary covenants for a financing of this type that, among other things, restrict CVR Partners’ ability and the ability of certain of its subsidiaries to: (i) sell assets; (ii) pay distributions on, redeem or repurchase the Nitrogen Fertilizer Partnership’s units or redeem or repurchase its subordinated debt; (iii) make investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from the CVR Partners’ restricted subsidiaries to CVR Partners; (vii) consolidate, merge or transfer all or substantially all of the CVR Partners’ assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. 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 2023 Notes to cause the acceleration of the 2023 Notes, in addition to the pursuit of other available remedies.
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CVR Refining
Amended and Restated ABL Credit Facility - On November 14, 2017, CRLLC, CVR Refining, its wholly-owned subsidiary, CVR Refining, LLC (“Refining LLC”) and each of the operating subsidiaries of Refining LLC (collectively, the “Credit Parties”) entered into Amendment No. 1 to the Amended and Restated ABL Credit Agreement (the “Amendment”) with a group of lenders and Wells Fargo Bank, National Association (“Wells Fargo”), as administrative agent and collateral agent. The Amended and Restated ABL is a $400 million asset-based revolving credit facility, with sub-limits for letters of credit and swingline loans of $60 million and $40 million, respectively. The Amended and Restated ABL also includes a $200 million uncommitted incremental facility.
2022 Notes - On October 23, 2012, CVR Refining, LLC (“Refining LLC”) and Coffeyville Finance Inc. (“Coffeyville Finance”) completed a private offering of $500 million aggregate principal amount of 6.50% Second Lien Senior Notes due 2022 (the “2022 Notes”). The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The 2022 Notes are unsecured and fully and unconditionally guaranteed by CVI, 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. On January 29, 2019, the Company, and certain of the Company’s subsidiaries, executed a full and unconditional guarantee of the 2022 Notes.
On January 27, 2020, the Company redeemed all of the outstanding 2022 Notes and settled accrued interest of approximately $8 million through the date of redemption. The redeemed notes were repurchased for approximately $505 million, or 101.083% of par value. Previously deferred financing charges related to the 2022 Notes totaled approximately $3 million. As a result of this transaction, the Company will recognize a $8 million loss on extinguishment of debt in the first quarter of 2020, which includes the total premiums paid of $5 million and the write-off of previously deferred financing charges of $3 million.
CVR Energy
2025 Notes and 2028 Notes - On January 27, 2020, CVR Energy completed a private offering of $600 million aggregate principal amount of 5.25% Senior Unsecured Notes due 2025 (the “2025 Notes”) and $400 million aggregate principal amount of 5.75% Senior Unsecured Notes due 2028 (the “2028 Notes” and, collectively with the 2025 Notes, the “Notes”). Interest on the Notes is payable semi-annually in arrears on February 15 and August 15 each year, commencing on August 15, 2020. The 2025 Notes mature on February 15, 2025, unless earlier redeemed or repurchased by the issuers. The 2028 Notes mature on February 15, 2028, unless earlier redeemed or repurchased by the issuers. The Notes are jointly and severally guaranteed on a senior unsecured basis by the wholly-owned subsidiaries of CVR Energy with the exception of CVR Partners and its subsidiaries and certain immaterial wholly-owned subsidiaries of CVR Energy.
In relation to the issuance of the Notes, the Company received $993 million of net cash proceeds, net of underwriting fees and other third-party fees and expenses associated with the offering. The debt issuance costs of the Notes totaled approximately $7 million and are being amortized over the terms of the respective notes as interest expense using the effective-interest amortization method.
On or after February 15, 2022 and February 15, 2023, we may on any one or more occasions, redeem all or part of the 2025 Notes and 2028 Notes, respectively, at the redemption prices set forth below expressed as a percentage of the principal amount of the respective notes, plus accrued and unpaid interest to the applicable redemption date.
| 2025 Notes | 2028 Notes | |||||||||||||||||||
| 12-month period beginning February 15, | Percentage | 12-month period beginning February 15, | Percentage | |||||||||||||||||
| 2022 | 102.625% | 2023 | 102.875% | |||||||||||||||||
| 2023 | 101.313% | 2024 | 101.917% | |||||||||||||||||
| 2024 and thereafter | 100.000% | 2025 | 100.958% | |||||||||||||||||
| 2026 and thereafter | 100.000% | |||||||||||||||||||
The indenture governing the Notes imposes covenants that will, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional indebtedness or issue certain disqualified equity; (ii) create liens on certain assets
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to secure debt; (iii) pay dividends or make other equity distributions; (iv) purchase or redeem capital stock; (v) make certain investments; (vi) sell assets; (vii) agree to certain restrictions on the ability of restricted subsidiaries to make distributions, loans, or other asset transfers to us; (viii) consolidate, merge, sell, or otherwise dispose of all or substantially all of our assets; (ix) engage in transactions with affiliates; and (x) designate our restricted subsidiaries as unrestricted subsidiaries. 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 2025 Notes and 2028 Notes to cause, amongst other available remedies, the acceleration of the respective notes.
Credit Agreement - On January 29, 2019, the Company entered into a credit agreement (the “Credit Agreement”) with Jefferies Finance LLC to provide a term loan credit facility with a maturity date of March 10, 2019. The borrowings under the Credit Agreement of $105 million were used to fund a portion of the CVRR Unit Purchase. All amounts were repaid on February 11, 2019. As the original maturity was less than three months from the issuance date, the borrowings and repayments under the credit agreement qualified for net reporting on the Consolidated Statements of Cash Flows.
(7) Revenue
The following tables present the Company’s revenue disaggregated by major product. The following tables include a reconciliation of the disaggregated revenue by product and other revenue components for the Company’s reportable segments.
| Year Ended December 31, 2019 | |||||||||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Other / Eliminations | Consolidated | |||||||||||||||||||
| Gasoline | $ | 3,050 | $ | — | $ | — | $ | 3,050 | |||||||||||||||
| Distillates (1) | 2,705 | — | — | 2,705 | |||||||||||||||||||
| Ammonia | — | 94 | — | 94 | |||||||||||||||||||
| UAN | — | 251 | — | 251 | |||||||||||||||||||
| Other urea products | — | 18 | — | 18 | |||||||||||||||||||
| Freight revenue | 23 | 33 | — | 56 | |||||||||||||||||||
| Other (2) | 129 | 8 | (8) | 129 | |||||||||||||||||||
| Revenue from product sales | 5,907 | 404 | (8) | 6,303 | |||||||||||||||||||
| Crude oil sales | 58 | — | — | 58 | |||||||||||||||||||
Other revenue (2) | 3 | — | — | 3 | |||||||||||||||||||
| Total revenue | $ | 5,968 | $ | 404 | $ | (8) | $ | 6,364 | |||||||||||||||
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| Year Ended December 31, 2018 | |||||||||||||||||||||||
| (in millions) | Petroleum | Nitrogen Fertilizer | Other / Eliminations | Consolidated | |||||||||||||||||||
| Gasoline | $ | 3,383 | $ | — | $ | — | $ | 3,383 | |||||||||||||||
| Distillates (1) | 3,083 | — | — | 3,083 | |||||||||||||||||||
| Ammonia | — | 66 | — | 66 | |||||||||||||||||||
| UAN | — | 222 | — | 222 | |||||||||||||||||||
| Other urea products | — | 21 | — | 21 | |||||||||||||||||||
| Freight revenue | 23 | 34 | — | 57 | |||||||||||||||||||
| Other (2) | 190 | 8 | (7) | 191 | |||||||||||||||||||
| Revenue from product sales | 6,679 | 351 | (7) | 7,023 | |||||||||||||||||||
| Crude oil sales | 96 | — | — | 96 | |||||||||||||||||||
Other revenue (2) | 5 | — | — | 5 | |||||||||||||||||||
| Total revenue | $ | 6,780 | $ | 351 | $ | (7) | $ | 7,124 | |||||||||||||||
(1)Distillates consist primarily of diesel fuel, kerosene, and jet fuel.
(2)Other revenue consists primarily of feedstock and asphalt sales and Cushing, OK storage tank lease revenue. See Note 2 (“Summary of Significant Accounting Policies”) for further discussion on the Cushing, OK storage tanks.
Petroleum Segment
The Petroleum Segment’s revenue from product sales is recorded upon delivery to customers, which is the point at which title is transferred and the customer has assumed the risk of loss. This generally takes place as product passes into the pipeline, as a product transfer order occurs within a pipeline system, or as product enters equipment or locations supplied or designated by the customer. Qualifying excise and other taxes collected from the Petroleum Segment’s customers and remitted to governmental authorities are not included in reported revenues.
Many of the Petroleum Segment’s contracts have index-based pricing which is considered variable consideration that should be estimated in determining the transaction price. The Petroleum Segment determined that it does not need to estimate the variable consideration because the uncertainty related to the consideration is resolved on the pricing date or the date when the product is delivered.
The Petroleum Segment may incur broker commissions or transportation costs prior to product transfer on some of its sales. The Petroleum Segment expenses these broker costs, since the contract durations are less than a year. Transportation costs are accounted for as fulfillment costs and are expensed as incurred since they do not meet the requirement for capitalization.
The Petroleum Segment’s contracts with its customers state the terms of the sale, including the description, quantity, and price of each product sold. Depending on the product sold, payment from customers is generally due in full within 2 to 32 days of product delivery or invoice date. The Petroleum Segment generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification. The Petroleum Segment has determined that product returns or refunds are very rare and will account for them as they occur.
Freight revenue recognized by the Petroleum Segment is primarily tariff and line loss charges rebilled to customers to reimburse the Petroleum Segment for expenses incurred from a pipeline operator. An offsetting expense is included in Cost of materials and other.
Nitrogen Fertilizer Segment
The Nitrogen Fertilizer Segment sells its products on a wholesale basis under a contract or by purchase order. The Nitrogen Fertilizer Segment’s contracts with customers generally contain fixed pricing and most have terms of less than one year. The Nitrogen Fertilizer Segment recognizes revenue at the point in time at which the customer obtains control of the product, which is generally upon delivery and acceptance by the customer. The customer acceptance point is stated in the contract and may be
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at one of the Nitrogen Fertilizer Segment’s manufacturing facilities, at one of the Nitrogen Fertilizer Segment’s off-site loading facilities, or at the customer’s designated facility. Freight revenue recognized by the Nitrogen Fertilizer Segment represents the pass-through finished goods delivery costs incurred prior to customer acceptance and is reimbursed by customers. An offsetting expense for freight is included in Cost of materials and other. Qualifying excise and other taxes collected from the Nitrogen Fertilizer Segment’s customers and remitted to governmental authorities are not included in reported revenues.
Depending on the product sold and the type of contract, payments from customers are generally either due prior to delivery or within 15 to 30 days of product delivery.
The Nitrogen Fertilizer Segment generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specifications. Product returns are rare, and as such, the Nitrogen Fertilizer Segment does not record a specific warranty reserve or consider activities related to such warranty, if any, to be a separate performance obligation.
The Nitrogen Fertilizer Segment has an immaterial amount of variable consideration for contracts with an original duration of less than a year. A small portion of the Nitrogen Fertilizer Segment’s revenue includes contracts extending beyond one year, some of which contain variable pricing in which the majority of the variability is attributed to the market-based pricing. The Nitrogen Fertilizer Segment’s contracts do not contain a significant financing component.
The Nitrogen Fertilizer Segment has an immaterial amount of fee-based revenue, included in other revenue in the table above, that is recognized based on the net amount of the proceeds received, consistent with prior accounting practice.
Remaining performance obligations
As of December 31, 2019, the Nitrogen Fertilizer Segment had approximately $9 million of remaining performance obligations for contracts with an original expected duration of more than one year. The Nitrogen Fertilizer Segment expects to recognize approximately $4 million of these performance obligations as revenue by the end of 2020, an additional $3 million by 2021, and the remaining balance thereafter.
Contract balances
The Nitrogen Fertilizer Segment’s deferred revenue is a contract liability that primarily relates to fertilizer sales contracts requiring customer prepayment prior to product delivery to guarantee a price and supply of nitrogen fertilizer. Deferred revenue is recorded at the point in time in which a prepaid contract is legally enforceable and the associated right to consideration is unconditional prior to transferring product to the customer. An associated receivable is recorded for uncollected prepaid contract amounts. Contracts requiring prepayment are generally short-term in nature and, as discussed above, revenue is recognized at the point in time in which the customer obtains control of the product. At December 31, 2019, $19 million of the deferred revenue balance pertained to prepaid contracts where the associated receivable was recognized as it had not yet been collected by the Nitrogen Fertilizer Segment.
A summary of the Nitrogen Fertilizer Segment’s deferred revenue activity during the year ended December 31, 2019 is presented below:
| (in millions) | |||||
| Balance at December 31, 2018 | $ | 69 | |||
| Add: | |||||
| New prepay contracts entered into during the period (1) | 46 | ||||
| Less: | |||||
| Revenue recognized that was included in the contract liability balance at the beginning of the period | 68 | ||||
| Revenue recognized related to contracts entered into during the period | 18 | ||||
| Other changes | 1 | ||||
| Balance at December 31, 2019 | $ | 28 | |||
(1)Includes $27 million where the payment associated with prepaid contracts was collected.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Major Customers
Petroleum Segment - The Petroleum Segment has two customers who comprise 25%, 25%, and 27% of petroleum net sales for the years ended December 31, 2019, 2018, and 2017, respectively.
Nitrogen Fertilizer Segment - The Nitrogen Fertilizer Segment has two customers who comprised 28%, 20%, and 16% of nitrogen fertilizer net sales for the years ended December 31, 2019, 2018, and 2017, respectively.
(8) Derivative Financial Instruments
Our segments are 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, the Petroleum Segment from time to time enters into various commodity derivative transactions. On a regular basis, the Company enters into commodity contracts with counterparties for the purchases or sale of crude oil, blendstocks, various finished products, and RINs. The contracts usually qualify for the normal purchase normal sale exception and follow the accrual method of accounting. All other derivative instruments are recorded at fair value using mark-to-market accounting on a periodic basis utilizing third-party pricing.
The Petroleum Segment holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges under GAAP. There are no premiums paid or received at inception of the derivative contracts or upon settlement. The Petroleum Segment may enter into forward purchase or sale contracts associated with RINs. As of December 31, 2019, the Petroleum Segment had open fixed-price commitments to purchase 20 million RINs.
Commodity derivatives include commodity swaps and forward purchase and sale commitments. There were no outstanding commodity swap positions as of December 31, 2019 and 2018. There were approximately 3 million and 1 million in forward purchase commitments as of December 31, 2019 and 2018, respectively, and 1 million and 1 million in forward sale commitments as of December 31, 2019 and 2018, respectively.
The following outlines the gains (losses) recognized on the Company’s derivative activities, all of which are recorded in Cost of materials and other on the Consolidated Statements of Operations:
| Gain (Loss) on Derivatives | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Forward purchases and sales, net | $ | 20 | $ | 103 | $ | (26) | |||||||||||
| Swaps | — | 44 | (43) | ||||||||||||||
| Futures | (1) | (1) | (1) | ||||||||||||||
| Total gain (loss) on derivatives, net | $ | 19 | $ | 146 | $ | (70) | |||||||||||
The following outlines our open commodity derivative instruments, which are classified as Prepaid expenses and other current assets and Other current liabilities on the Consolidated Balance Sheets:
| Open Commodity Derivative Instruments | Year Ended December 31, | ||||||||||
| (in millions of barrels) | 2019 | 2018 | |||||||||
| Forward Contracts: | |||||||||||
| Canadian crude oil | 5 | 2 | |||||||||
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Offsetting Assets and Liabilities
The Company elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty. These amounts are recognized as current assets and current liabilities within the Prepaid expenses and other current assets and Other current liabilities financial statement line items, respectively, in the Consolidated Balance Sheets as follows:
| Derivative Assets | Derivative Liabilities | ||||||||||||||||||||||
| December 31, | December 31, | ||||||||||||||||||||||
| (in millions) | 2019 | 2018 | 2019 | 2018 | |||||||||||||||||||
| Commodity Derivatives | $ | 3 | $ | 8 | $ | (11) | $ | 1 | |||||||||||||||
| Less: Counterparty Netting | (3) | (1) | 3 | (1) | |||||||||||||||||||
| Total Net Fair Value of Derivatives | $ | — | $ | 7 | $ | (8) | $ | — | |||||||||||||||
In accordance with FASB ASC Topic 820 — Fair Value Measurements and Disclosures (“ASC 820”), the Company utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets, liabilities, or a group of assets or liabilities, such as a business.
ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
•Level 1 — Quoted prices in active markets for identical assets or liabilities
•Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)
•Level 3 — Significant unobservable inputs (including the Company’s own assumptions in determining the fair value)
The following table sets forth the assets and liabilities measured or disclosed at fair value on a recurring basis, by input level, as of December 31, 2019 and 2018:
| December 31, 2019 | |||||||||||||||||||||||
| (in millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||
| Location and Description | |||||||||||||||||||||||
| Other current liabilities (commodity derivatives) | $ | — | $ | (8) | $ | — | $ | (8) | |||||||||||||||
| Other current liabilities (RFS obligation) | — | (7) | — | (7) | |||||||||||||||||||
| Long-term debt | — | (1,180) | — | (1,180) | |||||||||||||||||||
| Total Liabilities | $ | — | $ | (1,195) | $ | — | $ | (1,195) | |||||||||||||||
| December 31, 2018 | |||||||||||||||||||||||
| (In millions) | Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||
| Location and Description | |||||||||||||||||||||||
| Cash equivalents | $ | 50 | $ | — | $ | — | $ | 50 | |||||||||||||||
| Other current assets (derivative agreements) | — | 7 | — | 7 | |||||||||||||||||||
| Total Assets | 50 | 7 | — | 57 | |||||||||||||||||||
| Other current liabilities (RFS obligation) | — | (2) | — | (2) | |||||||||||||||||||
| Long-term debt | — | (1,163) | — | (1,163) | |||||||||||||||||||
| Total Liabilities | $ | — | $ | (1,165) | $ | — | $ | (1,165) | |||||||||||||||
As of December 31, 2019 and 2018, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s cash equivalents, derivative instruments, and the RFS obligation. The Petroleum Segment’s commodity derivative contracts and RFS obligation, which use fair value measurements and are valued using broker quoted
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
market prices of similar instruments, are considered Level 2 inputs. The Company had no transfers of assets or liabilities between any of the above levels during the year ended December 31, 2019.
(9) Share-Based Compensation
Overview
CVR Energy, CVR Refining, and CVR Partners all have a Long-Term Incentive Plans (collectively, the “LTIPs”) which permit the granting of options, stock and unit appreciation rights (“SARs”), restricted shares, restricted stock units, phantom units, unit awards, substitute awards, other unit-based awards, cash awards, dividend and distribution equivalent rights, share awards, and performance awards (including performance share units, performance units, and performance-based restricted stock). Individuals who are eligible to receive awards and grants under the LTIPs include the employees, officers, and directors of the Company, CVR Refining, and CVR Partners. The Company had 6.8 million shares or units, as applicable, available for future grants under our plans at December 31, 2019.
Incentive and Phantom Unit Awards
Incentive and phantom unit awards have been granted to officers, employees, and directors (collectively, the “Share-Based Awards”) under the LTIPs. As a result, Share-Based Awards that reflect the value and dividend or distributions of CVR Energy, CVR Refining, or CVR Partners have been granted and remain outstanding as of December 31, 2019. Each Share-Based Award and the related dividend or distribution equivalent right represents the right to receive, upon vesting, a cash payment equal to (i) the average fair market value of one share or unit, as applicable, in accordance with the award agreement, plus (ii) the per share or unit cash value of all dividends or distributions declared and paid, as applicable, from the grant date through the vesting date. The Share-Based Awards are generally graded-vesting awards, which are expected to vest over three years with one-third of the award vesting each year the grantee remains employed by the Company or its subsidiaries. Compensation expense is recognized ratably, based on service provided to the Company and its subsidiaries, with the amount recognized fluctuating as a result of the Share-Based Awards being re-measured to fair value at the end of each reporting period due to their liability-award classification.
A summary of activity for the Company’s Share-Based Awards for the year ended December 31, 2019 is presented below:
| Shares or Units | Weighted-Average Grant-Date Fair Value (per share or unit) | Aggregate Intrinsic Value (in millions) | |||||||||||||||
| Non-vested at December 31, 2018 | 2,432,073 | $ | 12.13 | $ | 24 | ||||||||||||
| Granted | 1,317,661 | 16.21 | |||||||||||||||
| Vested | (1,142,021) | 10.98 | |||||||||||||||
| Forfeited | (154,026) | 11.94 | |||||||||||||||
| Non-vested at December 31, 2019 | 2,453,687 | $ | 14.88 | $ | 33 | ||||||||||||
Performance Unit Awards
Pursuant to an employment agreement with the Company’s current chief executive officer, the Company entered into two performance award agreements on November 1, 2017. In connection with the performance period of January 1, 2018 to December 31, 2018, a performance award was granted with a target value of $1.5 million (the “2018 CEO Performance Award”). The payout of $1.9 million, paid in February 2019, under the 2018 CEO Performance Award was based on the Company’s performance against certain safety, operating, and financial measures. Additionally, the Company entered into a performance award agreement (the “CEO Performance Award”). The CEO Performance Award represents the right to receive upon vesting, a cash payment equal to $10 million if the average closing price of the Company’s common stock over the 30-trading day period from January 4, 2022 to February 15, 2022 is equal to or greater than $60 per share.
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Compensation Expense
A summary of total share based compensation expense and unrecognized compensation expense related to the Share-Based Awards and the Company’s performance awards, the amounts allocated to each of the Company’s segments, and the amounts that were not allocated to segments during the years ended December 31, 2019, 2018, and 2017 is presented below:
| Expenses | Unrecognized Expense | ||||||||||||||||||||||||||||
| For the year ended December 31, | At December 31, 2019 | ||||||||||||||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | Amount | Weighted-Average Remaining Years | ||||||||||||||||||||||||
| Share based awards | |||||||||||||||||||||||||||||
| Incentive Units | $ | 12 | $ | 4 | $ | 7 | $ | 22 | 2.4 | ||||||||||||||||||||
| Phantom Units | 5 | 8 | 8 | 5 | 2.3 | ||||||||||||||||||||||||
| Performance awards | |||||||||||||||||||||||||||||
| CEO Performance Award | — | 2 | — | 7 | 2.0 | ||||||||||||||||||||||||
| 2018 CEO Performance Award | — | 2 | — | — | 0.0 | ||||||||||||||||||||||||
| Former CEO Performance Award | — | — | 4 | — | 0.0 | ||||||||||||||||||||||||
| Total expense | $ | 17 | $ | 16 | $ | 19 | $ | 34 | |||||||||||||||||||||
The total tax benefit recognized during the years ended December 31, 2019, 2018, and 2017 related to compensation expense was $4 million, $4 million and $7 million respectively. For the years ended December 31, 2019, 2018, and 2017, the Company paid cash of $23 million, $17 million, and $16 million, respectively, to settle liability-classified awards upon vesting.
Other Benefit Plans
The Company sponsors and administers two defined-contribution 401(k) plans, the CVR Energy 401(k) Plan and the CVR Energy 401(k) Plan for Represented Employees (the “Plans”), in which the Company’s employees may participate. Participants in the Plans may elect to contribute a designated percentage of their eligible compensation in accordance with the Plans, subject to statutory limits. The Company provides a matching contribution of 100% of the first 6% of eligible compensation contributed by participants. Participants in both Plans are immediately vested in their individual contributions. The Plans provide for a -year vesting schedule for the Company’s matching contributions and contain a provision to count service with predecessor organizations. The Company’s contributions under the Plans were approximately $9 million, $9 million, and $9 million for the years ended December 31, 2019, 2018, and 2017, respectively.
(10) Income Taxes
Tax Allocation Agreement
Prior to the CVRR Unit Exchange, CVR Energy was a member of the consolidated federal tax group of AEP, an affiliate of IEP, and party to a tax allocation agreement with AEP (the “Tax Allocation Agreement”). The Tax Allocation Agreement provides that AEP will pay all consolidated federal income taxes on behalf of the consolidated tax group. As a result, CVR Energy was required to make payments to AEP in an amount equal to the tax liability, if any, that it would have had paid if it were to file as a consolidated group separate and apart from AEP.
Following the CVRR Unit Exchange, IEP and affiliates’ ownership of CVR Energy was reduced below 80% and, since that time, CVR Energy is no longer eligible to file as a member of the AEP consolidated federal income tax group. Beginning with the tax period after the exchange, CVR Energy became the parent of a new consolidated group for U.S. federal income tax purposes and will file and pay its federal income tax obligations directly to the IRS. Pursuant to the terms of the Tax Allocation Agreement, however, CVR Energy may be required to make payments in respect of taxes owed by AEP for periods prior to the exchange. Similar principles may apply for state or local income tax purposes where CVR Energy filed combined, consolidated or unitary tax returns with AEP. AEP has been notified by the IRS that its income tax return for the period ended December 31, 2017 will be examined.
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As of December 31, 2019 and 2018, the Company recognized a nominal payable and $4 million receivable for income taxes due to or from AEP. The receivable is recognized as Prepaid expenses and other current assets in the Consolidated Balance Sheets. As of December 31, 2019 and 2018, the Company’s Consolidated Balance Sheets also reflected a payable of $20 million to and receivable of $12 million from, respectively, the IRS and certain state jurisdictions.
Income Tax Expense (Benefit)
Income tax expense (benefit) is comprised of the following:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Current: | |||||||||||||||||
| Federal | $ | 96 | $ | 31 | $ | (1) | |||||||||||
| State | 5 | (7) | (22) | ||||||||||||||
| Total current | 101 | 24 | (23) | ||||||||||||||
| Deferred: | |||||||||||||||||
| Federal | 3 | 39 | (186) | ||||||||||||||
| State | 25 | 16 | (11) | ||||||||||||||
| Total deferred | 28 | 55 | (197) | ||||||||||||||
Total income tax expense (benefit) | $ | 129 | $ | 79 | $ | (220) | |||||||||||
The following is a reconciliation of total income tax expense (benefit) to income tax expense (benefit) computed by applying the statutory federal income tax rate to pretax income:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Tax computed at federal statutory rate | $ | 103 | $ | 94 | $ | 14 | |||||||||||
| State income taxes, net of federal tax benefit | 29 | 12 | (14) | ||||||||||||||
| State tax incentives, net of federal tax expense | (4) | (4) | (7) | ||||||||||||||
| Noncontrolling interest | 4 | (23) | 1 | ||||||||||||||
| Other, net | (3) | — | — | ||||||||||||||
| Adjustment to deferred tax assets and liabilities for enacted change in federal tax rate (1) | — | — | (214) | ||||||||||||||
Total income tax expense (benefit) | $ | 129 | $ | 79 | $ | (220) | |||||||||||
(1)The income tax benefit for the year ended December 31, 2017 was favorably impacted as a result of the Tax Cuts and Jobs Act legislation that was signed into law in December 2017, reducing the federal income tax rate from 35% to 21% beginning in 2018. As a result, the Company’s net deferred tax liabilities at December 31, 2017 were remeasured to reflect the lower tax rate in effect for the years in which the deferred tax assets and liabilities will be realized.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Deferred Tax Assets and Liabilities
The income tax effect of temporary differences that give rise to the Deferred income tax assets and Deferred income tax liabilities at December 31, 2019 and 2018 are as follows:
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
| Deferred income tax assets: | |||||||||||
| State tax credit carryforward, net | $ | 7 | $ | 11 | |||||||
| Total gross deferred income tax assets | 7 | 11 | |||||||||
| Deferred income tax liabilities: | |||||||||||
| Investment in CVR Partners | (61) | (59) | |||||||||
| Investment in CVR Refining | (341) | (327) | |||||||||
| Other | (1) | (5) | |||||||||
| Total gross deferred income tax liabilities | (403) | (391) | |||||||||
| Net deferred income tax liabilities | $ | (396) | $ | (380) | |||||||
Although realization is not assured, management believes that it is more likely than not that all of the Deferred income tax assets will be realized, and therefore, no valuation allowance was recognized as of December 31, 2019 and 2018.
As of December 31, 2019, CVR Energy has state tax credits of approximately $16 million, which are available to reduce future state income taxes. These credits can be carried forward indefinitely.
Uncertain Tax Positions
A reconciliation of unrecognized tax benefits is as follows:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Balance, beginning of year | $ | 23 | $ | 29 | $ | 44 | |||||||||||
| Increase in current year tax positions (interest expense) | 2 | — | — | ||||||||||||||
| Reductions related to expirations from statute of limitations | (3) | (6) | (15) | ||||||||||||||
| Balance, end of year | $ | 22 | $ | 23 | $ | 29 | |||||||||||
Included in the balance of unrecognized tax benefits as of December 31, 2019, 2018, and 2017 are $15 million, $18 million, and $23 million, respectively, of tax benefits that, if recognized, would affect the effective tax rate. Approximately $5 million, $6 million, and $15 million of the unrecognized tax positions relating to state income tax credits were recognized in 2019, 2018, and 2017, respectively, as a result of expirations from statute of limitations. Additionally, the Company believes that it is reasonably possible that approximately $3 million of its unrecognized tax positions related to state income tax credits may be recognized by the end of 2020 as a result of the expiration of statute of limitations. Approximately $10 million and $22 million of unrecognized tax benefits were netted with Deferred income tax asset carryforwards as of December 31, 2019 and 2018, respectively. The remaining unrecognized tax benefits are included in Other long-term liabilities in the Consolidated Balance Sheets.
CVR Energy recognized nominal interest benefit and nominal liability for interest as of December 31, 2019, interest benefit of approximately $1 million and a nominal liability for interest as of December 31, 2018, and interest expense of approximately $7 million and recognized a liability for interest of approximately $1 million as of December 31, 2017. No penalties were recognized during 2019, 2018, or 2017.
At December 31, 2019, the Company’s tax filings are generally open to examination in the United States for the tax years ended December 31, 2016 through December 31, 2018 and in various individual states for the tax years ended December 31, 2015 through December 31, 2018.
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(11) Commitments and Contingencies
Supply Commitments
The minimum required payments for unconditional purchase obligations are as follows:
| Year Ended December 31, | Unconditional Purchase Obligations | ||||
| (in millions) | |||||
| 2020 | $ | 95 | |||
| 2021 | 80 | ||||
| 2022 | 77 | ||||
| 2023 | 75 | ||||
| 2024 | 71 | ||||
| Thereafter | 375 | ||||
| $ | 773 | ||||
Supply Commitments - The Company is a party to various supply agreements with both related and third parties which commit the Company to purchase minimum volumes of crude oil, hydrogen, oxygen, nitrogen, pet coke, and natural gas to run its facilities’ operations. For the years ended December 31, 2019, 2018, and 2017, amounts purchased under these supply agreements totaled approximately $167 million, $214 million, and $209 million, respectively.
Crude Oil Supply Agreement
On August 31, 2012, an indirect, wholly-owned subsidiary of CVR Refining entered into an Amended and Restated Crude Oil Supply Agreement (as amended, the “Crude Oil Supply Agreement”) with Vitol Inc. (“Vitol”). Under the Crude Oil Supply Agreement, Vitol supplies the Petroleum Segment with crude oil and intermediation logistics helping to reduce the amount of inventory held at a certain locations and mitigate crude oil pricing risk. Volumes contracted under the Crude Oil Supply Agreement, as a percentage of the total crude oil purchases (in barrels), was approximately 36%, 42% and 55% for the years ended December 31, 2019, 2018, and 2017, respectively. The Crude Oil Supply Agreement, which currently extends through December 31, 2020, automatically renews for successive -year terms (each such term, a “Renewal Term”) unless either party provides the other with notice of nonrenewal at least 180 days prior to expiration of any Renewal Term.
Contingencies
CVRR Unit Purchase - During 2019, the Company, CVR Refining and its general partner, CVR Refining Holdings, IEP, and certain directors and affiliates have been named in at least one of nine lawsuits filed in the Court of Chancery of the State of Delaware by purported former unitholders of CVR Refining, on behalf of themselves and an alleged class of similarly situated unitholders (the “Call Option Lawsuits”). The Call Option Lawsuits primarily allege breach of contract, tortious interference and breach of the implied covenant of good faith and fair dealing and seek monetary damages and attorneys’ fees, among other remedies, relating to the Company’s exercise of the call option under the CVR Refining Amended and Restated Agreement of Limited Partnership assigned to it by CVR Refining’s general partner. In January 2020, the court dismissed CVR Holdings and certain former directors of CVR Refining’s general partner from the Call Option Lawsuits, although permitted some or all of the claims to proceed against each remaining defendant. The Company believes the Call Option Lawsuits are without merit and intends to vigorously defend against them. The Call Option Lawsuits remain in the early stages of litigation. Accordingly the Company cannot determine at this time the outcome of the Call Option Lawsuits, including whether the outcome of this matter would have a material impact on the Company’s financial position, results of operations, or cash flows.
Property Tax Matter - In September 2018, the Kansas Court of Appeals upheld property tax determinations by the Kansas Board of Tax Appeals in connection with Coffeyville Resources Nitrogen Fertilizer, LLC’s (“CRNF”) dispute with Montgomery County, Kansas (the “County”) over prior year property tax payments as previously disclosed. On October 29, 2018, the County petitioned the Kansas Supreme Court to review the Court of Appeals’ determination. Subsequent briefs were filed by CRNF and the County. In April 2019, CRNF and the County executed an agreement which the County agrees to withdraw its petition to the Kansas Supreme Court and CRNF is expected to recover approximately $8 million through favorable property tax assessments from 2019 through 2028, subject to the terms of the settlement agreement.
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Wynnewood Small Refinery Exemption - During 2019, Wynnewood Refining Company, LLC (“WRC”) intervened in a lawsuit filed by four ethanol and biofuels trade associations against the EPA, claiming the EPA exceeded its authority in granting Wynnewood’s 2017 small refinery exemption (“SRE”) under the RFS program under the CAA, as well as the SREs of two other unrelated refineries. In January 2020, the 10th Circuit Court of Appeals vacated the three SREs and remanded the matter to the EPA for further proceedings, holding, in part, that the “extension” language in the CAA requires a small refinery to have received an SRE continuously in every year since inception of the program to be eligible. As the EPA has not yet acted following remand by the court, and as Wynnewood intends to appeal this ruling, we cannot currently estimate the outcome, impact, or timing of the resolution of this matter.
Environmental, Health, and Safety (“EHS”) Matters
Clean Air Act Matter - On August 21, 2018, Coffeyville Resources Refining and Marketing (“CRRM”), a subsidiary of CVR Refining, received a letter from the United States Department of Justice (“DOJ”) on behalf of the EPA and Kansas Department of Health and Environment (“KDHE”) alleging violations of the Clean Air Act (“CAA”) and a 2012 Consent Decree between CRRM, the United States (on behalf of EPA), and KDHE at CRRM’s Coffeyville refinery. In September 2018, CRRM executed a tolling agreement with the DOJ and KDHE extending time for negotiation regarding the agencies’ allegations through March 2019, and this tolling agreement was extended through April 30, 2020. At this time the Company cannot reasonably estimate the potential penalties, costs, fines or other expenditures that may result from this matter or any subsequent enforcement or litigation relating thereto and, therefore, the Company cannot determine if the ultimate outcome of this matter will have a material impact on the Company’s financial position, results of operations or cash flows.
Renewable Fuel Standards - The Company’s Petroleum Segment is subject to the RFS of the Environmental Protection Agency (“EPA”) that require refiners to either blend renewable fuels in with their transportation fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. The Petroleum Segment is not able to blend the substantial majority of its transportation fuels and has to purchase RINs on the open market, and may have to obtain waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS.
The Company recognized an expense of approximately $43 million, $60 million, and $249 million for the years ended December 31, 2019, 2018, and 2017, respectively, for the Petroleum Segment’s compliance with the RFS. The recognized amounts are included within Cost of materials and other in the Consolidated Statements of Operations. The Company’s costs to comply with the RFS include the purchased cost of RINs acquired, the impact of recognizing the Petroleum Segment’s uncommitted biofuel blending obligation at fair value based on market prices at each reporting date, and the valuation change of RINs acquired in excess of its RFS obligation as of the reporting date. During the year ended December 31, 2019, the Company’s cost to comply with RFS was favorably impacted by a reduction in CVR Refining’s RFS obligation and reduced market pricing. As of December 31, 2019 and 2018, the Petroleum Segment’s RFS obligation was approximately $7 million and $4 million, respectively, which is recorded in Other current liabilities in the Consolidated Balance Sheets.
Environmental Remediation - As of December 31, 2019 and 2018, environmental accruals representing estimated costs for future remediation efforts at certain Petroleum Segment sites totaled approximately $6 million and $8 million, respectively. These amounts are reflected in Other current liabilities or Other long-term liabilities depending on when the Company expects to expend such amounts.
Wynnewood Refinery Incident - On September 28, 2012, the Petroleum Segment’s Wynnewood refinery, owned and operated by WRC, an indirect wholly-owned subsidiary of CVR Refining, 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. The Company completed an internal investigation of the incident and cooperated with the Occupational Safety and Health Administration (“OSHA”) in its investigation. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation, communicated its citations, and placed WRC in its Severe Violators Enforcement Program (“SVEP”). The Company is vigorously contesting the citations and OSHA’s placement of WRC in the SVEP. Any penalties associated with OSHA’s citations are not expected to have a material adverse effect on the consolidated financial statements.
December 31, 2019 | 97
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(12) Business Segments
The Company has two operating segments: Petroleum and Nitrogen Fertilizer. These operating segments are also the Company’s reportable segments. As discussed in Note 1 (“Organization and Nature of Business”), the Petroleum Segment is comprised entirely of the consolidated operations of CVR Refining and its subsidiaries, while the Nitrogen Fertilizer Segment is comprised entirely of the consolidated operations of CVR Partners and its subsidiaries. The other amounts reflect intercompany eliminations, corporate cash and cash equivalents, income tax activities, and other corporate activities that are not allocated to the operating segments. All operations of the segments are located within the United States.
The following tables summarize operating results, capital expenditures, and total asset information by segment:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Net sales | |||||||||||||||||
| Petroleum | $ | 5,968 | $ | 6,780 | $ | 5,664 | |||||||||||
| Nitrogen Fertilizer | 404 | 351 | 331 | ||||||||||||||
| Other | (8) | (7) | (7) | ||||||||||||||
| Total | $ | 6,364 | $ | 7,124 | $ | 5,988 | |||||||||||
| Operating income (loss) | |||||||||||||||||
| Petroleum | $ | 574 | $ | 544 | $ | 172 | |||||||||||
| Nitrogen Fertilizer | 27 | 6 | (10) | ||||||||||||||
| Other | (21) | (18) | (17) | ||||||||||||||
| Total | 580 | 532 | 145 | ||||||||||||||
| Interest expense, net | (102) | (102) | (109) | ||||||||||||||
| Other income, net | 13 | 15 | 2 | ||||||||||||||
| Income before income taxes | $ | 491 | $ | 445 | $ | 38 | |||||||||||
| Depreciation and amortization | |||||||||||||||||
| Petroleum | $ | 202 | $ | 196 | $ | 177 | |||||||||||
| Nitrogen Fertilizer | 80 | 72 | 74 | ||||||||||||||
| Other | 5 | 6 | 7 | ||||||||||||||
| Total | $ | 287 | $ | 274 | $ | 258 | |||||||||||
| Capital expenditures (1) | |||||||||||||||||
| Petroleum | $ | 89 | $ | 89 | $ | 103 | |||||||||||
| Nitrogen fertilizer | 20 | 19 | 12 | ||||||||||||||
| Other | 5 | 3 | — | ||||||||||||||
| Total | $ | 114 | $ | 111 | $ | 115 | |||||||||||
The following table summarizes total assets by segment:
| December 31, | |||||||||||
| (in millions) | 2019 | 2018 | |||||||||
| Petroleum | $ | 3,187 | $ | 2,453 | |||||||
| Nitrogen Fertilizer | 1,138 | 1,254 | |||||||||
| Other (2) | (420) | 293 | |||||||||
| Total assets | $ | 3,905 | $ | 4,000 | |||||||
(1)Capital expenditures are shown exclusive of capitalized turnaround and capitalized software costs.
(2)Includes elimination of intercompany assets.
December 31, 2019 | 98
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(13) Supplemental Cash Flow Information
Cash flows related to income taxes, interest, leases, and capital expenditures included in accounts payable were as follows:
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Supplemental disclosures: | |||||||||||||||||
| Cash paid for income taxes, net of refunds | $ | 69 | $ | 31 | $ | 15 | |||||||||||
| Cash paid for interest | 104 | 103 | 106 | ||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities (1): | |||||||||||||||||
| Operating cash flows from operating leases | 16 | ||||||||||||||||
| Operating cash flows from finance leases | 6 | ||||||||||||||||
| Financing cash flows from finance leases | 5 | ||||||||||||||||
| Non-cash investing and financing activities: | |||||||||||||||||
| Change in construction in progress included in accounts payable (2) | (7) | 9 | (5) | ||||||||||||||
(1)The lease standard was adopted on January 1, 2019 on a prospective basis. Therefore, only 2019 disclosures are applicable to be included within the table above. See Note 2 (“Summary of Significant Accounting Policies”).
(2)Capital expenditures are shown exclusive of capitalized turnaround expenditures and capitalized software.
(14) Related Party Transactions
Activity associated with the Company’s related party arrangements for the years ended December 31, 2019, 2018, and 2017 is summarized below:
| Expenses with related parties | |||||||||||||||||
| Year Ended December 31, | |||||||||||||||||
| (in millions) | 2019 | 2018 | 2017 | ||||||||||||||
| Cost of materials and other | |||||||||||||||||
| Joint Venture Transportation Agreement: | |||||||||||||||||
| Enable JV | $ | 12 | $ | 8 | $ | 2 | |||||||||||
| Payments (received) made | |||||||||||||||||
| Dividends (1) | 218 | 179 | 142 | ||||||||||||||
| Tax Allocation Agreement: | |||||||||||||||||
| American Entertainment Properties Corporation | (3) | 12 | 15 | ||||||||||||||
| Amounts due from related parties | |||||||||||
| (in millions) | December 31, 2019 | December 31, 2018 | |||||||||
| Tax Allocation Agreement: | |||||||||||
| American Entertainment Properties Corporation | $ | — | $ | 4 | |||||||
(1)See below for a summary of the dividends paid to IEP for the years ended December 31, 2019, 2018, and 2017.
Enable Joint Venture Agreement
CVR Refining is party to a transportation agreement as part of the Enable JV for an initial term of 20 years under which Enable provides transportation services for crude oil purchased within a defined geographic area. Additionally, CVR Refining entered into a terminalling services agreement with Enable JV under which it receives access to Enable JV’s terminal in Lawrence, Oklahoma to unload and pump crude oil into Enable JV’s pipeline for an initial term of 20 years.
December 31, 2019 | 99
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Midway Joint Venture
For the years ended December 31, 2019, 2018, and 2017, CRRM incurred costs of $21 million, $18 million, and $3 million, respectively, from crude oil transportation services incurred on the Midway JV through Vitol as the intermediary purchasing agent.
Property Exchange
On October 18, 2019, the audit committee of CVR Energy and the Conflicts Committee of the board of directors of CVR GP each agreed to authorize the exchange of certain parcels of property owned by subsidiaries of CVR Energy with an equal number of parcels owned by subsidiaries of CVR Partners, all located in Coffeyville, Kansas (the “Property Exchange”). On February 19, 2020, a subsidiary of CVR Energy and a subsidiary of CVR Partners executed the Property Exchange agreement. This Property Exchange will enable each such subsidiary to create a more usable, contiguous parcel of land near its own operating footprint. CVR Energy and the Partnership accounted for this transaction in accordance with the ASC 805-50 guidance on transferring assets between entities under common control. This transaction had a net impact to the Partnership’s partners’ capital of approximately $0.1 million.
Dividends to CVR Energy Stockholders
IEP, through its ownership of the Company’s common shares, is entitled to receive dividends that are declared and paid by the Company based on the number of shares held at each record date. The following presents dividends paid to the Company's stockholders, including IEP, during the years ended December 31, 2019:
| Dividends Paid (in millions) | ||||||||||||||||||||||||||||||||
| Related Period | Date Paid | Dividend Per Share | Stockholders | IEP | Total | |||||||||||||||||||||||||||
| 2018 - 4th Quarter | March 11, 2019 | $ | 0.75 | $ | 22 | $ | 53 | $ | 75 | |||||||||||||||||||||||
| 2019 - 1st Quarter | May 13, 2019 | 0.75 | 21 | 54 | 75 | |||||||||||||||||||||||||||
| 2019 - 2nd Quarter | August 12, 2019 | 0.75 | 21 | 54 | 75 | |||||||||||||||||||||||||||
| 2019 - 3rd Quarter | November 11, 2019 | 0.80 | 24 | 57 | 81 | |||||||||||||||||||||||||||
| Total | $ | 3.05 | $ | 88 | $ | 218 | $ | 306 | ||||||||||||||||||||||||
On February 19, 2020, the Company’s Board of Directors declared a cash dividend for the fourth quarter of 2019 to the Company’s stockholders of $0.80 per share, or $80 million in the aggregate. The dividend will be paid on March 9, 2020 to stockholders of record at the close of business on March 2, 2020. IEP will receive approximately $57 million in respect of its ownership interest in the Company’s shares.
Dividends, if any, including the payment, amount and timing thereof, are subject to change at the discretion of the Company’s Board of Directors.
During the years ended December 31, 2018 and 2017, the Company paid dividends totaling $2.50 and $2.00 per common unit, or $238 million and $174 million, respectively. Of these dividends, IEP received $179 million and $142 million, respectively, for the same periods.
December 31, 2019 | 100
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Distributions to CVR Partners’ Unitholders
The following table presents distributions paid by CVR Partners to CVR Partners’ unitholders, including amounts received by the Company, as of December 31, 2019.
| Distributions Paid (in millions) | ||||||||||||||||||||||||||||||||
| Related Period | Date Paid | Distribution Per Common Unit | Public Unitholders | CVR Energy | Total | |||||||||||||||||||||||||||
| 2018 - 4th Quarter | March 11, 2019 | $ | 0.12 | $ | 9 | $ | 5 | $ | 14 | |||||||||||||||||||||||
| 2019 - 1st Quarter | May 13, 2019 | 0.07 | 5 | 3 | 8 | |||||||||||||||||||||||||||
| 2019 - 2nd Quarter | August 12, 2019 | 0.14 | 11 | 5 | 16 | |||||||||||||||||||||||||||
| 2019 - 3rd Quarter | November 11, 2019 | 0.07 | 5 | 3 | 8 | |||||||||||||||||||||||||||
| Total | $ | 0.40 | $ | 30 | $ | 16 | $ | 46 | ||||||||||||||||||||||||
Distributions, if any, including the payment, amount, and timing thereof, are subject to change at the discretion of the board of directors of CVR Partners’ general partner. No distributions were declared for the fourth quarter of 2019.
The Partnership did not pay distributions during the year ended December 31, 2018, while during the year ended December 31, 2017, it paid a distribution of $0.02 per common unit, or $2 million. Of this distribution, CVR Energy received $1 million.
Affiliate Pension Obligations
Prior to the exchange offer discussed in Note 1 (“Organization and Nature of Business”), Mr. Carl C. Icahn, through certain affiliates, owned approximately 82% of the Company’s capital stock. Applicable pension and tax laws make each member of a “controlled group” of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability for any unfunded liabilities that may exist at the time the plan is terminated. As a result of the historical ownership interest in CVR Energy by Mr. Icahn’s affiliates (prior to the exchange offer), the Company was subject to the pension liabilities of all entities in which Mr. Icahn had a direct or indirect ownership interest of at least 80%. Two such entities, ACF Industries LLC (“ACF”) and Federal-Mogul, are the sponsors of several pension plans. As members of the controlled group, CVR Energy would be liable for any failure of ACF and Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. The unfunded plan balances for these sponsors was $435 million and $424 million as of June 30, 2018 and December 31, 2017, respectively. These results are based on the information provided by Mr. Icahn’s affiliates based on information from the plans’ actuaries. As of December 31, 2019 and 2018, and following the exchange offer, Mr. Icahn’s affiliates owned approximately 71% of the Company’s capital stock, and therefore, the Company is no longer considered to be liable for the aforementioned pension obligations of the controlled group. On October 1, 2018, Federal-Mogul was sold by Mr. Icahn’s affiliates to a third-party.
December 31, 2019 | 101
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(15) Selected Quarterly Financial Information
Summarized quarterly financial data for December 31, 2019 and 2018 is as follows:
| Year Ended December 31, 2019 | |||||||||||||||||||||||
| Quarter | |||||||||||||||||||||||
| (in millions) | First | Second | Third | Fourth | |||||||||||||||||||
| Net sales | $ | 1,486 | $ | 1,687 | $ | 1,622 | $ | 1,569 | |||||||||||||||
| Cost of materials and other (1) | 1,101 | 1,267 | 1,221 | 1,262 | |||||||||||||||||||
| Direct operating expenses (1) | 126 | 132 | 139 | 136 | |||||||||||||||||||
| Operating income | 160 | 192 | 159 | 69 | |||||||||||||||||||
| Net income | 102 | 128 | 104 | 28 | |||||||||||||||||||
| Net income (loss) attributable to noncontrolling interest | 1 | 12 | (15) | (16) | |||||||||||||||||||
| Net income attributable to CVR Energy stockholders | $ | 101 | $ | 116 | $ | 119 | $ | 44 | |||||||||||||||
| Basic and diluted earnings per share | $ | 1.00 | $ | 1.16 | $ | 1.18 | $ | 0.44 | |||||||||||||||
| Dividends declared per share | $ | 0.75 | $ | 0.75 | $ | 0.75 | $ | 0.80 | |||||||||||||||
| Weighted-average common shares outstanding - basic and diluted | 100.5 | 100.5 | 100.5 | 100.5 | |||||||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||||||||
| Quarter | |||||||||||||||||||||||
| (in millions) | First | Second | Third | Fourth | |||||||||||||||||||
| Net sales | $ | 1,536 | $ | 1,915 | $ | 1,935 | $ | 1,738 | |||||||||||||||
| Cost of materials and other (1) | 1,179 | 1,560 | 1,556 | 1,388 | |||||||||||||||||||
| Direct operating expenses (1) | 130 | 140 | 120 | 127 | |||||||||||||||||||
| Operating income | 136 | 108 | 164 | 124 | |||||||||||||||||||
| Net income | 93 | 70 | 108 | 95 | |||||||||||||||||||
| Net income attributable to noncontrolling interest | 33 | 24 | 28 | 22 | |||||||||||||||||||
| Net income attributable to CVR Energy stockholders | $ | 60 | $ | 46 | $ | 80 | $ | 73 | |||||||||||||||
| Basic and diluted earnings per share | $ | 0.69 | $ | 0.53 | $ | 0.85 | $ | 0.73 | |||||||||||||||
| Dividends declared per share | $ | 0.50 | $ | 0.50 | $ | 0.75 | $ | 0.75 | |||||||||||||||
| Weighted-average common shares outstanding - basic and diluted | 86.8 | 86.8 | 95.8 | 100.5 | |||||||||||||||||||
(1)Excludes depreciation and amortization expenses.
December 31, 2019 | 102
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, 2019, the Company has evaluated, under the direction of the Chief Executive Officer, Chief Financial Officer and Chief Accounting 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, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports filed or submitted under the Exchange Act is accurately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, as appropriate, to allow accurate and timely decisions regarding required disclosure.
Management’s Report on Internal Control Over Financial Reporting. The Company’s 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, we 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, the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer have concluded that internal control over financial reporting was effective as of December 31, 2019. The Company’s independent registered public accounting firm, that audited the consolidated financial statements included herein under Item 8, has issued a report on the effectiveness of the Company’s 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 the Company’s internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended December 31, 2019 that has materially affected or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
None.
December 31, 2019 | 103
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by Items 401, 405, 406, and 407(c)(3), (d)(4), and (d)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for our 2020 annual meeting of stockholders.
Item 11. Executive Compensation
The information required by Items 402 and 407(e)(4) and (e)(5) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for our 2020 annual meeting of stockholders.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The equity compensation plan information required by Items 201(d) and the information required by Item 403 of Regulation S-K in response to this item will be set forth in our definitive proxy statement for our 2020 annual meeting of stockholders.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by Items 404 and 407(a) of Regulation S-K in response to this item will be set forth in our definitive proxy statement for our 2020 annual meeting of stockholders.
Item 14. Principal Accounting Fees and Services
The information required by Items 9(e) of Schedule 14A in response to this item will be set forth in our definitive proxy statement for our 2020 annual meeting of stockholders.
December 31, 2019 | 104
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements - See Part II, Item 8 of this Annual Report on Form 10-K.
(a)(2) Financial Statement Schedules - All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission (the “SEC”) are not required under the related instructions or are inapplicable and therefore have been omitted.
(a)(3) Exhibits
| Exhibit Number | Exhibit Description | ||||
| 2.1** | |||||
| 3.1** | |||||
| 3.2** | |||||
| 4.1* | |||||
| 4.2** | |||||
| 4.3** | |||||
| 4.4** | |||||
| 4.5** | |||||
| 4.6** | |||||
| 4.7** | |||||
| 4.8** | |||||
| 4.9** | |||||
| 4.10** | |||||
December 31, 2019 | 105
| 4.11** | |||||
| 10.1** | |||||
| 10.1.1** | |||||
| 10.1.2* | |||||
| 10.2** | |||||
| 10.3** | |||||
| 10.4* | |||||
| 10.5* | |||||
| 10.6** | |||||
| 10.7** | |||||
| 10.7.1** | |||||
| 10.8**+ | |||||
| 10.9**+ | |||||
| 10.10** | |||||
December 31, 2019 | 106
| 10.11** | |||||
| 10.12** | |||||
| 10.12.1** | |||||
| 10.12.2** | |||||
| 10.13** | |||||
| 10.13.1** | |||||
| 10.14** | |||||
| 10.15** | |||||
| 10.16** | |||||
| 10.17** | |||||
| 10.18** | |||||
| 10.19** | |||||
| 10.19.1** | |||||
| 10.20** | |||||
| 10.21** | |||||
| 10.22** | |||||
December 31, 2019 | 107
| 10.23**+ | |||||
| 10.24**+ | |||||
| 10.25**+ | |||||
| 10.25.1**+ | |||||
| 10.26**+ | |||||
| 10.27**+ | |||||
| 10.28**+ | |||||
| 10.29**+ | |||||
| 10.30**+ | |||||
| 10.30.1**+ | |||||
| 10.30.2*+ | |||||
| 10.30.3*+ | |||||
| 10.31**+ | |||||
| 10.31.1**+ | |||||
| 10.32** | |||||
| 10.33** | |||||
| 10.34** | |||||
| 10.35** | |||||
| 10.36** | |||||
December 31, 2019 | 108
| 10.37** | |||||
| 10.38*+ | |||||
| 10.39*+ | |||||
| 10.40*+ | |||||
| 21.1* | |||||
| 23.1* | |||||
| 31.1* | |||||
| 31.2* | |||||
| 31.3* | |||||
| 32.1† | |||||
| 101* | The following financial information for CVR Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2019, formatted in XBRL (“Extensible Business Reporting Language”) includes: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Changes in Equity, (v) Consolidated Statements of Cash Flows, and (vi) the Notes to Consolidated Financial Statements, tagged in detail. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | ||||
| 104* | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | ||||
* Filed herewith.
** Previously filed.
† Furnished herewith.
+ Denotes management contract or compensatory plan or arrangement.
PLEASE NOTE: Pursuant to the rules and regulations of the SEC, we may file or incorporate by reference agreements as exhibits to the reports that 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 Company 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 Company’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 Company or its business or operations on the date hereof.
Item 16. Form 10-K Summary
None.
December 31, 2019 | 109
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 Energy, Inc. | |||||||||||
| By: | /s/ DAVID L. LAMP | ||||||||||
| David L. Lamp | |||||||||||
| President and Chief Executive Officer | |||||||||||
Date: February 20, 2020
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report had been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated.
| Signature | Title | Date | ||||||
| /s/ DAVID L. LAMP | President, Chief Executive Officer, and Director (Principal Executive Officer) | February 20, 2020 | ||||||
| David L. Lamp | ||||||||
| /s/ TRACY D. JACKSON | Executive Vice President, Chief Financial Officer (Principal Financial Officer) | February 20, 2020 | ||||||
| Tracy D. Jackson | ||||||||
| /s/ MATTHEW W. BLEY | Chief Accounting Officer and Corporate Controller (Principal Accounting Officer) | February 20, 2020 | ||||||
| Matthew W. Bley | ||||||||
| /s/ SUNGHWAN CHO | Chairman of the Board of Directors | February 20, 2020 | ||||||
| SungHwan Cho | ||||||||
| /s/ BOB G. ALEXANDER | Director | February 20, 2020 | ||||||
| Bob G. Alexander | ||||||||
| /s/ JONATHAN FRATES | Director | February 20, 2020 | ||||||
| Jonathan Frates | ||||||||
| /s/ STEPHEN MONGILLO | Director | February 20, 2020 | ||||||
| Stephen Mongillo | ||||||||
| /s/ PATRICIA AGNELLO | Director | February 20, 2020 | ||||||
| Patricia Agnello | ||||||||
| /s/ HUNTER C. GARY | Director | February 20, 2020 | ||||||
| Hunter C. Gary | ||||||||
| /s/ JAMES M. STROCK | Director | February 20, 2020 | ||||||
| James M. Strock | ||||||||