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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
______________________________________
FORM 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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: 001-35397
______________________________________
RENEWABLE ENERGY GROUP, INC.
(Exact name of registrant as specified in its charter)
Delaware
26-4785427
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
 
 
416 South Bell Avenue, Ames, Iowa
50010
(Address of principal executive offices)
(Zip Code)
Registrant’s telephone number, including area code: (515) 239-8000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class:
Name of each exchange on which registered:
Common Stock, par value $.0001 per share
NASDAQ Global Market
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of class)
______________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x
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  x
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  x    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 and post such files).    Yes  x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨ 
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” and “smaller reporting company”, and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨
Accelerated filer
x
Non-accelerated filer
¨ 
 
 
 
 
 
 
Smaller reporting company
¨ 
Emerging growth company
¨ 
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x
As of June 30, 2018, the aggregate market value of Common Stock held by non-affiliates was $556,864,879.
As of February 28, 2019, 37,355,193 shares of Common Stock of the registrant were issued and outstanding.
______________________________________
Documents Incorporated By Reference
All or a portion of Items 10 through 14 in Part III of this Form 10-K are incorporated by reference to the Registrant’s definitive proxy statement on Schedule 14A, which will be filed within 120 days after the close of the fiscal year covered by this report on Form 10-K, or if the Registrant’s Schedule 14A is not filed within such period, will be included in an amendment to this Report on Form 10-K which will be filed within such 120 day period.




TABLE OF CONTENTS
 
 
Page
PART I
 
 
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
 
 
PART II
 
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
 
 
PART III
 
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
 
 
PART IV
 
ITEM 15.
ITEM 16.




PART I
Cautionary Statement Regarding Forward-Looking Information
This annual report on Form 10-K contains, in addition to historical information, certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical facts contained in this report, including statements regarding our future results of operations and financial position, strategy and plans, and our expectations for future operations, are forward-looking statements. The words “believe,” “may,” “will,” “would,” “might,” “could,” “estimate,” “continue,” “anticipate,” “design,” “intend,” “plan,” “seek,” “potential,” “expect” and similar expressions are intended to identify forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and trends that we believe may affect our financial condition, results of operations, strategy, short-term and long-term business operations and objectives, and financial needs. Forward-looking statements include, but are not limited to, statements about:
our financial performance, including revenues, cost of revenues and operating expenses;
government programs, policymaking and requirements relating to renewable fuels;
the availability, future price and volatility of feedstocks;
the future price and volatility of petroleum;
our liquidity and working capital requirements;
anticipated trends and challenges in our business and competition in the markets in which we operate;
our ability to successfully implement our acquisition strategy and integration strategy;
our plan to sell the REG Life Sciences business;
our ability to protect proprietary technology and trade secrets;
our risk management activities;
product performance, in cold weather or otherwise;
seasonal fluctuations in our business;
our current products as well as products we are developing;
critical accounting policies and estimates, the impact or anticipated impact of recent accounting pronouncements, guidance or changes in accounting principles and future recognition of impairments for the fair value of assets, including goodwill, financial instruments, intangible assets and other assets acquired; and
assumptions underlying or relating to any of the foregoing.
These statements reflect current views with respect to future events and are based on assumptions and subject to risks and uncertainties. We note that a variety of factors, including but not limited to those Risk Factors discussed in Item 1A, could cause actual results and experience to differ materially from the anticipated results or expectations expressed in our forward-looking statements. Given these uncertainties, you should not place undue reliance on these forward-looking statements.
Forward-looking statements contained in this report present management’s views only as of the date of this report. We undertake no obligation to publicly update forward-looking statements, whether as a result of new information, future events or otherwise. You are advised, however, to consult any further disclosures we make on related subjects in our 10-Q and 8-K reports filed with the Securities and Exchange Commission after the date hereof.

1



ITEM 1.
Business
General
We focus on providing cleaner, lower carbon transportation fuels. We are North America's largest producer of advanced biofuels. We utilize a nationwide production, distribution and logistics system as part of an integrated value chain model designed to convert natural fats, oils and greases into advanced biofuels. During 2018, we sold 649 million total gallons of fuel (including fuel purchased from third parties for resale) and generated revenues of $2.4 billion. We believe our fully integrated approach, which includes acquiring feedstock, managing biorefinery facility construction and upgrades, operating biorefineries, and distributing fuel through a network of terminals, positions us to serve the market for cleaner transportation fuels. In May 2018, we launched our latest innovation in diesel fuel, REG Ultra CleanTM Diesel. REG Ultra CleanTM Diesel is among the lowest emission diesel fuels on the market today.
Plant Network
We own and operate a network of 14 biorefineries. Twelve biorefineries are located in the United States and two in Germany. Twelve biorefineries produce traditional biodiesel, one produces renewable diesel (“RD”), and one is a fermentation facility. Our thirteen biomass-based diesel production facilities have an aggregate nameplate production capacity of 520 million gallons per year ("mmgy").
We own and operate the following facilities in North America:
Property
 
Nameplate1
Production
Capacity (mmgy)
 
Effective Capacity 2 (mmgy)
 
REG
Operations
Commenced
 
Feedstock Capability
 
 
 
 
 
 
 
 
 
Ralston, Iowa
 
30
 
39.9
 
2002
 
Refined Oils and Fats
Albert Lea, Minnesota
 
30
 
45.6
 
2005
 
Crude, High FFA and Refined Oils and Fats
Newton, Iowa
 
30
 
34.7
 
2007
 
Crude, High FFA and Refined
Oils and Fats
Seabrook, Texas
 
35
 
47.8
 
2008
 
Refined Oils and Fats
Danville, Illinois
 
45
 
46.5
 
2009
 
Crude, High FFA and Refined
Oils and Fats
Seneca, Illinois
 
60
 
73.4
 
2010
 
Crude, High FFA and Refined
Oils and Fats
New Boston, Texas
 
15
 
17.3
 
2013
 
Crude, High FFA and Refined
Oils and Fats
Mason City, Iowa
 
30
 
38.5
 
2013
 
Crude, High FFA and Refined
Oils and Fats
Geismar, Louisiana
 
75
 
90.3
 
2014
 
Crude, High FFA and Refined
Oils and Fats
Okeechobee, Florida 3
 
n/a
 
n/a
 
2014
 
N/A
Grays Harbor, Washington
 
100
 
106.7
 
2015
 
Refined Oils and Fats
Madison, Wisconsin
 
20
 
27.2
 
2016
 
Crude, High FFA and Refined
Oils and Fats

1 
The nameplate capacity listed above is based on original plant design.
2 
Effective capacity represents the maximum average throughput that satisfies certain defined technical constraints.
3 
Okeechobee is a demo-scale fermentation facility associated with our Life Sciences business.


2



Our production network in Europe consists of the following facilities:
Property
 
Nameplate
Production
Capacity1 
 
Effective Capacity 2 
 
REG
Operations
Commenced
 
Feedstock Capability
Emden, Germany
 
27
 
29.7
 
2016
 
Crude, High FFA and Refined
Oils and Fats
Oeding, Germany
 
23
 
23.9
 
2016
 
Crude, High FFA and Refined
Oils and Fats

1 
The nameplate capacity listed above is based on the output of the original plant design. In Germany, nameplate capacity can be based on input, which is 30 mmgy for Emden and 26 mmgy for Oeding or 185,000 metric tons for these two locations.
2 
Effective capacity represents the maximum average throughput that satisfies certain defined technical constraints.

We maintain a testing laboratory at our corporate headquarters in Ames, Iowa, for testing various feedstocks for conversion into biomass-based diesel and various new manufacturing processes for the production of biomass-based diesel. We also have a regional office in Tulsa, Oklahoma, focused on maintaining and developing advanced biofuel technologies and renewable chemicals.

We produce renewable diesel at our Geismar, Louisiana facility. Renewable diesel generally carries a premium price compared to biodiesel as a result of a variety of factors including the ability to blend it with petroleum diesel seamlessly, better cold weather performance, and because it generates more RINs on a per gallon basis. We are evaluating long-term opportunities to further our ability to leverage our renewable diesel technology and expand renewable diesel production to meet the growing demand for cleaner transportation fuels. For example, in October 2018, we announced a collaboration project with Phillips 66 on the possible construction of a large-scale renewable diesel plant in Washington state. The plant would utilize our propriety BioSynfining® technology for the production of renewable diesel fuel. We have not reached a definitive agreement with Phillips 66 with respect to this potential joint development project and there is no assurance that an agreement will be reached. We are also evaluating a large-scale expansion of our renewable diesel facility in Geismar, Louisiana.
Our Feedstocks and Other Inputs
We are a lower-cost, lower carbon biomass-based diesel producer. We primarily produce our biomass-based diesel from a wide variety of lower-cost, lower carbon feedstocks, including inedible corn oil, used cooking oil and inedible animal fat. We also produce biomass-based diesel from virgin vegetable oils, such as soybean oil or canola oil, which tend to be higher in price. We believe our ability to process a wide variety of feedstocks in most of our facilities provides us with a cost advantage over many biomass-based diesel producers, particularly those that rely primarily on higher cost virgin vegetable oils.
We have the ability to adjust our processing in most of our facilities to accommodate different feedstocks and feedstock mixes. Our ability to use a wide range of feedstocks gives us a feedstock cost advantage over many other producers because we have the flexibility to respond to changes in feedstock pricing. In 2018, approximately 77% of our total feedstock usage was lower-cost inedible corn oil, used cooking oil or rendered animal fat feedstock. The remaining 23% consisted of refined vegetable oils, such as soybean oil or canola oil.
We procure our feedstocks from numerous vendors in quantities ranging from truckload to railcar to water vessel to pipeline. There is no established futures market for the lower-cost feedstocks that we utilize. Inedible corn oil is typically purchased in forward positions of one to three months, and occasionally longer, on fixed priced contracts. We generally purchase used cooking oil and rendered animal fats on one to four week forward positions using fixed pricing or an indexed price compared to a published index such as USDA reports or recognized industry price reports such as The Jacobsen or Informa. Soybean and canola oils can be purchased on a spot or forward contract basis from a number of suppliers and pricing for these vegetable oils is compared to the broadly traded Soybean Oil Index of the Chicago Mercantile Exchange.
From time to time, we work with developers of next generation feedstocks, such as algae and camelina, to assist them in bringing these new feedstocks to market. We have converted several of these feedstocks, as well as other second generation feedstocks, into high quality biomass-based diesel in our laboratory and production facilities. We believe we are well positioned to incorporate many new feedstocks into our production process as they become commercially available.
We procure methanol and chemical catalysts used in our production process such as sodium methylate and hydrochloric acid, under fixed-price contracts and formula-indexed contracts based upon competitive bidding. These procurement contracts typically last from three months to one year. The price of methanol is indexed to the monthly reported published price.

3



Distribution
We have established a national distribution system to supply biomass-based diesel throughout the United States. Each of our biomass-based diesel facilities is equipped with an on-site rail loading system, a truck loading system, or both. Our Seneca biorefinery near the Illinois River has direct barge access for supplying customers using the inland waterways system. Our Houston biorefinery has barge and deep-water ship loading capability. Our Grays Harbor biorefinery has deep-water capability for PANAMAX class vessels. We also manage some customers’ biomass-based diesel storage tanks and replenishment process. Our distribution performance for 2018 is depicted below.

a2018movementcontrol.jpg

As of December 31, 2018, we leased over 1,100 railcars for transportation and leased biomass-based diesel storage tanks in 46 terminals. In general, the terminals where we lease our biomass-based diesel storage tanks are petroleum fuel terminals so that fuel distributors and other biomass-based diesel customers can create a biomass-based diesel blend at the terminal before further distribution. Terminal contracts typically have one- to three-year terms and are generally renewable subject to certain terms and conditions. During 2018, REG sold products in 49 states in the U.S., six Canadian Provinces, and 19 other countries around the world.

In addition to biomass-based diesel, we also sell petroleum-based heating oil and diesel fuel, which enables us to offer additional biofuel blends to a broader customer base.  We sell heating oil and ultra-low sulfur diesel ("ULSD") at terminals throughout the northeastern U.S.  We sell additional biofuel blends at terminal locations in the Midwest, West Coast and Texas. We continue to look for terminal expansion opportunities across North America.
Government Programs Favoring Biomass-Based Diesel Production and Use
The biomass-based diesel industry benefits from numerous federal and state government programs.

4



Renewable Fuel Standard
Biomass-based diesel has historically been more expensive to produce than petroleum-based diesel. The biomass-based diesel industry's growth has largely been the result of federal and state programs that require or incentivize production and use of biomass-based diesel, which allows biomass-based diesel to be priced competitively with petroleum-based diesel.
The Renewable Fuel Standard’s ("RFS2") biomass-based diesel requirement became effective in 2010, requiring for the first time that a certain percentage of the diesel fuel consumed in the United States be made from renewable sources. The biomass-based diesel requirement can be satisfied by two primary fuels, biodiesel and renewable diesel. Required volumes under the RFS2 program, referred to as the renewable volume obligation ("RVO"), are determined by the United States Environmental Protection Agency, or EPA. The final RVO targets for the biomass-based diesel and advanced biofuels volumes for the years 2015 to 2020 as set by the EPA are as follows:
 
2015
2016
2017
2018
2019
2020
Biomass-based diesel
1.73 billion gallons
1.90 billion gallons
2.00 billion gallons
2.10 billion gallons
2.10 billion gallons
2.43 billion gallons
Total Advanced biofuels
2.88 billion RINs*
3.61 billion RINs*
4.28 billion RINs*
4.29 billion RINs*
4.92 billion RINs*
N/A
(* ethanol equivalent gallons)
The biomass-based diesel requirement is one of four separate renewable fuel requirements under RFS2. The RFS2 requirements are based on two primary categories and two subcategories. The two primary categories are conventional renewable fuel, which is primarily satisfied by corn ethanol, and advanced biofuel, which is defined as a biofuel that reduces lifecycle greenhouse gas emissions by at least 50% compared to the petroleum-based fuel the biofuel is replacing. The advanced biofuel category has two subcategories, cellulosic biofuel, to be satisfied by newly developed cellulosic biofuels, such as ethanol made from woody biomass, and biomass-based diesel, which is satisfied by biodiesel and renewable diesel. RFS2’s total advanced biofuel requirement is larger than the combined cellulosic fuel and biomass-based diesel requirements, thus requiring the use of additional volumes of advanced biofuels.
The RFS2 requirement for advanced biofuels can be satisfied by any advanced biofuel, including biodiesel, renewable diesel, biogas used in transportation, biobutanol, cellulosic ethanol or sugarcane-based ethanol, so long as it meets the 50% greenhouse gas reduction requirement.
The advanced biofuel RVO is expressed in terms of ethanol equivalent volumes, or EEV, which is based on the fuel’s renewable energy content compared to ethanol. Biodiesel has an EEV of 1.5 and renewable diesel typically has an EEV of 1.7, compared to 1.0 for sugarcane-based ethanol. Accordingly, it requires less biomass-based diesel than sugarcane-based ethanol to meet the required volumes as each gallon of biomass-based diesel counts as more gallons for purposes of fulfilling the advanced biofuel RVO, providing an incentive for refiners and importers to purchase biomass-based diesel to meet their advanced biofuel RVO.
The RFS2 volume requirements apply to petroleum refiners and petroleum fuel importers in the 48 contiguous states and Hawaii, who are defined as “Obligated Parties” in the RFS2 regulations. Obligated Parties are required to incorporate into their petroleum-based fuel a certain percentage of renewable fuel or purchase credits in the form of renewable identification numbers ("RINs") from those who do. An Obligated Party’s RVO is based on the volume of petroleum-based fuel they produce or import. The largest United States petroleum refining companies, such as Valero, Phillips 66, ExxonMobil, British Petroleum, Chevron, Shell, Marathon and Citgo, represent the majority of the total RVO, with the remainder made up of smaller refiners and importers.
Renewable Identification Numbers
The EPA created the RIN system to track renewable fuel production and compliance with the renewable fuel standard. EPA registered producers of renewable fuel may generate RINs for each gallon of renewable fuel they produce. In the case of biomass-based diesel, generally 1.5 to 1.7 biomass-based diesel RINs may be generated for each gallon of biomass-based diesel produced, based upon the fuel's renewable energy content. Renewable fuel, including biomass-based diesel, can then be sold with associated RINs attached. RINs may also be separated from the gallons of renewable fuel they represent and once separated they may be sold as a separate commodity. RINs are ultimately used by Obligated Parties to demonstrate compliance with RFS2. Obligated Parties must obtain and retire the required number of RINs to satisfy their RVO during a particular compliance period. An Obligated Party can obtain RINs by buying renewable fuels with RINs attached, buying RINs that have been separated, or producing renewable fuels themselves. All RIN activity under RFS2 must be entered into the EPA’s moderated transaction

5



system, which tracks RIN generation, transfer and retirement. RINs are retired when used for compliance with the RFS2 requirements.
The value of RINs is significant to the price of biomass-based diesel. In 2018, RIN prices as a percentage contribution to the daily average B100 spot price, as reported by the Oil Pricing Information System, or OPIS, fluctuated significantly throughout the year and ranged from a low of $0.47 per gallon, or 16% of the average B100 spot price per gallon, in October to a high of $1.36 per gallon, or 43% of the average spot price, in February.
Biodiesel Tax Credit
The federal biodiesel mixture excise tax credit, or BTC, is not currently in effect, but has historically provided a $1.00 refundable tax credit per gallon to the first blender of biomass-based diesel with petroleum-based diesel fuel. The BTC can then be credited against such biodiesel federal excise tax liability or the blender can obtain a cash refund from the United States Treasury for the value of the credit. The BTC was first implemented on January 1, 2005, although on several occasions it has been allowed to lapse and then has been reinstated, in some cases on a retroactive basis, as described in the following table:
a2018btctimelinea02.jpg
The BTC is an incentive shared across the biofuel production and distribution chain through routine, daily trading and negotiation. In February 2018, the BTC was retroactively reinstated for 2017, but was not reinstated for 2018. It is uncertain whether the BTC will be reinstated for 2018 or any later years. 
California Low Carbon Fuel Standard Credits
The California Low Carbon Fuel Standard, or LCFS, regulation is a rule designed to reduce greenhouse gas emissions associated with transportation fuels used in California. The regulation quantifies lifecycle greenhouse gas emissions by assigning a “carbon intensity” ("CI") score to each transportation fuel based on that fuel’s lifecycle assessment. Each petroleum fuel provider (generally the fuel’s producer or importer, or “regulated party”) is required to ensure that the overall CI score for its fuel pool meets the annual carbon intensity target for a given year. A regulated party’s fuel pool can include gasoline, diesel, and their blendstocks and substitutes.
We obtain CI credits when we sell qualified biomass-based diesel into California. During 2018, California CI credits ranged from $111.00 per metric ton to $200.50 per metric ton, as reported by OPIS.
Other Government Programs
According to the U.S. Department of Energy, more than 40 states have implemented various programs that encourage the use of biomass-based diesel through blending requirements as well as various tax incentives. The chart below summarizes some of the most significant programs.

6



Government
 
Program description
Illinois
 
Illinois offers an exemption from the generally applicable 6.25% sales tax on fuel for biomass-based diesel blends that incentivizes blending at 11% biomass-based diesel, or B11, through December 31, 2023. Illinois’ program has made that state one of the largest biomass-based diesel markets in the country
Iowa
 
Iowa has a retailer’s incentive for blended fuel which has been modified over time. For 2018 through 2024, retailers earn $0.035 per gallon of B5 - B10 and $0.055 per gallons for B11 and above. Iowa also has a biomass-based diesel production incentive that provides $0.02 per gallon of production capped after the first 25 million gallons per production plant. Iowa recently enacted an increase in its excise tax on fuel, which is three cents per gallon less for B11 or higher blends than the diesel fuel tax.
Texas
 
The biomass-based diesel portion of biomass-based diesel blends are exempt from Texas state excise tax, which results in a $0.20 per gallon incentive for B100.
Minnesota
 
Minnesota law requires a B5 biodiesel blend except during the summer months when a B20 blend is required.
Pennsylvania and Washington
 
These states have all adopted legislation requiring biomass-based diesel blends beginning at B2 with incremental increases, provided certain feedstock or production minimums are met. In addition, Washington State is in the process of developing legislation on a low carbon fuel programs.
Oregon
 
The Oregon Clean Fuel Program requires a 10% reduction of the average carbon intensity of Oregon’s transportation fuels from 2015 levels by 2025. The baseline year for the program is 2015 and represents 10 percent ethanol blended with gasoline and 5 percent biodiesel blended with diesel. The Oregon Renewable Fuels Standard requires all gasoline sold in the state to be blended with 10 percent ethanol (E10). In addition, all diesel fuel sold in the state must be blended with at least 5 percent biodiesel (B5).
City of New York, Connecticut and Vermont
 
In October 2016, the City of New York adopted legislation requiring biomass-based diesel blends at a 5% rate for heating oil starting on October 1, 2017 and the blend level then moves to 10% in 2025, 15% in 2030 and 20% in 2034. Several northeast states, including Connecticut and Vermont, have adopted legislation requiring biomass-based diesel blends in home heating oil.
Canada
 
While a number of provinces in Canada have biofuel programs (British Columbia has an LCFS, Alberta has a usage requirement, and Ontario has a usage requirement), the federal government is currently engaged in the rulemaking process on a nationwide Clean Fuel Standard, which may incorporate a number of carbon reducing policies.
Although we believe that other government requirements for the use of biofuels increase demand for our biomass-based diesel within such regions, they may not increase overall demand in excess of RFS2 requirements. Rather, existing demand for our biofuel from Obligated Parties in connection with federal requirements may shift to regions that have use requirements or tax incentive programs.
RED Program
The Renewable Energy Directive ("RED") in the European Union ("EU") establishes a 20% target by 2020 for the use of renewable energy in the transport sector in EU member states. Given the existing limited market presence of alternative fuels or electromobility, the majority of the target is currently being achieved through biofuels.  EU member states produce yearly renewable energy action plans indicating their yearly national obligations for the use of renewable energy in the transport sector. These national obligations progressively increase every year until achieving the 10% target in 2020. Biofuels produced from certain types of feedstocks, such as used cooking oil, benefit from an extra incentive as these feedstocks count double towards the 20% target and towards the national obligations. In 2018, the EU institutions adopted the so-called RED II, which is valid during the period from 2021 to 2030 and provides additional incentives for biofuel produced from waste feedstocks and even opens new outlets such as marine fuels.
Competition
We face competition from producers and suppliers of petroleum-based diesel fuel, other biomass-based diesel producers, marketers, traders and distributors. The size of the biomass-based diesel industry is small compared to the size of the petroleum-based diesel fuel industry and large petroleum companies have greater resources than we do. Our principal competitive differentiators are biomass-based diesel and RIN quality, supply reliability and price. In the United States and Canadian biomass-based diesel markets, we compete with independent biomass-based diesel producers as well as large, multi-product companies that have greater resources than we do. Archer Daniels Midland Company, Cargill Incorporated, Louis Dreyfus Commodities Group and Ag Processing Inc. are major international agribusiness corporations and biodiesel producers with the financial, feedstock sourcing and marketing resources to be formidable competitors in the biodiesel industry. These agribusiness

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competitors tend to make biodiesel from higher cost virgin vegetable oils such as soybean or canola oil, which they produce as part of their integrated agribusinesses. We are also in competition with several large and well capitalized producers of renewable diesel. Neste Corporation has approximately 882 million gallons of renewable diesel production capacity in Asia and Europe, a significant portion of which is imported into the United States. It has recently announced its decision to expand its renewable products production capacity in Singapore. Diamond Green Diesel, LLC, a joint venture between Valero Energy Corporation and Darling Ingredients Inc., operates a 275 mmgy capacity renewable diesel facility and has announced plans to expand capacity to 675 mmgy by 2021. We also face the prospect that petroleum refiners will be increasingly competitive with us, either by converting oil refineries to produce renewable diesel or by co-processing renewable feedstock with crude oil. Several smaller petroleum refiners in the United States have effected conversions of their facilities from crude oil to renewables in the past year and some of the largest refiners have reportedly started co-processing renewable feedstocks or have announced plans to do so. If refinery conversions accelerate or if co-processing expands significantly, the competition we face could increase significantly. We also face competition in the biomass-based diesel RIN compliance market from producers of renewable diesel and in the advanced biofuel RIN compliance market from producers of other advanced biofuels, such as Brazilian sugarcane ethanol producers and producers of biogas used in transportation. Competition from imported biodiesel changed significantly in 2018, when the International Trade Commission and U.S. Department of Commerce imposed countervailing duties against unfairly subsidized biodiesel exports to the U.S. from Argentina and Indonesia.  According to the U.S. Energy Information Administration ("EIA") data, biodiesel imports from Argentina decreased from 437 million gallons in 2016 to 280 million gallons in 2017 and no imports entered the U.S. since August 2017.  Biodiesel imports from Indonesia totaled 107 million gallons in 2016 and no imports have been reported since December 2016. However, renewable diesel imports from Singapore to the U.S have maintained a steady rate . Imports from Singapore totaled 223 million gallons in 2016, 189 million gallons in 2017, and is on pace for volume in 2018 similar to 2017 based on 11 months of data.
In our marketing and distribution operations, besides the integrated producers, we are also faced with competition from biomass-based diesel traders such as Lincoln Energy, NGL, BP, Shell, Vitol and others. The integrated producers and traders at times may have advantages because of logistics, feedstock accessibility and price, geographical location to customers, blending infrastructure, financial resources, and risk appetite for positions and/ or taking greater amounts of risk on a return of the blenders tax credit. These same trading companies may have greater financial resources than we do and are able to take significant biomass-based diesel positions in the marketplace. These competitors are often customers and/or suppliers of ours as well.
Risk Management
The prices for feedstocks and biomass-based diesel, including the value associated with government incentives, can be volatile and are not always closely correlated. Lower-cost feedstocks are particularly difficult to risk manage given that such feedstocks are not traded in any public futures market. To manage feedstock and biomass-based diesel price risks, we utilize forward contracting, hedging and other risk management strategies, including the use of futures, swaps, options and over-the-counter products.
In establishing our risk management strategies, we draw from our own in-house risk management expertise and consult with industry experts. We utilize research conducted by outside firms to provide additional market information and risk management strategies. We believe combining these sources of knowledge, experience and expertise expands our view of the fluctuating commodity markets for raw materials and energy to improve our risk management strategies.
Seasonality
Our operating results are influenced by seasonal fluctuations in the price of and demand for biodiesel. Seasonal fluctuations may be based on both the weather and the status of both the BTC and RVO.
Demand may be higher in the quarters leading up to the expiration of the BTC as customers seek to purchase biomass-based diesel when they can benefit from the agreed upon value sharing of the BTC with producers. This higher demand prompted by an expiring BTC has often resulted in reduced demand for biodiesel in the following quarter. In addition, RIN prices may also be subject to seasonal fluctuations. The RIN is dated for the calendar year in which it is generated. Since 20% of an Obligated Party's annual RVO can be satisfied by prior year RINs, most RINs must come from biofuel produced or imported during the RVO year. As a result, RIN prices can be expected to increase as the calendar year progresses if the RIN market is undersupplied compared to that year's RVO and decrease if it is oversupplied.
Seasonal fluctuation in our business also occurs in the colder months when historically there has been reduced demand for biodiesel in northern and eastern United States markets, which are some of the primary markets in which we operate. Biodiesel typically has a higher cloud point than petroleum-based diesel or renewable diesel. The cloud point is the temperature below which a fuel exhibits a noticeable cloudiness and eventually gels, leading to fuel handling and performance problems for

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customers and suppliers. Reduced demand in the winter for our higher cloud point biodiesel may result in excess supply of such higher cloud point biodiesel and lower prices for such higher cloud point biodiesel. To mitigate some of these seasonal fluctuations in demand, we have upgraded our Newton and Danville biorefineries to produce distilled biodiesel which improves cold-weather performance.
History
Our predecessor, REG Biofuels, LLC, formerly named REG Biofuels Inc., which was formerly named Renewable Energy Group, Inc., was formed under the laws of the State of Delaware in August 2006 upon acquiring the assets and operations of the biodiesel division of West Central Cooperative, or West Central, and two of West Central’s affiliated companies, InterWest, L.C. and REG, LLC. West Central is now known as Landus Cooperative.
Employees
As of December 31, 2018, we had 762 full-time employees in the U.S. and 88 international employees. None of our U.S. employees are represented by a labor organization or under any collective bargaining agreements. We consider our relationship with our employees to be good.
Intellectual Property
We own a significant number of U.S. and international patents and expect to file additional patent applications as we continue to pursue technological innovations. We have also developed trade secrets, and have licensed intellectual property related to our biomass-based diesel and industrial biotechnology businesses. We have developed a patented technology that uses microbes to convert sugars to biodiesel in a one-step fermentation process similar to ethanol manufacturing. Some of the patents issued to us do not expire until 2034 and additional patent applications in prosecution if issued will extend beyond 2034.
Customer concentration
Our sales to one customer, Pilot Travel Centers LLC, or Pilot, were $219.2 million, $182.2 million and $144.8 million, representing approximately 9%, 8% and 8% of our total revenues for each of 2018, 2017, and 2016, respectively. Our revenues from Pilot generally do not directly include the RINs associated with the gallons of biomass-based diesel sold. The value of those RINs represented approximately an additional 2%, 9% and 9% of our total sales in 2018, 2017 and 2016, respectively, based on the OPIS average RIN price for the year.
Executive Officers of the Registrant
Cynthia J. Warner, age 60, has served as our President and Chief Executive Officer since January 2019. Ms. Warner was Executive Vice President, Operations for Andeavor (formerly known as Tesoro Corporation) from August 2016 until Andeavor's acquisition by Marathon Petroleum Corporation in October 2018. Prior to that, Ms. Warner served as Andeavor's Executive Vice President, Strategy and Business Development, since October 2014. From 2012 to August 2014, Ms. Warner was Chairman and Chief Executive Officer of Sapphire Energy, Inc. and she continued to serve as Chairman through February 2015. From 2009 to 2011, Ms. Warner was President of Sapphire Energy. From 2007 to 2009, she was Group Vice President, Global Refining, at BP plc. Ms. Warner has served as a member of the Board of Directors of IDEX Corporation (NYSE: IEX) since February 2013. She is also a member of the National Petroleum Council. Ms. Warner has a Bachelor of Engineering degree in Chemical Engineering from Vanderbilt University and an MBA from Illinois Institute of Technology.
Chad Stone, age 49, has served as our Chief Financial Officer since August 2009. Prior to joining REG, from October 2007 to May 2009, he was a Director at Protiviti Inc., a global business consulting and internal audit firm. From August 1997 to September 2007, Mr. Stone served as Director with PricewaterhouseCoopers and he worked at Arthur Andersen from July 1992 to August 1997, departing as a manager. Mr. Stone was elected to the governing Board of the National Biodiesel Board in 2015, and has served as Vice-Chairman since November 2018, previously having served as Secretary from November 2016 to November 2018.  Mr. Stone served on the Executive Board of the Iowa Biodiesel Board from September 2010 to September 2016, serving as Vice-Chairman from 2014-2015. Since October 2015, Mr. Stone has served on the University of Iowa School of Management's Advisory Committee. Mr. Stone has over 20 years of experience in leading financial reporting, strategy, policy and compliance. Mr. Stone holds an M.B.A. with concentrations in finance, economics and accounting from the University of Chicago, Graduate School of Business and a B.B.A in Accounting from the University of Iowa. He is also a Certified Public Accountant.
Brad Albin, age 56, has served as our Vice President, Manufacturing since February 2008. Mr. Albin joined REG in 2006. From 2002 to 2006, Mr. Albin served as Executive Director of Operations for Material Sciences Corporation, where he directed multi-plant operations for automotive and global appliance industries. From 1996 to 2002, Mr. Albin was the Vice President of Operations for Griffin Industries. Mr. Albin has over 25 years of experience in executive operations positions in multi-feedstock

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biomass-based diesel, chemical, food and automotive supplier companies, such as The Monsanto Company, The NutraSweet Company and Griffin Industries. Mr. Albin was a charter member of the National Biodiesel Accreditation Committee. Mr Albin is a current director on two boards where REG has investments and was previously on the Board of Managers for Petrotec GmbH before REG acquired full ownership in 2017.  Mr. Albin was previously the President and Vice President of the Iowa Renewable Fuels Association from 2011-2013. In November 2014, Mr. Albin completed the Advanced Management Program from the University of Chicago Booth School of Business and he holds a B.S. in Chemistry from Eastern Illinois University.
Gary Haer, age 65, has served as our Vice President, Sales and Marketing since we commenced operations in August 2006. From October 1998 to August 2006, Mr. Haer served as the National Sales and Marketing Manager for biodiesel for West Central Cooperative, now known as Landus Cooperative, and was responsible for developing the marketing and distribution infrastructure for biodiesel sales in the United States. Mr. Haer has over 20 years of experience in the biomass-based diesel industry. Mr. Haer previously served on the Executive Committee of the National Biodiesel Board’s Governing Board and was Past Chairman.  He held various officer positions during his tenure from 1998 to 2017. Mr. Haer holds an M.B.A. from Baker University and a B.S. in Accounting from Northwest Missouri State University.
Eric M. Bowen, age 47, has served as our Vice President, Corporate Business Development & Legal Affairs since January 2013, and has led the REG Life Sciences business unit since January 2014. From June 2010 to January 2013, Mr. Bowen served as our Executive Director, Corporate Business Development and Legal Affairs. From 2005 to June 2010, Mr. Bowen was Founder, President and CEO of Tellurian Biodiesel, Inc. (formerly San Francisco Biodiesel), which was acquired by the Company. Prior to entering the advanced biofuels industry, Mr. Bowen practiced corporate and securities law in Silicon Valley. Mr. Bowen has been active in setting biofuels policy as a founding member of the California Advanced Biofuels Alliance and as Chairman from 2007 to 2012. He also served as Chairman of the San Francisco Biodiesel Taskforce and as a member of the California LCFS Advisory Panel. Mr. Bowen has served as a member of the Board of Directors of a company in which REG has invested since November 2013. Mr. Bowen is also on the board of the California Advanced Biofuel Alliance. Mr Bowen holds a J.D. from the University of California, Berkeley and a B.A. from the University of Oregon Honors College.
Available Information
Our internet address is http://www.regi.com. Through that address, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports are available free of charge as soon as reasonably practicable after they are filed with the United States Securities and Exchange Commission. The information contained on our website is not included in, or incorporated by reference into, this annual report on Form 10-K.
ITEM 1A.
Risk Factors
Our business, financial condition, results of operations and liquidity are subject to various risks and uncertainties, including those described below. As a result, the trading price of our common stock could decline.

RISKS RELATED TO FEDERAL AND STATE INCENTIVES
The Renewable Fuel Standard Program, a Federal law mandating the consumption of qualifying biofuels, could be repealed, curtailed or otherwise changed, which might have a material adverse effect on our revenues, operating margins and financial condition.
We and other participants in the biomass-based diesel industry rely on governmental programs requiring or incentivizing the consumption of biofuels. Biomass-based diesel has historically been more expensive to produce than petroleum-based diesel fuel and these governmental programs support a market for biomass-based diesel that might not otherwise exist.
One of the most important of these programs is the Renewable Fuel Standard ("RFS2"), a Federal law which requires that transportation fuels in the United States contain a minimum amount of renewable fuel. This program is administered by the Environmental Protection Agency ("EPA"). The EPA's authority includes setting annual minimum aggregate levels of consumption in four renewable fuel categories, including the two primary categories in which our fuel competes (biomass-based diesel and advanced biofuel). The parties obligated to comply with this renewable volume obligation ("RVO"), are petroleum refiners and petroleum fuel importers.
The petroleum industry is strongly opposed to the RFS2 and can be expected to continue to press for changes both in the RFS2 itself and in the way that it is administered by the EPA. One key point of contention is the rate of growth in the annual RVO. The RVO for biomass-based diesel was set at steadily rising levels beginning at 1.0 billion gallons in 2012 and increasing to 2.00 billion gallons in 2017. However, growth in the RVO was constrained from 2017 through 2019, as the biomass-based diesel RVO increased by only 100,000 gallons from 2.00 billion to 2.10 billion gallons while the advanced biofuel RVO increased from 4.28 billion gallons to 4.92 billion gallons. For 2020, the EPA set the biomass-based diesel RVO

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at 2.43 billion gallons. The 2020 advanced biofuel RVO will be established later this year. We believe that growth in the annual RVOs strongly influences our ability to grow our business and supports the price of our fuel through the RINs. The EPA's future decisions regarding the RVO will significantly influence our revenues and profit margins.
The RFS2 also grants to the EPA authority to grant small refiner waivers, waiving, in whole or in part, a qualifying refiner's obligation based on a determination that the program is causing severe economic harm to that refinery. Prior to 2016, relatively few requests were made for waivers and roughly half of those requests were granted by the EPA. In the 2016 compliance year, the EPA received 20 requests, granted 19, with one remaining pending today, which amounted to approximately 790 million total RINs that were being waived through exceptions. In the 2017 and 2018 compliance years, the EPA received 37 waiver requests each year. According to the EPA, 29 of the 2017 requests were granted with seven still pending and one withdrawn, which amounted to 1,460 million RINs or 7.6% of the total RIN requirement that was waived. All 37 requests for 2018 remain pending. We believe that these exemptions, in addition to other factors such as HOBO spread, impacted the demand for and price of RINs as the average price of D4 RINs fell from $0.82 to $0.55 during 2018 according to OPIS data. If the EPA continues this practice, it will harm demand for and the price of RINs and thus our profitability.
The United States Congress could repeal, curtail or otherwise change the RFS2 program in a manner adverse to us. Similarly, the EPA could curtail or otherwise change its administration of the RFS2 program in a manner adverse to us, including by not increasing or even decreasing the RVO, by waiving compliance with the RVO or otherwise. In addition, while Congress specified RFS2 volume requirements through 2022 (subject to adjustment in the rulemaking process), beginning in 2023 required volumes of renewable fuel will be largely at the discretion of the EPA (in coordination with the Secretary of Energy and Secretary of Agriculture). We cannot predict what changes, if any, will be instituted or the impact of any changes on our business, although adverse changes could seriously harm our revenues, earnings and financial condition.

Loss of or reductions in Federal and State Government tax incentives for biomass-based diesel production or consumption may have a material adverse effect on our revenues and operating margins.
Federal and State Government tax incentives have assisted the biomass-based diesel industry by making the price of biomass-based diesel more cost competitive with the price of petroleum-based diesel fuel to the end user.
Federal Tax Incentives
The most significant tax incentive program has been the federal biodiesel mixture excise tax credit, referred to as the Biodiesel Tax Credit ("BTC"). Under the BTC, the first person to blend pure biomass-based diesel with petroleum-based diesel fuel receives a $1.00-per-gallon refundable tax credit.
The BTC was established on January 1, 2005 and has lapsed and been reinstated retroactively and prospectively several times. Most recently in February 2018, the BTC was retroactively reinstated for 2017, but was not reinstated for any subsequent periods. As a result, the BTC has not been in effect since January 1, 2018. As was the case in previous periods when the BTC was not in effect, we and many other biomass-based diesel industry producers have adopted contractual arrangements with customers and vendors specifying the allocation and sharing of any retroactively reinstated incentive. Whether the BTC will be reinstated for 2018 or future years will have a very significant impact on our results of operations and financial condition. Reinstatement of the BTC for 2017 resulted in a $205 million net benefit (after satisfaction of sharing arrangements) to our net income in the first quarter of 2018 and to our Adjusted EBITDA for 2017. We estimate that if the BTC is reinstated for 2018 on the same terms as in 2017, the net benefits to our net income in the period in which it is reinstated and Adjusted EBITDA for business conducted in the year ended December 31, 2018, would each increase by approximately $237 million.
Unlike the RFS2 program, the BTC has a direct effect on Federal Government spending and changes in federal budget policy could result in its elimination or in changes to its terms that are less beneficial to us. We cannot predict what action, if any, Congress may take with respect to the BTC. There is no assurance that the BTC will be reinstated, that it will be reinstated on the same terms or, if reinstated, that its application will be retroactive, prospective or both. Due to the significance of this program to our business, adverse changes in the BTC can be expected to seriously harm our results of operations and financial condition.
State Tax Incentives
Several states have enacted tax incentives for the use of biodiesel. For example, Illinois has a generally applicable 6.25% sales tax, but offers an exemption from this tax for a blend of fuel that consists of 11% biodiesel ("B11"). In Iowa, for 2018 through 2024, retailers earn $0.035 per gallon of B5 - B10 and $0.055 per gallon for B11 and above. Iowa also has a biomass-based diesel production incentive that provides $0.02 per gallon of production capped after the first 25 million gallons per production plant. The biomass-based diesel portion of biomass-based diesel blends are exempt from Texas state excise tax, which results in a $0.20 per gallon incentive for B100. Minnesota law requires a B5 biodiesel blend except during the summer months when a B20 blend is required. State budget or other considerations could cause the modification or elimination of tax

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incentive programs. The curtailment or elimination of such incentives could materially and adversely affect our revenues and profitability.

We derive a significant portion of our revenues from sales of our renewable fuel in the State of California primarily as a result of California’s Low Carbon Fuel Standard; adverse changes in this law or reductions in the value of the credits we receive under the LCFS and sell to third parties would harm our revenues and profits.
We estimate that our revenues from the sale of renewable fuel in California and from sales of credits received under California's Low Carbon Fuel Standard ("LCFS") were approximately $353.3 million in 2018. The LCFS is designed to reduce greenhouse gas emissions associated with transportation fuels used in California by ensuring that the total amount of fuel consumed meets declining targets for such emissions. The regulation quantifies lifecycle greenhouse gas emissions by assigning a “carbon intensity” ("CI") score to each transportation fuel based on that fuel’s lifecycle assessment. Each petroleum fuel provider, generally the fuel’s producer or importer is required to ensure that the overall CI score for its fuel pool meets the annual carbon intensity target for a given year. This obligation is tracked through credits and deficits and credits can be traded. We receive LCFS credits when we sell qualified biomass-based diesel in California. As a result of the trading price of LCFS credits, California has become a desirable market in which to sell our renewable fuel. In 2018, LCFS credit prices increased from $116 per credit on January 2, 2018 to $195 per credit on December 31, 2018. As a result, an increasing percentage of our revenue and profit is related to sales to California and LCFS credit values. If the value of LCFS credits were to materially decrease as a result of greater supply or reduced demand for qualifying renewable fuel, if the fuel we produce is deemed not to qualify for LCFS credits or if the LCFS or the manner in which it is administered or applied were otherwise changed in a manner adverse to us, our revenues and profits could be seriously harmed.

RISKS RELATED TO OUR BUSINESS OPERATIONS AND THE MARKETS IN WHICH WE OPERATE

Increased industry-wide production of biodiesel as a result of potential utilization of existing excess production capacity, announced large plant expansions of renewable diesel and potential co-processing of renewable diesel by petroleum refiners, could reduce prices for our fuel and increase the cost of feedstocks used to produce them, which would seriously harm our revenues and results of operations.
If additional volumes of advanced biofuel RIN production come online and the EPA does not increase the RVO in accordance with the increased production, the volume of advanced biofuel RINs generated could exceed the volume required under the RFS2.  In the event this occurs, biomass-based diesel and advanced biofuel RIN prices would be expected to decrease, potentially significantly, harming demand for our products and our profitability.
According to the National Biodiesel Board ("NBB"), in 2017, 4.1 billion gallons per year of biomass-based diesel production capacity in the United States was registered under the RFS2 program by NBB members. In addition to this amount, several hundred million more gallons of U.S. based biomass-based diesel production capacity was registered by non-NBB members and another 4.5 billion gallons of biomass-based diesel production was registered by foreign producers. These amounts far exceed both historic consumption of biomass-based diesel in the United States and required consumption under the RFS2.
Additionally, several leading biomass-based diesel companies have announced their intention to expand their production of renewable diesel for the U.S. market. World Energy has announced that it will expand capacity at its Los Angeles area biorefinery from its existing 45 mmgy to over 300 mmgy. Diamond Green Diesel, the largest U.S. producer of renewable diesel, has announced plans to expand its 275 million mmgy capacity by 400 mmgy. Neste, the largest global producer of renewable diesel, announced in December 2018 a 440 mmgy expansion of its Singapore facility that exports a significant portion of its production to the U.S.West Coast.
Further, due to the economic incentives available, several petroleum refiners have started or may soon start to produce co-processed renewable diesel, or CPRD. CPRD uses the same feedstocks we use to produce biomass-based diesel and it generates an advanced biofuel RIN. CPRD may be more cost-effective to produce than biomass-based diesel, particularly biodiesel.
If production of competitive advanced renewable fuels increases significantly as a result of utilization of existing excess production capacity or new capacity as described above, competition for a relatively fixed supply of feedstocks would increase significantly, harming our margins. Furthermore if supply of advanced renewable fuels exceeds demand, prices for our renewable fuel and for RINs and other credits may decrease significantly, harming our profitability and potentially forcing us to idle our facilities.




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Our gross margins are dependent on the spread between biomass-based diesel prices and feedstock costs, each of which are volatile and can cause our results of operations to fluctuate substantially.
Biomass-based diesel has traditionally been marketed primarily as an additive or alternative to petroleum-based diesel fuel, and, as a result, biomass-based diesel prices have been heavily influenced by the price of petroleum-based diesel fuel, adjusted for government incentives supporting renewable fuels, more so than biomass-based diesel production costs. The absence of a close correlation between production costs and biomass-based diesel prices means that we may be unable to pass increased production costs on to our customers in the form of higher prices. If there is a decrease in the spread between biomass-based diesel prices and feedstock costs, whether as a result of an increase in feedstock prices or as a result of a reduction in biomass-based diesel and credit prices, our gross margins, cash flow and results of operations would be adversely affected.
Energy prices, particularly the market price for crude oil, are volatile. According to OPIS data, the average B100 price in the Upper Midwest ranged from a low of $2.77 per gallon to a high of $3.19 per gallon in 2018. Petroleum prices are volatile due to global factors, such as the impact of wars, political uprisings, new extraction technologies and techniques, OPEC production quotas, worldwide economic conditions, changes in refining capacity and natural disasters.
In addition, an element of the price of biomass-based diesel that we produce is the value of the associated credits, including RINs. RIN prices in the biomass-based diesel category as reported by OPIS fluctuated significantly in 2018, ranging from $0.31 to $0.91 per RIN while in 2017, RIN prices started the year at $1.05 per RIN and declined to a low of $0.79 per RIN in December. For years there has been significant volatility in RIN prices. For example, in 2013, RIN prices decreased sharply from $1.09 per RIN on July 1, 2013 to $0.35 per RIN on December 31, 2013. Reductions in RIN values, such as those experienced in prior years, may have a material adverse effect on our revenues and profits as they directly reduce the value we are able to capture for our biomass-based diesel.
A decrease in the availability or an increase in the price, of feedstocks may have a material adverse effect on our financial condition and operating results. The price and availability of feedstocks and other raw materials may be influenced by general economic, market and regulatory factors. These factors include weather conditions, farming decisions, government policies and subsidies with respect to agriculture and international trade and global supply and demand. During periods when the BTC has lapsed, biomass-based diesel producers may elect to continue purchasing feedstock and producing biomass-based diesel at negative margins under the assumption the BTC will be retroactively reinstated, and consequently, the price of feedstocks may not decrease to a level proportionate to current operating margins. Increasing production of biomass-based diesel and, particularly recent and prospective expansion of renewable diesel capacity, the development of alternative fuels and renewable chemicals also puts pressure on feedstock supply and availability to the biomass-based diesel industry. The biomass-based diesel industry may have difficulty in procuring feedstocks at economical prices if competition for biomass-based diesel feedstocks increases due to newly added biodiesel capacity or alternative fuels.
Historically, the spread between biomass-based diesel prices and feedstock costs has varied significantly. Although actual yields vary depending on the feedstock quality, the average monthly spread between the price per gallon of 100% pure biodiesel ("B100") as reported by The Jacobsen Publishing Company, and the price per gallon for the amount of choice white grease necessary to produce one gallon of B100 was $1.28 in 2016, $1.20 in 2017 and $1.38 in 2018, assuming eight pounds of choice white grease yields one gallon of biomass-based diesel. The average monthly spread for the amount of crude soybean oil required to produce one gallon of B100, based on the nearby futures contract as reported on the Chicago Board of Trade, was $0.73 in 2016, $0.64 in 2017 and $0.76 in 2018, assuming 7.5 pounds of soybean oil yields one gallon of biomass-based diesel. For each year from 2016 to 2018, approximately 72%, 73% and 77%, respectively, of our annual total feedstock usage was inedible corn oil, used cooking oil or inedible animal fat, and approximately 28%, 27% and 23%, respectively, was virgin vegetable oils. When the spread between biomass-based diesel prices and feedstock prices narrows, our profitability will be harmed.

Risk management transactions could significantly increase our operating costs and may not be effective.
In an attempt to partially offset the effects of volatile feedstock costs and biomass-based diesel fuel prices, we enter into contracts that establish market positions in feedstocks, such as inedible corn oil, used cooking oil, inedible animal fats and soybean oil, along with related commodities, such as heating oil and ultra-low sulfur diesel ("ULSD"). The financial impact of such market positions depends on commodity prices at the time that we are required to perform our obligations under these contracts as well as the cumulative sum of the obligations we assume under these contracts.
Risk management activities can themselves result in losses when a position is purchased in a declining market or a position is sold in a rising market. Risk management arrangements expose us to the risk of financial loss in situations where the counterparty defaults on its contract or, in the case of exchange-traded or over-the-counter futures or options contracts, where there is a change in the expected differential between the underlying price in the contract and the actual prices paid or received by us. Changes in the value of these futures instruments are recognized in current income and may result in margin calls. We had risk management gains of $18.4 million from our derivative financial instrument trading activity for the year

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ended December 31, 2018, compared to risk management losses of $23.4 million for the year ended December 31, 2017. At December 31, 2018, the net notional volumes of NY Harbor ULSD, CBOT Soybean Oil and NYMEX Natural Gas covered under the open risk management contracts were approximately 83.3 million gallons and 218.3 million pounds and 1.3 million million British thermal units, respectively. A 10% positive change in the prices of NYMEX NY Harbor ULSD would have a negative effect of $14.0 million on the fair value of these instruments at December 31, 2018. A 10% adverse change in the price of CBOT Soybean Oil would have had a negative effect of $6.1 million on the fair value of these instruments at December 31, 2018. If these adverse changes in derivative instrument fair value were to occur in larger magnitude or simultaneously, a significant amount of liquidity would be needed to fund margin calls.  In addition, we may also vary the amount of risk management strategies we undertake, or we may choose not to engage in risk management transactions at all.  Our results of operation may be negatively impacted if we are not able to manage our risk management strategy effectively.

One customer accounted for a meaningful percentage of revenues and a loss of this customer could have an adverse impact on our total revenues.
One customer, Pilot Travel Centers LLC, ("Pilot"), the largest operator of travel centers in North America, accounted for 9%, 8% and 8% of our revenues in each of 2018, 2017 and 2016, respectively. Our revenues from Pilot generally do not include the RINs or LCFS credits associated with the gallons of biomass-based diesel sold to Pilot. The value of those RINs and LCFS credits represented approximately an additional 2%, 9% and 9% of our total sales in 2018, 2017 and 2016, respectively, based on the OPIS average RIN and LCFS price for these periods. In the event we lose Pilot as a customer or Pilot significantly reduces the volume of biomass-based diesel purchased from us, it could be difficult to replace the lost revenues, and our profitability and cash flow could be materially harmed. We do not have a long-term contract with Pilot that ensures a continuing level of business from Pilot.

Our facilities and our customers' facilities are subject to risks associated with fire, explosions, leaks, and natural disasters, which may disrupt our business and increase costs and liabilities.
Because biomass-based diesel and some of its inputs and outputs are combustible and/or flammable, a leak, fire or explosion may occur at a plant or customer’s facility which could result in damage to the plant and nearby properties, injury to employees and others, and interruption of operations. For example, we experienced fires at our Geismar facility in April 2015 and again in September 2015 and there was a fire at our Madison facility in June 2017. As a result of these fires, people were injured and the affected facilities were shut down for lengthy periods while repairs and upgrades were completed.
The operations at our facilities are also subject to the risk of natural disasters. Our Houston and Geismar facilities, due to their Gulf Coast locations, are vulnerable to hurricanes and flooding, which may cause plant damage, injury to employees and others and interruption of operations. For example, in August 2016 we experienced reduced operating days at our Geismar facility as a result of local area flooding and reduced operating days at our Houston facility as a result of Hurricane Harvey in August 2017. A majority of our facilities are located in the Midwest, and are subject to tornado activity. In addition, California has become one of our largest markets, serviced by our Geismar and Midwest facilities. An earthquake or other natural disaster could disrupt our ability to transport, store and deliver products to the California market.
If we experience a fire or other serious incident at our facilities or if any of our facilities is affected by a natural disaster, we may incur significant additional costs including, among other things, loss of profits due to unplanned temporary or permanent shutdowns of our facilities, or the means of transporting our products, cleanup costs, liability for damages or injuries, legal expenses and reconstruction expenses, which would harm our results of operations and financial condition.

In addition to biodiesel and renewable diesel, we store and transport petroleum-based motor fuels.  The dangers inherent in the storage and transportation of fuels could cause disruptions in our operations and could expose us to potentially significant losses, costs or liabilities.
We store fuel in aboveground storage tanks and transport fuel in our own trucks as well as with third-party carriers. Our operations are subject to significant hazards and risks inherent in transporting and storing fuel. These hazards and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and other damage to our properties and the properties of others. Any such event not covered by our insurance could have a material adverse effect on our business, financial condition and results of operations.

Our insurance may not protect us against our business and operating risks.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially and, in some

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instances, certain insurance policies may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we intend to maintain insurance at levels we believe are appropriate for our business and consistent with industry practice, we will not be fully insured against all risks. In addition, pollution, environmental risks and the risk of natural disasters generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

We operate in a highly competitive industry and competition in our industry would increase if new participants enter the biomass-based diesel or advanced biofuels business.
We operate in a very competitive environment. The biomass-based diesel industry primarily comprises smaller entities that engage exclusively in biodiesel production, large integrated agribusiness companies that produce biodiesel along with their soybean crush businesses and increasingly, integrated petroleum companies producing renewable diesel. We face competition for capital, labor, feedstocks and other resources from these companies. In the United States, we compete with soybean processors and refiners, including Archer-Daniels-Midland Company, Cargill, and Louis Dreyfus Commodities. In addition, petroleum refiners are increasingly entering into renewable diesel production. Such petroleum refiners include Neste Corporation with approximately 882 mmgy of global renewable diesel production capacity in Asia and Europe, and Valero Energy Corporation through its Diamond Green Diesel joint venture that operates an approximate 275 mmgy capacity renewable diesel facility in Norco, Louisiana that is in the process of being expanded by 400 mmgy. In addition, petroleum refiners such as Sinclair, British Petroleum and Andeavor (formerly known as Tesoro) have announced that they have begun co-processing renewable diesel at certain of their refineries. All of these named competitors have greater financial resources than we do and may be able to produce biomass-based diesel at a lower cost than we do due to their integrated operations or greater refining capacity.
Petroleum companies and diesel retailers form the primary distribution networks for marketing biomass-based diesel through blended petroleum-based diesel. If these companies increase their direct or indirect biomass-based diesel production, including in the form of co-processing, there will be less need to purchase biomass-based diesel from independent biomass-based diesel producers like us. Such a shift in the market would materially harm our operations, cash flows and financial position.

We derive a substantial portion of our profitability from the production of renewable diesel at our plant located in Geismar, Louisiana and any interruption in our operations at this facility would have a material adverse effect on our results of operations and financial conditions.
Renewable diesel carries a premium price to biodiesel as a result of a variety of factors including the ability to blend it with petroleum diesel seamlessly, better cold weather performance, and because it generates more RINs on a per gallon basis. We estimate that our renewable diesel production facility in Geismar, Louisiana generated more than half of our adjusted EBITDA in 2018. We experienced two fires at this facility in 2015 that each resulted in the plant being shut down for a lengthy period. If production at this facility were interrupted again due to a fire or for any other reason, it would have a disproportionately significant and material adverse impact on our results of operations and financial conditions.

Technological advances and changes in production methods in the biomass-based diesel industry and renewable chemical industry could render our plants obsolete and adversely affect our ability to compete.
It is expected that technological advances in biomass-based diesel production methods will continue to occur and new technologies for biomass-based diesel production may develop. Advances in the process of converting oils and fats into biodiesel and renewable diesel, including CPRD, could allow our competitors to produce biomass-based diesel faster and more efficiently and at a substantially lower cost. In addition, we currently produce biomass-based diesel to conform to or exceed standards established by the American Society for Testing and Materials ("ASTM"). ASTM standards for biomass-based diesel and biomass-based diesel blends may be modified in response to new technologies from the industries involved with diesel fuel.
New standards or production technologies may require us to make additional capital investments in, or modify, plant operations to meet these standards. If we are unable to adapt or incorporate technological advances into our operations, our production facilities could become less competitive or obsolete. Further, it may be necessary for us to make significant expenditures to acquire any new technology, acquire licenses or other rights to technology and retrofit our plants in order to incorporate new technologies and remain competitive.There is no assurance that we will be able to obtain such technologies, licenses or rights on favorable terms. If we are unable to obtain, implement or finance new technologies, our production facilities could be less efficient than our competitors, and our ability to produce biomass-based diesel on a competitive level may be harmed, negatively impacting our revenues and profitability.

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Our intellectual property is integral to our business. If we are unable to protect our intellectual property, or others assert that our operations violate their intellectual property, our business could be adversely affected.
Our success depends in part upon our ability to protect and prevent others from using our intellectual property. Failure to obtain or maintain adequate intellectual property protection could adversely affect our competitive business position. We rely on a combination of intellectual property rights, including patents, copyrights, trademarks and trade secrets in the United States and in select foreign countries. Effective patent, copyright, trademark and trade secret protection may be unavailable, limited or not applied for in some countries.
We rely in part on trade secret protection to protect our confidential and proprietary information and processes. However, trade secrets are difficult to protect. We have taken measures to protect our trade secrets and proprietary information, but these measures may not be effective. For example, we require new employees and consultants to execute confidentiality agreements upon the commencement of their employment or consulting arrangement with us. These agreements generally require that all confidential information developed by the individual or made known to the individual by us during the course of the individual’s relationship with us be kept confidential and not disclosed to third parties. These agreements also generally provide that knowhow and inventions conceived by the individual in the course of rendering services to us are our exclusive property. Nevertheless, these agreements may be breached, or may not be enforceable, and our proprietary information may be disclosed. Despite the existence of these agreements, third parties may independently develop substantially equivalent proprietary information and techniques.
It may be difficult for us to protect and enforce our intellectual property. Costly and time-consuming litigation could be necessary to enforce and determine the scope of our proprietary rights. If we pursue litigation to assert our intellectual property rights, an adverse judicial decision in any legal action could limit our ability to assert our intellectual property rights, limit our ability to develop new products, limit the value of our technology or otherwise negatively impact our business, financial condition and results of operations.
A competitor could seek to enforce intellectual property claims against us. Defending intellectual property rights claims asserted against us, regardless of merit, could be time-consuming, expensive to litigate or settle, divert management resources and attention and force us to acquire intellectual property rights and licenses, which may involve substantial royalty payments. Further, a party making such a claim, if successful, could secure a judgment that requires us to pay substantial damages.

Increases in our transportation costs or disruptions in our transportation services could have a material adverse effect on our business.
Our business depends on transportation services to deliver raw materials to us and finished products to our customers. The costs of these transportation services are affected by the volatility in fuel prices or other factors. For example, from January 2016 to mid-2018, diesel prices increased from just over one dollar per gallon to over two dollars per gallon for the second and third quarters of 2018.
Changes in fuel prices, and thus changes in our transportation costs, can be drastic and unpredictable. Our transportation costs are also affected by U.S. oil production in the Bakkens, which has had a significant impact on tank car availability and prices. If oil production from this area increases, the demand for rail cars will rise and will significantly increase rail car prices. We have not been able in the past, and may not be able in the future, to pass along part or all of any of these price increases to customers.
If we continue to be unable to increase our prices as a result of increased fuel costs charged to us by transportation providers, our gross margins may be materially adversely affected. If any transportation providers fail to deliver raw materials to us in a timely manner, we may be unable to manufacture products on a timely basis. Shipments of products and raw materials may be delayed due to weather conditions, strikes or other events. Any failure of a third-party transportation provider to deliver raw materials or products in a timely manner could harm our reputation, negatively affect our customer relationships and have a material adverse effect on our business, financial condition and results of operations.

We are dependent upon our key management personnel and other personnel whereby the loss of any of these persons could adversely affect our results of operations.
Our success depends on the abilities, expertise, judgment, discretion, integrity and good faith of our management and employees to manage the business and respond to economic, market and other conditions. We are highly dependent upon key members of our relatively small management team and employee base that possess unique technical skills for the execution of our business plan. There can be no assurance that any individual will continue in his or her capacity for any particular period of time or that replacement personnel with comparable skills could be found. The inability to retain our management team and employee base or attract suitably qualified replacements and additional staff could adversely affect our business. The loss of

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employees could delay or prevent the achievement of our business objectives and have a material adverse effect upon our results of operations and financial position.

We may encounter difficulties in effectively integrating the businesses we acquire, including our international businesses where we have limited operating history.
We may face significant challenges in effectively integrating entities and businesses that we acquire, and we may not realize the benefits anticipated from such acquisitions.  Achieving the anticipated benefits of our acquired businesses will depend in part upon whether we can integrate our businesses in an efficient and effective manner.  Our integration of acquired businesses involves a number of risks, including:
difficulty in integrating the operations and personnel of the acquired company;
difficulty in effectively integrating the acquired technologies, products or services with our current technologies, products or services;
demands on management related to the increase in our size after the acquisition;
the diversion of management’s attention from daily operations to the integration of acquired businesses and personnel;
failure to achieve expected synergies and costs savings;
difficulties in the assimilation and retention of employees;
difficulties in the assimilation of different cultures and practices, as well as in the assimilation of broad and geographically dispersed personnel and operations;
difficulties in the integration of departments, systems, including accounting systems, technologies, books and records and procedures, as well as in maintaining uniform standards and controls, including internal control over financial reporting, and related procedures and policies;
incurring acquisition-related costs or amortization costs for acquired intangible assets that could impact our operating results;
the need to fund significant working capital requirements of any acquired production facilities;
potential failure of the due diligence processes to identify significant problems, liabilities or other shortcomings or challenges of an acquired company or technology, including but not limited to, issues with the acquired company’s intellectual property, product quality, environmental liabilities, data back-up and security, revenue recognition or other accounting practices, employee, customer or partner issues or legal and financial contingencies;
exposure to litigation or other claims in connection with, or inheritance of claims or litigation risk as a result of, an acquisition, including but not limited to, claims from terminated employees, customers, former stockholders or other third parties; and
incurring significant exit charges if products or services acquired in business combinations are unsuccessful.

Our ability to recognize the benefit of our acquisition of two biodiesel production facilities in Germany and associated business operations, or any other international operations we may invest in the future, will require the attention of management and is subject to a number of risks. Our experience operating a biorefinery and other business operations outside of the United States is limited. In addition, while the biodiesel market in Europe benefits from regulations that encourage the use of biodiesel, these regulations are subject to political and public opinion and may be changed. In addition, expanding our operations internationally subjects us to the following risks:
recruiting and retaining talented and capable management and employees in foreign countries;
challenges caused by distance, language and cultural differences;
protecting and enforcing our intellectual property rights;
difficulties in the assimilation and retention of employees;
the inability to extend proprietary rights in our technology into new jurisdictions;
currency exchange rate fluctuations;
general economic and political conditions in foreign jurisdictions;
foreign tax consequences;
foreign exchange controls or U.S. tax laws in respect of repatriating income earned in countries outside the United States;
compliance with the U.S.'s Foreign Corrupt Practices Act and other similar anti-bribery and anti-corruption regulations;
political, economic and social instability;
higher costs associated with doing business internationally; and
export or import regulations as well as trade and tariff restrictions.

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Our failure to successfully manage and integrate our acquisitions could have an adverse effect on our operating results, ability to recognize international revenue, and our overall financial condition.

We incur significant expenses to maintain and upgrade our operating equipment and plants, and any interruption in the operation of our facilities may harm our operating performance.
We regularly incur significant expenses to maintain and upgrade our equipment and facilities. The machines and equipment that we use to produce our products are complex, have many parts and some are run on a continuous basis. We must perform routine maintenance on our equipment and will have to periodically replace a variety of parts such as motors, pumps, pipes and electrical parts. In addition, our facilities require periodic shutdowns to perform major maintenance and upgrades. These scheduled shutdowns of facilities result in decreased sales and increased costs in the periods in which a shutdown occurs and could result in unexpected operational issues in future periods as a result of changes to equipment and operational and mechanical processes made during the shutdown period.

Growth in the sale and distribution of biodiesel is dependent on the expansion of related infrastructure which may not occur on a timely basis, if at all, and our operations could be adversely affected by infrastructure limitations or disruptions.
While renewable diesel has the same chemical composition as petroleum diesel and can utilize the same distribution infrastructure, biodiesel has a different chemical composition and may require separate or additional infrastructure. Growth in the biodiesel market depends on continued development of infrastructure for the distribution of biodiesel. Substantial investment required for these infrastructure changes and expansions may not be made on a timely basis or at all. The scope and timing of any infrastructure expansion are often beyond our control. Also, we compete with other biofuel companies for access to some of the key infrastructure components such as pipeline, terminal and underground storage tank capacity. As a result, increased production of biodiesel will increase the demand and competition for necessary infrastructure. Any delay or failure in expanding distribution infrastructure could hurt the demand for or prices of biodiesel, impede delivery of our biodiesel, and impose additional costs, each of which would have a material adverse effect on our results of operations and financial condition. Our business will be dependent on the continuing availability of infrastructure for the distribution of increasing volumes of biodiesel and any infrastructure disruptions could materially harm our business.

Our business is subject to seasonal changes based on regulatory factors and weather conditions and this seasonality could cause our revenues and operating results to fluctuate.
Our operating results are influenced by seasonal fluctuations in the price of and demand for biomass-based diesel. Seasonal fluctuations may be based on both the weather and the status of both the BTC and RVO.
Demand for our biomass-based diesel may be higher in the quarters leading up to the expiration of the BTC as customers seek to purchase biomass-based diesel when they can benefit from the agreed upon value sharing of the BTC with producers. This higher demand prompted by an expiring BTC has often resulted in reduced demand for biodiesel in the following quarter. In addition, RIN prices may also be subject to seasonal fluctuations. The RIN is dated for the calendar year in which it is generated. Since 20% of an Obligated Party's annual RVO can be satisfied by prior year RINs, most RINs must come from biofuel produced or imported during the RVO year. As a result, RIN prices can be expected to increase as the calendar year progresses if the RIN market is undersupplied compared to that year's RVO and decrease if it is oversupplied.
Weather also impacts our business because biodiesel typically has a higher cloud point than petroleum-based or renewable diesel. The cloud point is the temperature below which a fuel exhibits a noticeable cloudiness and eventually gels, leading to fuel handling and performance problems for customers and suppliers. Reduced demand in the winter for our higher cloud point biodiesel may result in excess supply of such higher cloud point biodiesel and lower prices for such higher cloud point biodiesel. Most of our production facilities are located in colder Midwestern states and our costs of shipping biodiesel to warmer climates generally increase in cold weather months.
The tendency of biodiesel to gel in colder weather may also result in long-term storage problems. In cold climates, fuel may need to be stored in a heated building or heated storage tanks, which result in higher storage costs. Higher cloud point biodiesel may have other performance problems, including the possibility of particulate formation above the cloud point which may result in increased expenses as we try to remedy these performance problems, including the costs of extra cold weather treatment additives. Remedying these performance problems may result in decreased yields, lower process throughput or both, as well as substantial capital costs. Any reduction in the demand for our biodiesel product, or the production capacity of our facilities will reduce our revenues and have an adverse effect on our cash flows and results of operations.

Failure to comply with governmental regulations, including EPA requirements relating to RFS2, could result in the imposition of penalties, fines, or restrictions on our operations and remedial liabilities.

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The biomass-based diesel industry is subject to extensive federal, state and local laws and regulations. Under certain environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, and regardless of whether current or prior operations were conducted consistent with the accepted standards of practice. Many of our assets and plants were acquired from third parties and we may incur costs to remediate property contamination caused by previous owners. Compliance with these laws, regulations and obligations could require substantial capital expenditures. Failure to comply could result in the imposition of penalties, fines or restrictions on operations and remedial liabilities.
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our business in general and on our results of operations, competitive position or financial condition. We are unable to predict the effect of additional environmental laws and regulations which may be adopted in the future, including whether any such laws or regulations would significantly increase our cost of doing business or affect our operations in any area.
We are subject to various laws and regulations related to RFS2, most significantly regulations related to the generation and dissemination of RINs. These regulations are highly complex and continuously evolving, requiring us to periodically update our compliance systems. In 2014, the EPA issued a final rule to establish a quality assurance program and the EPA also implemented regulations related to the generation and sale of biomass-based diesel RINs. Compliance with these or any new regulations or Obligated Party verification procedures could require significant expenditures to attain and maintain compliance. Any violation of these regulations by us, could result in significant fines and harm our customers’ confidence in the RINs we issue, either of which could have a material adverse effect on our business.

Renewable diesel fuel is superior to biodiesel in certain respects and if renewable diesel production capacity increases to a sufficient extent, it could largely supplant biodiesel as the renewable fuel of choice; we may not be successful in expanding our renewable diesel production capacity.
Renewable diesel is not as widely available as biodiesel, but it has certain characteristics that favorably distinguish it from traditional biodiesel and as a result renewable diesel carries a price premium compared to biodiesel. For example, renewable diesel has very similar chemical properties to petroleum-based diesel, which permits 100% renewable diesel (unlike 100% biodiesel) to flow through the same fuel storage and distribution network as petroleum diesel. Renewable diesel can also be used in its pure form in modern engines rather than as a blend with petroleum diesel and has similar cold weather performance as petroleum diesel. Renewable diesel and co-processed renewable diesel may receive 1.6 or 1.7 RINs per gallon, whereas biodiesel receives 1.5 RINs per gallon. As the value of RINs increases, this RIN advantage makes renewable diesel more cost-effective, both as a petroleum-based diesel substitute and for meeting RFS2 requirements. If renewable diesel proves to have superior performance characteristics and is more cost-effective than biodiesel, revenues from our biodiesel plants and our results of operations would be adversely impacted.
In view of the demand and price premium for renewable diesel, we are evaluating opportunities to expand our renewable diesel operations. The opportunities currently under review include a potential collaboration with Phillips 66 on the possible construction of a large-scale renewable diesel plant in Washington state. We have not reached a definitive agreement with Phillips 66 and an agreement may never be reached. We are also evaluating a large-scale expansion of our renewable diesel facility in Geismar, Louisiana. If we elect to undertake either or both of these projects to expand our renewable diesel capacity, we will be required to make substantial capital expenditures, we may incur significant indebtedness and there is no assurance that the new or expanded operations will operate profitably or profitably enough to support the investment we make.

Perception about “food vs. fuel” could impact public policy which could impair our ability to operate at a profit and substantially harm our revenues and operating margins.
Some people believe that biomass-based diesel may increase the cost of food, as some feedstocks such as soybean oil used to make biomass-based diesel can also be used for food products. This debate is often referred to as “food vs. fuel.” This is a concern to the biomass-based diesel industry because biomass-based diesel demand is heavily influenced by government policy and if public opinion were to erode, it is possible that these policies could lose political support. These views could also negatively impact public perception of biomass-based diesel. Such claims have led some, including members of Congress, to urge the modification of current government policies which affect the production and sale of biofuels in the United States.

Concerns regarding the environmental impact of biomass-based diesel production could affect public policy which could impair our ability to operate at a profit and substantially harm our revenues and operating margins.
Under the Energy Independence and Security Act of 2007 ("EISA"), the EPA is required to produce a study every three years of the environmental impacts associated with current and future biofuel production and use, including effects on air and water quality, soil quality and conservation, water availability, energy recovery from secondary materials, ecosystem health and

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biodiversity, invasive species and international impacts. The only such triennial report was released in February 2012. The 2012 report concludes that (1) the extent of negative impacts to date are limited in magnitude and are primarily associated with the intensification of corn production; (2) whether future impacts are positive or negative will be determined by the choice of feedstock, land use change, cultivation and conservation practices; and (3) realizing potential benefits will require implementation and monitoring of conservation and best management practices, improvements in production efficiency, and implementation of innovative technologies at commercial scales. Should future EPA triennial studies, or other analyses find that biofuel production and use has resulted in, or could in the future result in, adverse environmental impacts, such findings could also negatively impact public perception and acceptance of biofuel as an alternative fuel, which also could result in the loss of political support. To the extent that state or federal laws are modified or public perception turns against biomass-based diesel, use requirements such as RFS2 and state tax incentives may not continue, which could materially harm our ability to operate profitably.

Nitrogen oxide emissions from biodiesel may harm its appeal as a renewable fuel and increase costs.
In some instances, biodiesel may increase emissions of nitrogen oxide as compared to petroleum-based diesel fuel, which could harm air quality. Nitrogen oxide is a contributor to ozone and smog. While newer diesel engines are believed to eliminate any such increase, emissions from older vehicles may decrease the appeal of biodiesel to environmental groups and agencies who have been historic supporters of the biodiesel industry, potentially harming our ability to market our biodiesel.
In addition, several states may act to regulate potential nitrogen oxide emissions from biodiesel. California recently adopted regulations that limit the volume of biodiesel that can be used or requires an additive to reduce potential emissions. In states where such an additive is required to sell biodiesel, the additional cost of the additive may make biodiesel less profitable or make biodiesel less cost competitive against petroleum-based diesel or renewable diesel, which would negatively impact our ability to sell biodiesel in such states and therefore have an adverse effect on our revenues and profitability.

We are dependent upon one supplier to provide hydrogen necessary to execute our renewable diesel production process and the loss of this supplier could disrupt our production process.
Our Geismar facility relies on one supplier to provide hydrogen necessary to execute the production process. Any disruptions to the hydrogen supply during production from this supplier will result in the shutdown of our Geismar plant operations. We are currently seeking additional hydrogen suppliers for our Geismar facility.

RISKS RELATED TO OUR INDEBTEDNESS

We and certain subsidiaries have indebtedness, which subjects us to potential defaults, that could adversely affect our ability to raise additional capital to fund our operations and limits our ability to react to changes in the economy or the biomass-based diesel industry.
At December 31, 2018, our total term debt before debt issuance costs was $185.8 million. This includes $75.5 million aggregate carrying value on our $96.3 million face amount, 4.00% convertible senior notes due in June 2036, which we refer to as the "2036 Convertible Senior Notes", and $66.4 million aggregate carrying value on our $67.5 million face value, 2.75% convertible senior notes due in June 2019, which we refer to as the "2019 Convertible Senior Notes". At December 31, 2018, our total term debt also includes borrowings at our Danville facility of $9.0 million, at our Ralston facility of $18.9 million, at our Grays Harbor facility of $8.8 million and at REG Capital LLC. of $7.2 million.
Our indebtedness could:
require us to dedicate a substantial portion of our cash flow from operations to payments of principal, interest on, and other fees related to such indebtedness, thereby reducing the availability of our cash flow to fund working capital and capital expenditures, and for other general corporate purposes;
increase our vulnerability to general adverse economic and biomass-based diesel industry conditions, including interest rate fluctuations, because a portion of our revolving credit facilities are and will continue to be at variable rates of interest;
limit our flexibility in planning for, or reacting to, changes in our business and the biomass-based diesel industry, which may place us at a competitive disadvantage compared to our competitors that have less debt; and
limit among other things, our ability to borrow additional funds.
Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness, including the 2036 Convertible Senior Notes and 2019 Convertible Senior Notes, depends on our future financial performance, which is subject to several factors including economic, financial, competitive and other factors beyond our control. Our business may not generate cash flow from operations in the future sufficient to satisfy our obligations under our indebtedness or any future indebtedness we may incur as well as our ability to make necessary capital expenditures. If we are unable to generate such cash

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flow, we may be required to adopt one or more alternatives, such as reducing or delaying investments or capital expenditures, selling assets, refinancing or obtaining additional capital on terms that may be onerous or highly dilutive. Our ability to refinance our existing or future indebtedness will depend on the conditions in the capital markets and our financial condition prior to maturity of the indebtedness.

Despite our current indebtedness levels, we may still incur significant additional indebtedness. Incurring more indebtedness could increase the risks associated with our substantial indebtedness.
We and our subsidiaries may be able to incur substantial additional indebtedness, including additional secured indebtedness, in the future. As of December 31, 2018, we had $114.9 million of undrawn availability under our lines of credit, subject to borrowing base limitations. In addition, the indentures governing our convertible notes do not prevent us from incurring additional indebtedness or other liabilities that constitute indebtedness. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

We are subject to counterparty risk with respect to the capped call transactions that we entered into in connection with the issuance of our 2019 Convertible Senior Notes.
In connection with the issuance of our 2019 Convertible Senior Notes, we entered into privately-negotiated capped call transactions with various counterparties. The counterparties to the capped call transactions are financial institutions, and we will be subject to the risk that they might default under the capped call transactions. Our exposure to the credit risk of the option counterparties will not be secured by any collateral. Recent global economic conditions have resulted in the actual or perceived failure or financial difficulties of many financial institutions. If any option counterparty becomes subject to insolvency proceedings, we will become an unsecured creditor in those proceedings, with a claim equal to our exposure at that time under our transactions with such option counterparty. Our exposure will depend on many factors, but generally, an increase in our exposure will be correlated to an increase in the market price and volatility of shares of our common stock. In addition, upon a default by any option counterparty, we may suffer more dilution than we currently anticipate with respect to our common stock. We can provide no assurances as to the financial stability or viability of the option counterparties.

We may not have the ability to raise the funds necessary to settle conversions of our convertible notes in cash or to repurchase the convertible notes for cash upon a fundamental change or on a repurchase date, and our future debt may contain limitations on our ability to repurchase the convertible notes.
Holders of the 2019 or 2036 Convertible Senior Notes will have the right to require us to repurchase their 2019 or 2036 Convertible Senior Notes upon the occurrence of a fundamental change at a repurchase price generally equal to 100% of their principal amount, plus accrued and unpaid interest, if any.
Holders of the 2036 Convertible Senior Notes will also have the right to require us to repurchase their notes on each of June 15, 2021, June 15, 2026 and June 15, 2031 at a repurchase price generally equal to 100% of their principal amount, plus accrued and unpaid interest, if any.
In addition, holders of the 2019 and 2036 Convertible Senior Notes have the right to convert their notes during any calendar quarter when the last reported sale price of our common stock for 20 trading days during a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the applicable conversion price, or $16.02 in the case of the 2019 Convertible Senior Notes and $14.01 in the case of the 2036 Convertible Senior Notes. Both series of notes became convertible due to the trading price of our common stock.
The 2019 Convertible Senior Notes will mature on June 15, 2019 and can be converted at any time on or after December 15, 2018. In accordance with the indenture governing the 2019 Convertible Senior Notes, we have elected to settle all conversions of each $1,000 principal amount of notes being converted on or after October 23, 2018, with $1,000 in cash and any conversion value in excess of that amount in shares of our common stock. For the 2036 Convertible Senior Notes, our current intent is to settle conversions using cash for the principal amount of convertible senior notes converted, with the remaining value satisfied at the Company's option in cash, stock or a combination of cash and stock. However, we may not have enough available cash or be able to obtain financing at the time we are required to make repurchases of the 2019 or 2036 Convertible Senior Notes upon a fundamental change or to settle conversion of the 2019 or 2036 Convertible Senior Notes in cash.
In addition, our ability to repurchase the 2019 or 2036 Convertible Senior Notes may be limited by law, by regulatory authority or by agreements governing our future indebtedness. Our failure to repurchase 2019 or 2036 Convertible Senior Notes at a time when the repurchase is required by the indenture would constitute a default under the indenture governing the 2019 or 2036 Convertible Senior Notes. A default under the indenture or the fundamental change itself could also lead to a default under agreements governing our other indebtedness. If the repayment of the related indebtedness were to be accelerated

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after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and repurchase the convertible notes.

Certain provisions in the indenture governing the 2019 or 2036 Convertible Senior Notes could delay or prevent an otherwise beneficial takeover or takeover attempt of us.
Certain provisions in the 2019 or 2036 Convertible Senior Notes and the indenture could make it more difficult or more expensive for a third party to acquire us. For example, if a takeover would constitute a fundamental change, holders of the 2019 or 2036 Convertible Senior Notes will have the right to require us to repurchase their 2019 or 2036 Convertible Senior Notes in cash. In addition, if a takeover constitutes a make-whole fundamental change, we may be required to increase the conversion rate for holders who convert their 2019 or 2036 Convertible Senior Notes in connection with such takeover. In either case, and in other cases, our obligations under the 2019 or 2036 Convertible Senior Notes and the indenture could increase the cost of acquiring us or otherwise discourage a third party from acquiring us or removing incumbent management.

We are a holding company and there are limitations on our ability to receive dividends and distributions from our subsidiaries.
All of our principal assets, including our biomass-based diesel production facilities, are owned by subsidiaries and some of these subsidiaries are subject to loan covenants that generally restrict them from paying dividends, making distributions or making loans to us or to any other subsidiary. These limitations will restrict our ability to repay indebtedness, finance capital projects or pay dividends to stockholders from our subsidiaries’ cash flows from operations.

Our debt agreements impose significant operating and financial restrictions on our subsidiaries, which may prevent us from capitalizing on business opportunities.
Certain of our revolving and term credit agreements, including our M&L and Services Revolver, impose significant operating and financial restrictions on certain of our subsidiaries. These restrictions limit certain of our subsidiaries’ ability, among other things, to:
incur additional indebtedness or issue certain disqualified stock and preferred stock;
place restrictions on the ability of certain of our subsidiaries to pay dividends or make other payments to us;
engage in transactions with affiliates;
sell certain assets or merge with or into other companies;
guarantee indebtedness; and
create liens.
When (and for as long as) the availability under the M&L and Services Revolver is less than a specified amount for a certain period of time, funds deposited into deposit accounts used for collections will be transferred on a daily basis into a blocked account with the administrative agent and applied to prepay loans under the M&L and Services Revolver.
As a result of these covenants and restrictions, we may be limited in how we conduct our business and we may be unable to raise additional debt or equity financing to compete effectively or to take advantage of new business opportunities. The terms of any future indebtedness we may incur could include more restrictive covenants. There is no assurance that we will be able to maintain compliance with these covenants in the future and, if we fail to do so, that we will be able to obtain waivers from the lenders and/or amend the covenants.
There are limitations on our ability to incur the full $150.0 million of commitments under the M&L and Services Revolver. Borrowings under our M&L and Services Revolver are limited by a specified borrowing base consisting of a percentage of eligible accounts receivable and inventory, less customary reserves. In addition, under the M&L and Services Revolver, a monthly fixed charge coverage ratio would become applicable if excess availability under the M&L and Services Revolver is less than 10% of the total $150 million of current revolving loan commitments, or $15 million. As of December 31, 2018, availability under the M&L and Services Revolver was approximately $114.9 million. However, it is possible that excess availability under the Revolving Credit could fall below the 10% threshold in a future period. If the covenant trigger were to occur, our subsidiaries who are the borrowers under the M&L and Services Revolver would be required to satisfy and maintain on the last day of each month a fixed charge coverage ratio of at least 1.0x for the preceding twelve month period.
As of December 31, 2018, the fixed charge coverage ratio for our M&L and Services Revolver was approximately 0.445, which was below the minimum amount required for compliance with this ratio. However, as noted above, we are not required to comply with the minimum fixed charge covenant of 1.0 unless availability under the M&L and Services Revolver drops below the agreed threshold. Our ability to meet the required fixed charge coverage ratio can be affected by events beyond our

22



control, and we cannot assure you that we will meet this ratio. A breach of any of these covenants would result in a default under the M&L and Services Revolver.

RISKS RELATED TO OUR COMMON STOCK

The market price for our common stock may be volatile.
The market price for our common stock is likely to be highly volatile and subject to wide fluctuations in response to factors including the following:
actual or anticipated fluctuations in our financial condition and operating results;
changes in the performance or market valuations of other companies engaged in our industry;
issuance of new or updated research reports by securities or industry analysts;
changes in financial estimates by us or of securities or industry analysts;
investors’ general perception of us and the industry in which we operate;
changes in the political climate in the industry in which we operate, existing laws, regulations and policies applicable to our business and products, including RFS2, and the continuation or adoption or failure to continue or adopt renewable energy requirements and incentives, including the BTC;
other regulatory developments in our industry affecting us, our customers or our competitors;
announcements of technological innovations by us or our competitors;
announcement or expectation of additional financing efforts, including sales or expected sales of additional common stock;
additions or departures of key management or other personnel;
litigation;
inadequate trading volume;
general market conditions in our industry;
whether our shares are included in stock market indexes such as the S&P SmallCap 600 index; and
general economic and market conditions, including continued dislocations and downward pressure in the capital markets.
In addition, stock markets experience significant price and volume fluctuations from time to time that are not related to the operating performance of particular companies. These market fluctuations may have material adverse effect on the market price of our common stock.

We may issue additional common stock as consideration for future investments or acquisitions.
We have issued in the past, and may issue in the future, our securities in connection with investments and acquisitions. Our stockholders could suffer significant dilution, from our issuances of equity or convertible debt securities. Any new equity securities we issue could have rights, preferences and privileges superior to those of holders of our common stock. The amount of our common stock or securities convertible into or exchangeable for our common stock issued in connection with an investment or acquisition could constitute a material portion of our then outstanding common stock.

If we fail to maintain effective internal control over financial reporting, we might not be able to report our financial results accurately or prevent fraud. In that case, our stockholders could lose confidence in our financial reporting, which would harm our business and could negatively impact the value of our stock.
Effective internal controls are necessary for us to provide reliable financial reports and prevent fraud. The process of maintaining our internal controls may be expensive and time consuming and may require significant attention from management. Although we have concluded as of December 31, 2018 that our internal control over financial reporting provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, because of its inherent limitations, internal control over financial reporting may not prevent or detect fraud or misstatements.
Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our results of operations or cause us to fail to meet our reporting obligations. If we or our independent registered public accounting firm discover a material weakness, the disclosure of that fact could harm the value of our stock and our business.

Delaware law and our amended and restated certificate of incorporation and bylaws contain anti-takeover provisions that could delay or discourage takeover attempts that stockholders may consider favorable.
Provisions in our amended and restated certificate of incorporation and bylaws may have the effect of delaying or preventing a change of control or changes in our management. These provisions include the following:

23



the right of the board of directors to elect a director to fill a vacancy created by the expansion of the board of directors;
the requirement for advance notice for nominations for election to the board of directors or for proposing matters that can be acted upon at a stockholders’ meeting;
the ability of the board of directors to alter our bylaws without obtaining stockholder approval;
the ability of the board of directors to issue, without stockholder approval, up to 10,000,000 shares of preferred stock with rights set by the board of directors, which rights could be senior to those of common stock;
a classified board;
the required approval of holders of at least two-thirds of the shares entitled to vote at an election of directors to adopt, amend or repeal our bylaws or amend or repeal the provisions of our amended and restated certificate of incorporation regarding the classified board, the election and removal of directors and the ability of stockholders to take action by written consent; and
the elimination of the right of stockholders to call a special meeting of stockholders and to take action by written consent.
In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law ("DGCL"). These provisions may prohibit or restrict large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us. These provisions in our amended and restated certificate of incorporation and bylaws and under Delaware law could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock in the future and result in our market price being lower than it would without these provisions.
ITEM 1B.
Unresolved Staff Comments
None.
ITEM 2.
Properties
The following tables list each of our owned North American and European production facilities and their location, use, and nameplate production capacity. Each facility listed below is used by our Biomass-based diesel Segment, except for the Okeechobee, Florida facility.
PRODUCTION FACILITIES - NORTH AMERICA
Location
 
Use
 
Nameplate
Production
Capacity
(mmgy)
Ralston, Iowa
 
Biodiesel production
 
30
Seabrook, Texas
 
Biodiesel production
 
35
Danville, Illinois
 
Biodiesel production
 
45
Newton, Iowa
 
Biodiesel production
 
30
Seneca, Illinois
 
Biodiesel production
 
60
Albert Lea, Minnesota
 
Biodiesel production
 
30
New Boston, Texas
 
Biodiesel production
 
15
Mason City, Iowa
 
Biodiesel production
 
30
Geismar, Louisiana*
 
Renewable diesel production
 
75
Grays Harbor, Washington
 
Biodiesel production
 
100
DeForest, Wisconsin
 
Biodiesel production
 
20
Okeechobee, Florida
 
Fermentation facility
 
N/A

* This facility produces renewable diesel, naphtha, and liquid petroleum gas.

24



PRODUCTION FACILITIES - EUROPE
Location
 
Use
 
Nameplate
Production
Capacity
(mmgy)
Emden, Germany
 
Biodiesel production
 
27
Oeding, Germany
 
Biodiesel production
 
23
We own our corporate headquarters located at 416 South Bell Avenue, Ames, Iowa 50010, comprised of 60,480 square feet of office and laboratory space; as well as two other buildings located at 300 South Bell Avenue, Ames, Iowa 50010 and at 215 Alexander Avenue, Ames, Iowa 50010, which have a combined 26,837 square feet of office space.
ITEM 3.
Legal Proceedings
Neither the Company nor any subsidiary of the Company is a party to any material pending legal or governmental proceeding, nor is any of the Company's property the subject of any material pending legal proceeding, except ordinary routine legal or governmental proceedings arising in the ordinary course of the Company's business and incidental to the Company's business, none of which is expected to have a material adverse impact upon the Company's business, financial position or results of operations.
ITEM 4.
Mine Safety Disclosures
None.

PART II
ITEM 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market For Our Common Equity
Our common stock trades on the NASDAQ Global market under the ticker symbol "REGI".
Holders
As of February 28, 2019, there were approximately 1,762 holders of record of our common stock.
Performance Graph
The following performance graph is not “soliciting material,” is not deemed filed with the SEC, and is not to be incorporated by reference into any of our filings under the Securities Act of 1933 or the Securities Exchange Act of 1934, as amended, respectively.
On May 15, 2018, we were added to the S&P SmallCap 600 index by Nasdaq. The following graph shows a comparison of the cumulative total returns for the last 5 years to December 31, 2018, for us, the Elements MLCX Biofuels ETN Index, the Russell 3000 Index and the S&P SmallCap 600. The graph assumes that $100 was invested on January 19, 2012 in our common stock, the Elements MLCX Biofuels ETN Index and the Russell 3000 Index, and that all dividends were reinvested.

25



a2018stockperformancegraph02.jpg
 
01/19/2012

 
12/31/2014

 
12/31/2015

 
12/31/2016

 
12/31/2017

 
12/31/2018

REGI
$
100.00

 
$
97.10

 
$
92.50

 
$
97.00

 
$
118.00

 
$
257.00

Elements MLCX Biofuels ETN
100.00

 
84.57

 
72.32

 
73.77

 
67.50

 
60.37

Russell 3000
100.00

 
157.50

 
155.58

 
171.77

 
204.16

 
189.89

S&P SmallCap 600
100.00

 
158.93

 
153.59

 
191.60

 
214.07

 
193.19

Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
In December 2017, the Company's board of directors approved a repurchase program (the "2017 Program") of up to $75.0 million of the Company's 2.75% Convertible Senior Notes due 2019 and/or shares of common stock. In June 2018, the Company's board of directors approved another repurchase program of up to $75.0 million of the Company's convertible notes and/or shares of common stock (the "2018 Program"). Under these programs, the Company may repurchase convertible notes or shares from time to time in open market transactions, privately negotiated transactions or by other means. The timing and amount of repurchase transactions under each program are determined by the Company's management based on its evaluation of market conditions, share price, bond price, legal requirements and other factors. On January 29, 2019, the Company's Board of Directors authorized an additional $75.0 million to repurchase convertible notes and/or shares of Common Stock.
The Company made no share repurchases under the 2018 Program during the quarter ended December 31, 2018.
During the quarter ended December 31, 2018, the Company used approximately $51.5 million under the 2018 Program to repurchase $21.2 million principal amount of its 2036 Convertible Senior Notes. At December 31, 2018, the remaining amount under the 2018 Program was approximately $7.4 million.
ITEM 6.
Selected Financial Data
The following selected consolidated financial data should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this annual report.

26



The selected consolidated balance sheet data as of December 31, 2018 and 2017, and the selected consolidated statements of operations data for each year ended December 31, 2018, 2017 and 2016, have been derived from our audited consolidated financial statements which are included elsewhere in this annual report. The selected consolidated balance sheet data as of December 31, 2016, 2015 and 2014, and the selected consolidated statements of operations data for the years ended December 31, 2015 and 2014 have been derived from our audited consolidated financial statements not included in this annual report.
 
Year Ended December 31,
 
2018 (1)
 
2017 (2)
 
2016 (3)
 
2015 (4)
 
2014 (5)
 
(In thousands, except per share amounts)
Consolidated Statements of Operations Data:
 
 
 
 
 
 
 
 
 
Total revenues from continuing operations
$
2,382,987

 
$
2,154,655

 
$
2,039,232

 
$
1,387,344

 
$
1,273,831

Net income (loss) from continuing operations attributable to the company's common stockholders
295,804

 
(66,279
)
 
62,204

 
(105,088
)
 
82,400

Net loss from discontinued operations attributable to the company's common stockholders
(11,312
)
 
(12,800
)
 
(19,128
)
 
(46,303
)
 
(806
)
 
 
 
 
 
 
 
 
 
 
Net income (loss) per share from continuing operations attributable to common stockholders
 
 
 
 
 
 
 
 
 
Basic
$
7.85

 
$
(1.71
)
 
$
1.52

 
$
(2.39
)
 
$
2.02

Diluted
$
6.78

 
$
(1.71
)
 
$
1.52

 
$
(2.39
)
 
$
2.01

Net loss per share from discontinued operations attributable to common stockholders
 
 
 
 
 
 
 
 
 
Basic
$
(0.30
)
 
$
(0.33
)
 
$
(0.47
)
 
$
(1.05
)
 
$
(0.02
)
Diluted
$
(0.30
)
 
$
(0.33
)
 
$
(0.47
)
 
$
(1.05
)
 
$
(0.02
)
 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheet Data:
 
 
 
 
 
 
 
 
 
Total assets
$
1,107,096

 
$
1,005,596

 
$
1,136,603

 
$
1,223,620

 
$
1,367,736

Long-term debt
33,421

 
208,536

 
196,203

 
247,251

 
242,031


(1)
In the first quarter of 2018, we adopted Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606). The implementation of the new standard did not have any material impact on the measurement or recognition of revenue of prior periods, however additional disclosures have been added as further described in Note 2 of Item 8 - Financial Statements and Supplementary Data. The long-term debt at December 31, 2018 does not include the 2019 Convertible Senior Notes of $66,361 that becomes due in June 2019 and the 2036 Convertible Senior Notes of $75,477 that was reclassified to current as the early conversion event was met based on our stock price. In the fourth quarter of 2018, our Board of Directors authorized us to pursue a plan to sell the REG Life Sciences' core assets and business, which represents a strategic shift in our business. As a result, REG Life Sciences business, valued at selling price less estimated costs to sell, are classified as discontinued operations in 2018. All prior period disclosures below have been recast to present results on a comparable basis.
(2)
Includes the impact of the impairment of our New Orleans facility and the “H.R. 1”, formerly known as the “Tax Cuts and Jobs Act” signed into law on December 22, 2017 as further described in Note 2 and Note 13, respectively, of Item 8 - Financial Statements and Supplementary Data.
(3)
Includes issuance of the convertible senior notes on June 2, 2016 and impact of the impairment of our Emporia facility as further described in Note 12 and Note 2, respectively, of Item 8 - Financial Statements and Supplementary Data.
(4)
Includes the impact of a full write-off of goodwill in the Biomass-based Diesel and Renewable Chemicals reporting units.
(5)
Includes the issuance of the 2019 Convertible Senior Notes on June 3, 2014.

ITEM 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto that appear elsewhere in this report. This discussion contains forward-looking statements reflecting our current

27



expectations that involve risks and uncertainties. Actual results may differ materially from those discussed in these forward-looking statements due to a number of factors, including those set forth in the section entitled “Risk Factors” and elsewhere in this report.
Overview
We focus on providing cleaner, lower carbon transportation fuels. We are North America's largest producer of advanced biofuels. We utilize a nationwide production, distribution and logistics system as part of an integrated value chain model designed to convert natural fats, oils and greases into advanced biofuels. We believe our fully integrated approach, which includes acquiring feedstock, managing biorefinery facility construction and upgrades, operating biorefineries, and distributing fuel through a network of terminals, positions us to serve the market for cleaner transportation fuels. In May 2018, we launched our latest innovation in diesel fuel, REG Ultra CleanTM Diesel. REG Ultra CleanTM Diesel is among the lowest emission diesel fuels on the market today.
We own and operate a network of 14 biorefineries. Twelve biorefineries are located in the United States and two in Germany. Twelve biorefineries produce biodiesel, one produces renewable diesel (“RD”), and one is a fermentation facility. Our thirteen biomass-based diesel production facilities have an aggregate nameplate production capacity of 520 million gallons per year (“mmgy”).
We are a lower-cost, lower carbon biomass-based diesel producer. We primarily produce our biomass-based diesel from a wide variety of lower-cost, lower carbon feedstocks, including inedible corn oil, used cooking oil and inedible animal fat. We produce a portion of our biomass-based diesel from virgin vegetable oils, such as soybean oil or canola oil, which tend to be higher in price. We believe our ability to process a wide variety of feedstocks at most of our facilities provides us with a cost advantage over many biomass-based diesel producers, particularly those that rely primarily on higher cost virgin vegetable oils.
We also sell petroleum-based heating oil and diesel fuel, which enables us to offer a variety of fuel products to a broader customer base. We sell heating oil and ultra-low sulfur diesel, or ULSD, at terminals throughout the northeastern U.S. as well as BioHeat® blended heating fuel at one of these terminal locations. In 2018, we expanded our sales of biofuel blends to Midwest and West Coast terminal locations and look to potentially expand in other areas across North America and internationally.
In October 2018, we announced that we are collaborating with Phillips 66 on the possible construction of a large-scale renewable diesel plant in Washington state. The plant would utilize our propriety BioSynfining® technology for the production of renewable diesel.We have not reached a definitive agreement with Phillips 66 with respect to this potential joint development project and there is no assurance that an agreement will be reached.
During 2018, we sold 649 million gallons of fuel, which included 45 million biomass-based gallons we purchased from third parties, 45 million gallons produced by our facilities in Germany and 119 million petroleum-based diesel gallons. During 2017, we sold 587 million gallons, including 52 million gallons we purchased from third parties and resold, 38 million biomass-based diesel gallons produced by our facilities in Germany and 83 million petroleum-based diesel gallons.
In the fourth quarter of 2018, concluding a comprehensive strategic assessment of our development-stage industrial biotechnology business, our Board of Directors authorized us to pursue a plan to sell the core assets of REG Life Sciences, which have comprised our Renewable Chemicals segment. As a result, the former Renewable Chemicals segment has been valued at the estimated proceeds from the sale less costs to sell, and the operations of the Renewable Chemicals segment have been classified as discontinued operations.
Our businesses are organized into two reportable segments - the Biomass-based Diesel segment and the Services segment.
Biomass-based Diesel Segment
Our Biomass-based Diesel segment includes:
the operations of the following biomass-based diesel production refineries:
a 30 mmgy nameplate biodiesel production facility located in Ralston, Iowa;
a 35 mmgy nameplate biodiesel production facility located near Houston, Texas;
a 45 mmgy nameplate biodiesel production facility located in Danville, Illinois;
a 30 mmgy nameplate biodiesel production facility located in Newton, Iowa;
a 60 mmgy nameplate biodiesel production facility located in Seneca, Illinois;
a 30 mmgy nameplate biodiesel production facility located near Albert Lea, Minnesota;
a 15 mmgy nameplate biodiesel production facility located in New Boston, Texas;
a 30 mmgy nameplate biodiesel production facility located in Mason City, Iowa;

28



a 75 mmgy nameplate renewable diesel production facility located in Geismar, Louisiana;
a 27 mmgy nameplate biodiesel production facility located in Emden, Germany;
a 23 mmgy nameplate biodiesel production facility located in Oeding, Germany;
a 100 mmgy nameplate biodiesel production facility located in Grays Harbor, Washington; and
a 20 mmgy nameplate biodiesel production facility located in DeForest, Wisconsin.
purchases and resales of biomass-based diesel, petroleum-based diesel, RINs and LCFS credits, and raw material feedstocks acquired from third parties;
sales of biomass-based diesel produced under toll manufacturing arrangements with third party facilities using our feedstocks; and
incentives received from federal and state programs for renewable fuels.
We derive a small portion of our revenues from the sale of co-products of the biomass-based diesel production process. In 2018 and 2017, our revenues from the sale of co-products were less than five percent of our total Biomass-based diesel segment revenues. During 2018 and 2017, revenues from the sale of petroleum-based heating oil and diesel fuel acquired from third parties, along with the sale of these items further blended with biodiesel produced by our facilities or purchased from third parties, were approximately 10% and 7% of our total revenues, respectively.
In accordance with EPA regulations, we generate 1.5 to 1.7 RINS, for each gallon of biomass-based diesel we produce. RINs are used to track compliance with Renewable Fuel Standard, or RFS2, using the EPA moderated transaction system, or EMTS. RFS2 allows us to attach between zero and 2.5 RINs to any gallon of biomass-based diesel we sell. When we attach RINs to a sale of biomass-based diesel gallons, a portion of our selling price for a gallon of biomass-based diesel is generally attributable to RFS2 compliance, but no cost is allocated to the RINs generated by our biomass-based diesel production because RINs are a form of government incentive and not a result of the physical attributes of the biomass-based diesel production. In addition, RINs, once obtained through the production and sale of gallons of biomass-based diesel, may be separated by the acquirer and sold separately. We regularly obtain RINs from third parties for resale, and the value of these RINs is reflected in “Prepaid expenses and other assets” on our Consolidated Balance Sheet. At each balance sheet date, this RIN inventory is valued at the lower of cost or net realizable value and resulting adjustments are reflected in our cost of goods sold for the period. The cost of RINs obtained from third parties is determined using the average cost method. Because we do not allocate costs to RINs generated by our biomass-based diesel production, fluctuations in the value of our RIN inventory represent fluctuations in the value of RINs we have obtained from third parties. At December 31, 2018, we had approximately 10.3 million biomass-based diesel RINs and 3.9 million advanced biofuel RINs available to be sold, as compared to 37.8 million biomass-based diesel RINs and 1.2 million advanced biofuel RINs held for sale at December 31, 2017. According to the Oil Pricing Information System ("OPIS"), the median closing sales price at December 31, 2018 was $0.55 and $0.51 for biomass-based diesel RINs and advanced biofuel RINs, respectively, compared to $1.05 and $1.06, at December 31, 2017, per biomass-based diesel RIN and advanced biofuel RIN, respectively. We believe that the decrease in RIN value during 2018 has been influenced by the relatively wider spread between biomass-based diesel prices and feedstock prices and record levels of Smaller Refiner Exemptions from RIN compliance requirements for 2016 and 2017.
We generate Low Carbon Fuel Standard credits for our low carbon fuels or blendstocks when our qualified low carbon fuels are imported into states that have adopted an LCFS program. As a result, a portion of the selling price for a gallon of biomass-based diesel sold into an LCFS market is also attributable to LCFS compliance. Like RINs, LCFS credits that we generate are a form of government incentive and not a result of the physical attributes of the biomass-based diesel production. Therefore, no cost is allocated to the LCFS credit when it is generated, regardless of whether the LCFS credit is transferred with the biomass-based diesel produced or held by us. At December 31, 2018, we held for sale approximately 29,843 California and 25,891 Oregon LCFS credits, compared to 5,700 California and 0 Oregon LCFS credits at December 31, 2017. According to OPIS, the median closing price at December 31, 2018 and December 31, 2017 was $195.00 and $113.00, respectively, per California LCFS credit. According to OPIS, the median closing price at December 31, 2018 was $137.50 per Oregon LCFS credit. The increase in LCFS prices was largely attributable to growing demand for LCFS credits.
Services Segment
Our Services segment, which primarily provides services to our Biomass-based Diesel Segment, includes:
biomass-based diesel facility management and operational services, whereby we provide day-to-day management and operational services to biomass-based diesel production facilities; and
construction management services, whereby we act as the construction management and general contractor for the construction of biomass-based diesel production facilities.

29



During recent years, we have utilized our construction management expertise internally to upgrade our facilities, such as our facilities located in Ralston, Albert Lea, New Boston, Mason City and Newton. In March 2018, we completed the expansion project at our Ralston facility. In June 2017, we completed the acquisition of approximately 82 acres of land at and in close proximity to our Geismar, Louisiana biorefinery. The purchase included the acquisition of land we previously leased for our Geismar operations and approximately 61 additional acres in parcels adjacent to and near the facility. We plan to improve and utilize the new acreage to support existing production capacity and for future expansion opportunities using the Services segment.
Factors Influencing Our Results of Operations
The principal factors affecting our results of operations and financial conditions are the market prices for biomass-based diesel and the feedstocks used to produce biomass-based diesel, as well as governmental programs designed to create incentives for the production and use of cleaner renewable fuels.
Governmental programs favoring biomass-based diesel production and use
Biomass-based diesel has historically been more expensive to produce than petroleum-based diesel. The biomass-based diesel industry’s growth has largely been the result of federal and state programs that require or incentivize the production and use of biomass-based diesel, which allows biomass-based diesel to be price-competitive with petroleum-based diesel.
RFS2 was implemented in 2010, stipulating volume requirements for the amount of biomass-based diesel and other advanced biofuels that must be utilized in the United States each year. Under RFS2, Obligated Parties, including petroleum refiners and fuel importers, must show compliance with these standards. Currently, biodiesel and renewable diesel satisfy three categories of an Obligated Party’s annual renewable fuel required volume obligation, or RVO—biomass-based diesel, advanced biofuel and renewable fuel. The final RVO targets for the biomass-based diesel and advanced biofuels volumes for the years 2015 to 2020 as set by the EPA are as follows:
 
2015
2016
2017
2018
2019
2020
Biomass-based Diesel
1.73 billion gallons
1.90 billion gallons
2.00 billion gallons
2.10 billion gallons
2.10 billion gallons
2.43 billion gallons
Total Advanced Biofuels
2.88 billion RINs*
3.61 billion RINs*
4.28 billion RINs*
4.29 billion RINs*
4.92 billion RINs*
**
*Ethanol equivalent gallons
**To be established by EPA in a rule making later in 2019
The federal biodiesel mixture excise tax credit, or the BTC, has historically provided a $1.00 refundable tax credit per gallon to the first blender of biomass-based diesel with petroleum-based diesel fuel. The BTC became effective January 1, 2005, but since January 1, 2010 it has been allowed to lapse and then been reinstated a number of times. For example, the BTC lapsed on January 1, 2014, was retroactively reinstated for 2014 on December 19, 2014 and then lapsed again on January 1, 2015. On December 18, 2015, the BTC was retroactively reinstated for 2015 and extended for 2016. The BTC again lapsed on January 1, 2017 and was reinstated on a retroactive basis for 2017 on February 9, 2018. It is not currently in effect for 2018 or 2019.
As a result of this history of retroactive reinstatement of the BTC, we and many other biomass-based diesel producers have adopted contractual arrangements with customers and vendors specifying the allocation and sharing of any retroactively reinstated incentive. The reinstatement of the 2017 BTC resulted in a $205 million net benefit to our net income for the year ended December 31, 2018 and Adjusted EBITDA for the year ended December 31, 2017, with another $11 million related to products delivered and sales recognized in the first quarter of 2018. It is uncertain whether the BTC will be reinstated for 2018 or later years and if reinstated, whether it will be reinstated retroactively or on the same terms. The modification or failure to reinstate the BTC would have a material adverse effect on our financial results. As of December 31, 2018, we estimate that if the BTC is reinstated on the same terms as in 2017, our Adjusted EBITDA for business conducted in the year ended December 31, 2018 would increase by approximately $237 million.
Biomass-based diesel and feedstock price fluctuations
Our operating results generally reflect the relationship between the price of biomass-based diesel, including credits and incentives and the price of feedstocks used to produce biomass-based diesel.
Biomass-based diesel is a cleaner low carbon, renewable alternative to petroleum-based diesel fuel and is primarily sold to the end user after it has been blended with petroleum-based diesel fuel. Biomass-based diesel prices have historically been heavily influenced by petroleum-based diesel fuel prices. Accordingly, biomass-based diesel prices have generally been

30



impacted by the same factors that affect petroleum prices, such as crude oil supply and demand balance, worldwide economic conditions, wars and other political events, OPEC production quotas, changes in refining capacity and natural disasters.
Regulatory and legislative factors also influence the price of biomass-based diesel. Biomass-based diesel RIN pricing, a value component that was introduced via RFS2 in July 2010, has had a significant impact on our biomass-based diesel pricing. The following table shows for 2016, 2017 and 2018 the high and low average monthly contributory value of RINs, as reported by OPIS, to the average B100 spot price of a gallon of biodiesel, as reported by The Jacobsen in terms of dollars per gallon.
rinpricevsb100pricechart2018.jpg
Value of RINs acquired from third parties and held in inventory were volatile in 2018 and resulted in a $7.0 million write-down to the lower of cost or net realizable value for the year ended December 31, 2018. The fluctuations in the value of RINs during 2017 and 2016 resulted in write-downs of $4.5 million and $19.4 million, respectively, on RIN inventory acquired from third parties. At December 31, 2018, the write-down to lower of cost or net realizable value of RINs was $0.6 million. See “Note 10 – Other Assets” to our Consolidated Financial Statements. We enter into forward contracts to sell RINs and we use risk management position limits to manage RIN exposure.
During 2018, feedstock expense accounted for 78% of our direct production cost, while methanol and chemical catalysts expense accounted for 5% and 3% of our costs of goods sold, respectively.
Feedstocks for biomass-based diesel production, such as inedible oil, used cooking oil, inedible animal fat, canola oil and soybean oil are commodities and market prices for them will be affected by a wide range of factors unrelated to the price of biomass-based diesel and petroleum-based diesel. There are a number of factors that influence the supply and price of our feedstocks, such as the following: biomass-based diesel demand; export demand; government policies and subsidies; weather conditions; ethanol production; cooking habits and eating habits; number of restaurants near collection facilities; hog/beef/poultry supply and demand; palm oil supply; soybean meal demand and/or production, and crop production both in the U.S. and South America.
During 2018 and 2017, 77% and 73% of the feedstocks used in our operations, respectively, were comprised of inedible corn oil, used cooking oil and inedible animal fats with the remainder coming from virgin vegetable oils.
The graph below illustrates the spread between the cost of producing one gallon of biodiesel made from soybean oil to the cost of producing one gallon of biodiesel made from the specified lower-cost feedstock for the period January 2016 to December 2018. The results were derived using assumed conversion factors for the yield of each feedstock and subtracting the cost of producing one gallon of biodiesel made from each respective lower-cost feedstock from the cost of producing one gallon of biodiesel made from soybean oil.

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graphsbospread2018a02.jpg

(1)
Used cooking oil prices ("UCO") are based on the monthly average of the daily low sales price of Missouri River yellow grease as reported by The Jacobsen (based on 8.5 pounds per gallon).
(2)
Inedible corn oil ("ICO") prices are reported as the monthly average of the daily distillers’ corn oil market values delivered to Illinois as reported by The Jacobsen (based on 8.2 pounds per gallon).
(3)
Choice white grease ("CWG") prices are based on the monthly average of the daily low prices of Missouri River choice white grease as reported by The Jacobsen (based on 8.0 pounds per gallon).
(4)
Soybean oil (crude) ("SBO") prices are based on the monthly average of the daily closing sale price of the nearby soybean oil contract as reported by CBOT (based on 7.5 pounds per gallons).
Our results of operations generally will benefit when the spread between biomass-based diesel prices and feedstock prices widens and will be harmed when this spread narrows. The following graph shows feedstock cost data for choice white grease and soybean oil on a per gallon basis compared to the per gallon sale price data for biodiesel, and the spread between biodiesel and each of soybean oil and choice white grease from January 2016 to December 2018.
graphspreadpricing2018a01.jpg


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(1)
Biodiesel prices are based on the monthly average of the midpoint of the high and low prices of B100 (Upper Midwest) as reported by The Jacobsen.
(2)
Soybean oil (crude) prices are based on the monthly average of the daily closing sale price of the nearby soybean oil contract as reported by CBOT (based on 7.5 pounds per gallon).
(3)
Choice white grease prices are based on the monthly average of the daily low price of Missouri River choice white grease as reported by The Jacobsen (based on 8.0 pounds per gallon).
(4)
Spread between biodiesel price and choice white grease price.
(5)
Spread between biodiesel price and soybean oil (crude) price.
During 2018, NY Harbor ULSD prices ranged from a low of $1.66 per gallon in late December to a high of $2.44 per gallon in early October with an average price for the year of $2.10 per gallon. Energy prices decreased in February but increased at a steady pace until the early part of the last quarter. Prices decreased precipitously during mid to late November and this trend continued through the end of the year. During the first three quarters of 2018, there was consistently strong demand for diesel fuel and OPEC's crude oil production quotas contributed to price increases until the fourth quarter. In the fourth quarter the ULSD market responded to oversupply of crude oil in the global market as well as fears of global economic slowdown in 2019 and regional trade tension.
Animal fat and vegetable oil production have both increased in 2018, which contributed to lower feedstock prices during the year. Soybean oil prices ranged from a high of $0.3376 per pound in January to a low of $0.2696 per pound in November with an average price for the year of $0.2987 per pound. The soybean oil market responded to a near-record crush in the United States and significantly lower soybean exports, and it trended upward at the end of the fourth quarter of 2018 based on increased optimism about trade negotiations between the United States and China. Choice white grease prices ranged from a low of $0.1600 in February to a high of $0.2575 per pound in June with an average price for the year of $0.2024 per pound. Relatively low priced feed cost along with continued strong demand for pork and beef has continued to lead to expansions in the U.S. hog and cattle industries. Both hog and cattle production numbers in 2018 were higher than the prior year resulting in lower prices for animal fats.
Risk Management
The profitability of producing biomass-based diesel largely depends on the spread between prices for feedstocks and biomass-based diesel, including incentives, each of which is subject to fluctuations due to market factors and each of which is not significantly correlated. Adverse price movements for these commodities directly affect our operating results. We attempt to protect cash margins for our own production and our third-party trading activity by entering into risk management contracts that mitigate the impact on our margins from price volatility in feedstocks and biomass-based diesel. We create offsetting positions by using a combination of forward fixed-price physical purchases and sales contracts on feedstock and biomass-based diesel and risk management futures contracts, swaps and options primarily on the New York Mercantile Exchange NY Harbor ULSD and CBOT Soybean Oil; however, the extent to which we engage in risk management activities varies substantially from time to time, and from feedstock to feedstock, depending on market conditions and other factors. In making risk management decisions, we utilize research conducted by outside firms to provide additional market information in addition to our internal research and analysis.
Inedible corn oil, used cooking oil, inedible animal fat, canola oil and soybean oil are the primary feedstocks we used to produce biomass-based diesel in 2016, 2017 and 2018. We utilize several varieties of inedible animal fat, such as beef tallow, choice white grease and poultry fat derived from livestock. There is no established futures market for these lower-cost feedstocks. The purchase prices for lower-cost feedstocks are generally set on a negotiated flat price basis or spread to a prevailing market price reported by the USDA price sheet or The Jacobsen. Our efforts to risk manage against changing prices for inedible corn oil, used cooking oil and inedible animal fat have involved entering into futures contracts, swaps or options on other commodity products, such as CBOT soybean oil and New York Mercantile Exchange NY Harbor ULSD. However, these products do not always experience the same price movements as lower-cost feedstocks, making risk management for these feedstocks challenging. We manage feedstock supply risks related to biomass-based diesel production in a number of ways, including, where available, through long-term supply contracts. The purchase price for soybean oil under these contracts may be indexed to prevailing CBOT soybean oil market prices with a negotiated market basis. We utilize futures contracts, swaps and options to risk manage, or lock in, the cost of portions of our future feedstock requirements generally for varying periods up to one year.
Our ability to mitigate our risk of falling biomass-based diesel prices is limited. We have entered into forward contracts to supply biomass-based diesel. However, pricing under these forward sales contracts generally has been indexed to prevailing market prices, as fixed price contracts for long periods on acceptable terms have generally not been available. There is no established derivative market for biomass-based diesel in the United States. Our efforts to hedge against falling biomass-based diesel prices generally involve entering into futures contracts, swaps and options on other commodity products, such as diesel

33



fuel and New York Mercantile Exchange NY Harbor ULSD. However, price movements on these products are not highly correlated to price movements of biomass-based diesel.
We generate 1.5 to 1.7 biomass-based diesel RINs for each gallon of biomass-based diesel we produce and sell. We also obtain RINs from third party transactions which we hold for resale. There is no effective established futures market for biomass-based diesel RINs, which severely limits the ability to risk manage the price of RINs. We enter into forward contracts to sell RINs, and we use risk management position limits to manage RIN exposure, however, pricing under those forward contracts generally has been indexed to prevailing market prices as fixed price contracts for long periods have generally not been available.
As a result of our strategy, we frequently have gains or losses on derivative financial instruments that are conversely offset by losses or gains on forward fixed-price physical contracts on feedstocks and biomass-based diesel or inventories. Gains and losses on derivative financial instruments are recognized each period in operating results while corresponding gains and losses on physical contracts are generally not recognized until quantities are delivered or title transfers which may be in the same or later periods. Our results of operations are impacted when there is a period mismatch of recognized gains or losses associated with the change in fair value of derivative instruments used for risk management purposes at the end of the reporting period but the purchase or sale of feedstocks or biomass-based diesel has not yet occurred and thus the offsetting gain or loss will be recognized in a later accounting period.
We had risk management gains of $18.4 million from our derivative financial instrument trading activity for the year ended December 31, 2018, compared to risk management losses of $23.4 million for the year ended December 31, 2017. Changes in the value of these futures or swap instruments are reflected in current income or loss, generally within our cost of goods sold. In 2018 and 2017, risk management gains (losses) resulted mostly from the significant volatility in the energy market and accounted for a gain of $0.03 and a loss of $0.04 per gallon sold, respectively. In general, these gains (losses) were largely off-set with physical product sales that benefit from the higher energy prices which drove the risk management gain (losses).
Increasing importance of renewable diesel
Renewable diesel has become an increasingly significant part of our business. Renewable diesel carries a premium price to biodiesel as a result of a variety of factors including the ability to blend it with petroleum diesel seamlessly, better cold weather performance, and because it generates more RINs on a per gallon basis. We estimate that our renewable diesel production facility in Geismar, Louisiana generated more than half of our adjusted EBITDA in 2018. We experienced two fires at this facility in 2015 that each resulted in the plant being shut down for a lengthy period. If production at this facility were interrupted again due to a fire or for any other reason, it would have a disproportionately significant and material adverse impact on our results of operations and financial conditions.
Seasonality
Our operating results are influenced by seasonal fluctuations in the demand for biomass-based diesel. Our biodiesel sales tend to decrease during the winter season due to reduced blending concentrations to adjust for performance during colder weather. Colder seasonal temperatures can cause the higher cloud point biodiesel we make from inedible animal fats to become cloudy and eventually gel at a higher temperature than petroleum-based diesel, renewable diesel, or lower cloud point biodiesel made from soybean oil, canola oil or inedible corn oil. Such gelling can lead to plugged fuel filters and other fuel handling and performance problems for customers and suppliers. Reduced demand in the winter for our higher cloud point biodiesel can result in excess supply of such higher cloud point biodiesel and lower prices for such biodiesel. In addition, most of our biodiesel production facilities are located in colder Midwestern states in proximity to feedstock origination, and our costs of shipping can increase as more biodiesel is transported to warmer climate geographies during winter. To mitigate some of these seasonal fluctuations, we have upgraded our Newton and Danville biorefineries to produce distilled biodiesel from low-cost feedstocks, which has improved cold-weather performance.
RIN prices may also be subject to seasonal fluctuations. The RIN is dated for the calendar year in which it is generated, commonly referred to as the RIN vintage. Since 20% of the annual RVO of an Obligated Party can be satisfied by prior year RINs, most RINs must come from biofuel produced or imported during the RVO year. As a result, RIN prices can be expected to decrease as the calendar year progresses if the RIN market is oversupplied compared to that year's RVO and increase if the market is undersupplied. See chart below for comparison between actual RIN generation and RVO level for biomass-based diesel as set by the EPA.

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Year
 
RIN Generation (D4 Biomass-based Diesel)
 
Finalized RVO level for D4 Biomass-based Diesel
2016
 
2.60 billion gallons
 
1.90 billion gallons
2017
 
2.50 billion gallons
 
2.00 billion gallons
2018
 
2.50 billion gallons
 
2.10 billion gallons
Industry capacity, production and imports
Our operating results are influenced by our industry's capacity and production, including in relation to RFS2 production requirements. Under RFS2, Obligated Parties are entitled to satisfy up to 20% of their annual requirement with prior year RINs. Biomass-based diesel production and/or imports, as reported by EMTS, were 2.60 billion gallons for 2016, 790 million gallons higher than 2015. The amount of biomass-based diesel produced and/or imported into the U.S. in 2017 was 2.50 billion gallons. In 2018, according to EMTS data, 2.50 billion gallons of biomass-based diesel were produced and/or imported into the U.S.
The amount of imported biodiesel gallons qualifying under RFS2 has decreased from 692.9 million gallons in 2016 to approximately 576.3 million gallons in 2017. The amount of imported biodiesel decreased further to 306.5 million gallons in the first 11 months of 2018, according to the EIA. This significant decrease in 2018 is a result of the anti-dumping and countervailing duty trade case mentioned previously, which eliminated the imports of biodiesel from Argentina and Indonesia in 2018.
Components of Revenues and Expenses
Continuing Operations:
We derive revenues in our Biomass-based diesel segment from the following sources:
sales of biodiesel and renewable diesel produced at our facilities, including RINs and LCFS credits, transportation, storage and insurance costs to the extent paid for by our customers;
revenues from our sale of biomass-based diesel and RINs produced by third parties through toll manufacturing arrangements with us;
resale of finished biomass-based diesel, RINs and LCFS credits acquired from third parties, and raw material feedstocks acquired from others;
revenues from our sale of petroleum-based heating oil and ultra-low sulfur diesel, or ULSD, acquired from third parties, along with the sale of these petroleum-based products further blended with biomass-based diesel;
sales of glycerin, other co-products of the biomass-based diesel production process; and
incentive payments from federal and state governments, including the BTC, and from the USDA Advanced Biofuel Program.
We derive revenues in our Services segment from the following sources - primarily internally generally:
fees received from operations management services that we provide for biomass-based diesel production facilities, typically based on production rates and profitability of the managed facility; and
amounts received for services performed by us in our role as general contractor and construction manager for upgrades and repairs to our biomass-based diesel production facilities.
Cost of goods sold for our Biomass-based diesel segment includes:
with respect to our production facilities, expenses incurred for feedstocks, catalysts and other chemicals used in the production process, leases, utilities, depreciation, salaries and other indirect expenses related to the production process, and, when required by our customers, transportation, storage and insurance;
with respect to biomass-based diesel acquired from third parties produced under toll manufacturing arrangements, expenses incurred for feedstocks, transportation, catalysts and other chemicals used in the production process and toll processing fees paid to the facility producing the biomass-based diesel;
with respect to fuel and RINs acquired from third parties, the purchase price of biomass-based diesel and RINs on the spot market or under contract, and related expenses for transportation, storage, insurance, labor and other indirect expenses;
adjustments made to reflect the lower of cost or market values of our finished goods inventory, including RINs acquired from third parties;
expenses from the purchase of petroleum-based heating oil and ULSD acquired from third parties; and

35



changes during the applicable accounting period in the market value of derivative and hedging instruments, such as exchange traded contracts, related to feedstocks and commodity fuel products.
Cost of goods sold for our Services segment includes:
with respect to our facility management and operations activities, primarily salary expenses for the services of management employees for each facility and others who provide procurement, marketing and various administrative functions; and
with respect to our construction management services activities, primarily our payments to subcontractors constructing the production facility and providing the biomass-based diesel processing equipment, and, to a much lesser extent, salaries and related expenses for our employees involved in the construction process.
Selling, general and administrative expense consists of expenses generally involving corporate overhead functions and operations at our Ames, Iowa, international operations and regional offices.
Impairment of property, plant and equipment represents non-cash impairment charges of certain property, plant and equipment items.
Other income (expense), net is primarily comprised of the change in fair value of contingent considerations, gain on debt extinguishment, changes in fair value of convertible debt conversion liability, interest expense including the accretion of convertible debt and amortization of deferred financing costs, interest income and gain on involuntary conversion, which represents the amount of insurance proceeds in excess of the net book value of the property damage recorded by us related to the June 2017 fire at our Madison facility.
Discontinued Operations:
Loss from Discontinued Operations was related to the research and development activities of REG Life Sciences, aimed to bring industrial biotechnology products to market and loss on classification of the REG Life Sciences as assets available for sale.

36



Critical Accounting Policies
Our discussion and analysis of our financial condition and results of operations is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amount of assets, liabilities, equities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for judgments we make about the carrying values of assets and liabilities that are not readily apparent from other sources. Because these estimates can vary depending on the situation, actual results may differ from the estimates.
We believe the following critical accounting policies affect our more significant judgments used in the preparation of our consolidated financial statements:
Income Taxes
Our income tax provision, deferred income tax assets and liabilities, and liabilities for unrecognized tax benefits represent the Company’s best estimate of current and future income taxes to be paid. Our annual effective tax rate is based on income tax laws, statutory tax rates, taxable income levels and tax planning opportunities available in various jurisdictions where we operate. These tax laws are complex and require significant judgment to determine the consolidated provision for income taxes. Changes in tax laws, statutory tax rates, and estimates of our future taxable income levels could result in actual realization of deferred taxes being materially different from amounts provided for in the consolidated financial statements.
Deferred income taxes represent temporary differences between the tax and the financial reporting basis of assets and liabilities, which will result in taxable or deductible amounts in the future. Deferred tax assets also include loss carryforwards and tax credits. These assets are regularly assessed for the likelihood of recoverability from estimated future taxable income, reversal of deferred tax liabilities and tax planning strategies. To the extent we determine that it is more likely than not a deferred income tax asset will not be realized, a valuation allowance is established. The recoverability analysis of the deferred income tax assets and the related valuation allowances requires significant judgment and relies on estimates.
On December 22, 2017, President Donald Trump signed into law “H.R. 1”, formerly known as the “Tax Cuts and Jobs Act” (the “Tax Legislation”). The Tax Legislation, which was effective on January 1, 2018, significantly revises the U.S. tax code by, among other things, lowering the corporate income tax rate from 35% to 21%, and implementing a hybrid-territorial tax system imposing a repatriation tax on deemed repatriated earnings of foreign subsidiaries (“transition tax”). We are required to recognize the effect of the tax law changes in the period of enactment.
In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”), which allows for the recording of provisional amounts during a measurement period not to extend beyond one year of the enactment date. Although the Tax Legislation was passed late in the fourth quarter of 2017, we consider the accounting for the transition tax to be final, along with the impact of the reduction in the corporate tax rate. As a result, the provisional tax benefit of $13.7 million recorded in the fourth quarter of 2017 has not changed.
The indefinite reinvestment in the earnings of non-US subsidiaries assertion is determined by management’s judgment about and intentions concerning future investment in operations. Management’s judgment is that we are not indefinitely reinvested in the undistributed earnings of our non-US subsidiaries at December 31, 2018. The assertion regarding undistributed non-US earnings does not have a material impact on our consolidated financial statements.
Revenue Recognition
In the first quarter of 2018, we adopted Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606). Under the ASU, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all contracts with customers and elected the modified retrospective implementation method. We have generally a single performance obligation in our arrangements with customers. We believe for most of our contracts with customers, control is transferred at a point in time, typically upon delivery to the customers. When we perform shipping and handling activities after the transfer of control to the customers (e.g., when control transfers prior to delivery), they are considered as fulfillment activities, and accordingly, the costs are accrued for when the related revenue is recognized. Taxes collected from customers relating to product sales and remitted to governmental authorities are excluded from revenues. We generally expense sales commissions when incurred because the amortization period would have been less than one year. We record these costs within selling, general and administrative expenses. The implementation of

37



the new standard did not have any material impact on the measurement or recognition of revenue of prior periods, however additional disclosures have been added in accordance with the ASU.
Results of Operations
Fiscal years ended December 31, 2018 and December 31, 2017
Set forth below is a summary of certain financial information (dollars in thousands and gallons in millions except per gallon data) for the periods indicated:
 
Twelve Months Ended
December 31,
 
2018
 
2017
Gallons sold
649.2

 
586.7

Average biomass-based diesel price per gallon (BTC net benefit adjusted ASP of $3.03 for the year ended December 31, 2018)
$
3.43

 
$
3.06

 
 
 
 
Revenues from continuing operations
$
2,382,987

 
$
2,154,655

Costs of goods sold from continuing operations
1,962,996

 
2,070,301

Gross profit from continuing operations
419,991

 
84,354

Selling, general and administrative expenses
104,702

 
93,425

Research and development expense
2,037

 
2,418

Impairment of property, plant and equipment
879

 
49,873

Income (loss) from operations
312,373

 
(61,362
)
Other expense, net
(2,874
)
 
(35,407
)
Income tax benefit (expense)
(5,871
)
 
30,490

Net income (loss) from continuing operations attributable to the Company
303,628

 
(66,279
)
Net loss from discontinued operations attributable to the Company
(11,312
)
 
(12,800
)
Net income (loss) to the Company
292,316

 
(79,079
)
 
 
 
 
Effects of participating share-based awards on continuing operations
(7,824
)
 

Net income (loss) from continuing operations attributable to the Company’s common stockholders
$
295,804

 
$
(66,279
)
Net loss from discontinued operations attributable to the Company's common stockholders
$
(11,312
)
 
$
(12,800
)
Continuing Operations:
Revenues. Our total revenues increased $228.3 million, or 11%, to $2,383.0 million for the year ended December 31, 2018, from $2,154.7 million for the year ended December 31, 2017. This increase was primarily due to the 2017 BTC that was earned during 2017 yet recognized in the first quarter of 2018 when it was retroactively reinstated, coupled with a 11% increase in gallons sold, offset by lower average selling price without the impact of the 2017 BTC. The increase in the total revenues was also negatively impacted by a significant reduction in revenues from sales of separate RINs.
Biomass-based diesel revenues including government incentives increased $227.2 million, or 11%, to $2,380.7 million during the year ended December 31, 2018, from $2,153.5 million for the year ended December 31, 2017. Gallons sold increased 62.5 million, or 11%, to 649.2 million during the year ended December 31, 2018, compared to 586.7 million during the year ended December 31, 2017. The increase in gallons sold for the year ended December 31, 2018 accounted for a revenue increase of $189.4 million using 2018 average sales pricing. The increase in revenues was also attributable to a $338.8 million increase in government incentives revenues in 2018 as the 2017 BTC was not reinstated until February 9, 2018 and was recognized in revenues in the first quarter of 2018. Our average biomass-based diesel sales price per gallon including the 2017 BTC net benefit increased $0.37, or 12%, to $3.43 during the year ended December 31, 2018, but decreased $0.03, or 1% excluding the 2017 BTC net benefit, compared to $3.06 during the year ended December 31, 2017. This decrease was mainly due to the lower energy prices in 2018. The decrease in average sales price excluding the 2017 BTC net benefit from 2017 to 2018 contributed to a $17.6 million revenue decrease when applied to the number of gallons sold during 2017. The net 2017 BTC benefits contributed to an increase in revenues of $208.9 million. Sales of separated RIN inventory were $137.9 million and $337.5 million for the years ended December 31, 2018 and 2017, respectively, reducing the overall increase in biomass-based diesel revenues in 2018. RIN value decreased significantly in 2018 - RIN prices declined almost 60% year over year and we believe RIN prices have been inversely correlated to the HOBO spread.

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Costs of goods sold. Our costs of goods sold decreased $107.3 million, or 5%, to $1,963.0 million for the year ended December 31, 2018, from $2,070.3 million for the year ended December 31, 2017. Costs of goods sold as a percentage of revenues were 82% and 96% for the years ended December 31, 2018 and 2017, respectively. The significant drop in costs of goods sold as a percentage of revenues is largely due to the recognition of the 2017 BTC in full as revenues in the first quarter of 2018 and lower feedstock costs as discussed below, coupled with risk management gains in 2018 as compared to losses in 2017.
Biomass-based diesel costs of goods sold decreased in 2018 despite a 11% increase in gallons sold, largely driven by lower feedstock costs and gains from risk management activity. Average lower cost feedstocks prices for the year ended December 31, 2018 were $0.25 per pound, compared to $0.29 per pound for the year ended December 31, 2017. Average soybean oil costs for the years ended December 31, 2018 and December 31, 2017 were $0.31 and $0.33 per pound, respectively. We recorded risk management gains of $18.4 million from our derivative financial instrument activity in 2018, compared to risk management losses of $23.4 million for 2017. This fluctuation in risk management gains and losses was mainly due to the volatility in the energy and commodities market. Costs of goods sold for separated RIN inventory sales were $75.7 million and $264.8 million for the years ending December 31, 2018 and 2017, respectively.
Selling, general and administrative expenses. Our selling, general and administrative, or SG&A, expenses were $104.7 million for the year ended December 31, 2018, compared to $93.4 million for the year ended December 31, 2017. SG&A expenses increased $11.3 million, or 12%, for the year ended December 31, 2018 as compared to the year ended December 31, 2017. As a percentage of revenues, our SG&A expenses were 4.4% and 4.3% for 2018 and 2017, respectively. The increase in 2018 year over year was driven largely by higher employee related compensation, arising from the Company's strong financial performance in 2017.
Impairment of property, plant and equipment. The amount of property, plant and equipment impairment recorded in 2018 was approximately $0.9 million mainly due to the impairment charges related to certain identified plant property, plant and equipment at our current facilities as the carrying amounts of those assets were deemed not recoverable. During the fourth quarter of 2017, we recorded impairment charges of $44.6 million against property, plant and equipment assets at our partially completed facility in New Orleans, Louisiana. The impairment charge resulted from the probability that the project would not be completed in the near term as a result of other strategic investment priorities, such as potential expansion of our renewable diesel facility at Geismar, coupled with limited financing availability and construction cost requirements. In addition, during 2017, we recorded impairment charges of $5.3 million against certain identified plant property, plant and equipment at our other facilities as the carrying amounts of those assets were deemed not recoverable.
Other income (expense), net. Other expense was $2.9 million for the year ended December 31, 2018, compared to other expense of $35.4 million for the year ended December 31, 2017. Other income (expense) is primarily comprised of change in fair value of contingent consideration, gain on debt extinguishment, gain on involuntary conversion, change in fair value of convertible debt conversion liability, interest expense, interest income and other non-operating items. On December 8, 2017, at the special meeting of stockholders, we obtained approval from our stockholders to remove the common stock issuance restrictions in connection with conversions of the 2036 Convertible Senior Notes. Accordingly, the embedded conversion option was reclassified into Additional Paid-in Capital at December 8, 2017, resulting in a $18.8 million expense in 2017 related to the fair value adjustment on the convertible debt conversion liability. There was no such expense in 2018. The other expense in 2018 was offset by debt extinguishment gains related to our buyback of the 2036 Convertible Senior Notes.
Income tax benefit (expense). Income tax expense recorded during the year ended December 31, 2018 was $5.9 million, compared to income tax benefit of $30.5 million for the year ended December 31, 2017. The primary difference resulted from the enactment of the Tax Cuts and Jobs Act in the fourth quarter of 2017, which reduced the U.S. corporate income tax rate from 35% to 21%, causing a re-measurement of deferred tax liabilities, and the release of valuation allowance due to the reclassification of the 2036 Convertible Senior Notes to Additional Paid-in Capital. At December 31, 2018 and 2017, we had net deferred income tax assets of approximately $275.2 million and $257.2 million, respectively, with a valuation allowance of $283.6 million and $265.4 million, respectively. As a result, our effective tax rate was 2.0% and 27.8% for the years ended December 31, 2018 and 2017, respectively.
Effects of participating share-based awards. Effects of participating restricted stock units was $7.8 and $0.0 million for the years ended December 31, 2018 and 2017, respectively.

39



Discontinued Operations:
In the fourth quarter of 2018, our Board of Directors authorized us to pursue a plan to sell the core assets and business of REG Life Sciences, the main component of our Renewable Chemicals segment. This represents a strategic shift in our business. As a result, REG Life Sciences business is classified as discontinued operations. Net loss from discontinued operations included an impairment loss, net of tax, of $11.2 million reflecting the fair value of the estimated proceeds from a sale, net of costs to sell. Net loss from discontinued operations for the year ended December 31, 2018 also included a loss of $14.0 million primarily related to the research and development activities of REG Life Sciences, which was offset by a change in value of contingent consideration of $13.9 million as a result of shortened duration to the final earnout determination date and reduced commercialization probability. For the year ended December 31, 2017, the net loss was $12.8 million. The net loss in both years were related to research and development expenses to bring industrial biotechnology products to market.
Fiscal years ended December 31, 2017 and December 31, 2016
Set forth below is a summary of certain financial information (dollars in thousands and gallons in millions except per gallon data) for the periods indicated:
 
Twelve Months Ended
December 31,
 
2017
 
2016
Gallons sold
586.7

 
567.1

Average biomass-based diesel price per gallon
$
3.06

 
$
3.17

 
 
 
 
Revenues from continuing operations
$
2,154,655

 
$
2,039,232

Costs of goods sold from continuing operations
2,070,301

 
1,867,847

Gross profit from continuing operations
84,354

 
171,385

Selling, general and administrative expenses
93,425

 
88,285

Research and development expense
2,418

 
4,890

Impairment of property, plant and equipment
49,873

 
17,893

Income (loss) from operations
(61,362
)
 
60,317

Other income (expense), net
(35,407
)
 
7,792

Income tax benefit (expense)
30,490

 
(4,268
)
Net income (loss) from continuing operations
(66,279
)
 
63,841

Less---Net income attributable to noncontrolling interest

 
386

Net income (loss) from continuing operations attributable to the Company
(66,279
)
 
63,455

Net loss from discontinued operations attributable to the Company
(12,800
)
 
(19,128
)
Net income (loss) to the Company
(79,079
)
 
44,327

 
 
 
 
Effects of participating share-based awards on continuing operations

 
(1,251
)
Net income (loss) from continuing operations attributable to the Company’s common stockholders
$
(66,279
)
 
$
62,204

Net loss from discontinued operations attributable to the Company's common stockholders
$
(12,800
)
 
$
(19,128
)
Continuing Operations:
Revenues. Our total revenues increased $115.4 million, or 6%, to $2,154.7 million for the year ended December 31, 2017, from $2,039.2 million for the year ended December 31, 2016. This increase was primarily due to a 3% increase in gallons sold, offset by a significant drop in government incentives revenues due to the BTC lapsing through 2017 and lower average selling price. The majority of the increase in the gallons sold consisted of renewable diesel gallons produced at our Geismar facility, which operated at higher utilization rates throughout 2017 compared to 2016.
Biomass-based diesel revenues including government incentives increased $114.5 million, or 6%, to $2,153.5 million during the year ended December 31, 2017, from $2,039.1 million for the year ended December 31, 2016. Gallons sold increased 19.6 million, or 3%, to 586.7 million during the year ended December 31, 2017, compared to 567.1 million during the year ended December 31, 2016. The increase in gallons sold for the year ended December 31, 2017 accounted for a revenue increase of $60.0 million using 2017 average sales pricing. The increase in revenues was offset by a $317.9 million decrease in government incentives revenues in 2017 as the 2017 BTC was not reinstated until February 9, 2018. Our average biomass-

40



based diesel sales price per gallon decreased $0.11, or 3%, to $3.06 during the year ended December 31, 2017, compared to $3.17 during the year ended December 31, 2016, mainly due to the impact of the lapsing of the BTC during 2017. The decrease in average sales price from 2016 to 2017 contributed to a $62.4 million revenue decrease when applied to the number of gallons sold during 2016. Sales of separated RIN inventory were $337.5 million and $274.8 million for the years ended December 31, 2017 and 2016, respectively, contributing to the overall increase in biomass-based diesel revenues.
Costs of goods sold. Our costs of goods sold increased $202.5 million, or 11%, to $2,070.3 million for the year ended December 31, 2017, from $1,867.8 million for the year ended December 31, 2016. Costs of goods sold as a percentage of revenues were 96% and 92% for the years ended December 31, 2017 and 2016, respectively. The increase in costs of goods sold as a percentage of revenues is largely due to the reduction in government incentives revenue for 2017 as the BTC was not reinstated for 2017 until February 9, 2018.
Biomass-based diesel costs of goods sold increased in 2017 mainly due to a 3% increase in gallons sold. Average lower- cost feedstocks prices for the year ended December 31, 2017 were $0.29 per pound, compared to $0.28 per pound for the year ended December 31, 2016. Average soybean oil costs for the years ended December 31, 2017 and December 31, 2016 were both $0.33 per pound. We recorded risk management losses of $23.4 million from our derivative financial instrument activity in 2017, compared to risk management losses of $35.4 million for 2016. This fluctuation in risk management gains and losses was mainly due to the volatility in the commodities market. In addition, the movements in the value of RINs during 2017 resulted in a $4.5 million write-down to lower of cost or net realizable value, which was mainly based on the future contracted RIN prices, on RIN inventory held throughout the year compared to a write-down of $19.4 million during 2016. Costs of goods sold for separated RIN inventory sales excluding lower of cost write-downs were $260.3 million and $231.4 million for the years ending December 31, 2017 and 2016, respectively.
Selling, general and administrative expenses. Our selling, general and administrative, or SG&A, expenses were $93.4 million for the year ended December 31, 2017, compared to $88.3 million for the year ended December 31, 2016. SG&A expenses increased $5.1 million, or 6%, for the year ended December 31, 2017 as compared to the year ended December 31, 2016. As a percentage of revenues, our SG&A expenses were 4.3% for 2017 and 4.3% for 2016. The increase year over year in SG&A expenses was primarily due to executive severance costs and increases in costs related to the Company's efforts on regulatory activities and an ITC trade case.
Impairment of property, plant and equipment. During the fourth quarter of 2017, we recorded impairment charges of $44.6 million against property, plant and equipment assets at our partially completed facility in New Orleans, Louisiana. The impairment charge resulted from the probability that the project would not be completed in the near term as a result of other strategic investment priorities, such as potential expansion of our renewable diesel facility at Geismar, coupled with limited financing availability and construction cost requirements. In addition during 2017, we recorded impairment charges of $5.2 million against certain identified plant property, plant and equipment at our other facilities as the carrying amounts of those assets were deemed not recoverable. The amount of property, plant and equipment impairment recorded in 2016 was approximately $17.9 million mainly due to the impairment charges related to our partially completed facility in Emporia, Kansas.
Other income (expense), net. Other expense was $35.4 million for the year ended December 31, 2017, compared to other income of $7.8 million for the year ended December 31, 2016. Other income (expense) is primarily comprised of change in fair value of contingent consideration, interest expense, interest income and other non-operating items. The increase in the overall other expense of $43.2 million was mainly due to a loss in fair value of convertible debt conversion liability of $18.8 million for the year ended December 31, 2017, compared to a gain in fair value of $13.0 million for the year ended December 31, 2016 related to our 2036 Convertible Senior Notes. In addition, the increase in the overall other expense was also attributable to a reduced gain in involuntary conversion of $4.6 million and an increase of $2.8 million in interest expense.
Income tax expense. There was an income tax benefit recorded during the year ended December 31, 2017 of $30.5 million, compared to an income tax expense of $4.3 million for the year ended December 31, 2016. The primary difference resulted from changes due to the Tax Cuts and Jobs Act where we saw a reduction in U.S. corporate income tax rate from 35% to 21%, including a remeasurement of deferred tax liabilities and the release of valuation allowance due to the reclassification of the 2036 Convertible Senior Notes to Additional Paid-in Capital. At December 31, 2017 and 2016, we had net deferred income tax assets of approximately $257.2 million and $344.8 million, respectively, with a valuation allowance of $265.4 million and $365.0 million, respectively. As a result, our effective tax rate was 27.8% and 8.7% for the years ended December 31, 2017 and 2016, respectively.
Effects of participating share-based awards. Effects of participating restricted stock units was $0.0 million and $1.3 million for the years ended December 31, 2017 and 2016, respectively.
Discontinued Operations:

41



Net loss from discontinued operations was attributable to the research and development activities at the REG Life Sciences business. The decrease in the net loss compared to 2016 was attributable to management's cost containment efforts and an increase in joint development agreement revenues.
Non - GAAP Financial Measures
Adjusted EBITDA
Earnings before interest, taxes, depreciation and amortization ("EBITDA") and Adjusted EBITDA are not measures of financial performance under GAAP. We use EBITDA and EBITDA adjusted for certain additional items, identified in the table below, or Adjusted EBITDA, as a supplemental performance measure. We present EBITDA and Adjusted EBITDA because we believe they assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, we use Adjusted EBITDA to evaluate, assess and benchmark our financial performance on a consistent and a comparable basis and as a factor in determining incentive compensation for our executives.

42



The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income (loss):
(In thousands)
 
 
 
 
 
 
 
 
Year ended December 31,
 
 
 
 
 
 
 
 
 
Year ended December 31,

1Q-2018
 
2Q-2018
 
3Q-2018
 
4Q-2018
 
2018
 
1Q-2017
 
2Q-2017
 
3Q-2017
 
4Q-2017
 
2017
Net income (loss) attributable to the Company
$
214,389

 
$
33,850

 
$
25,003

 
$
19,074

 
$
292,316

 
$
(15,914
)
 
$
(34,809
)
 
$
(11,373
)
 
$
(16,983
)
 
$
(79,079
)
Adjustments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
4,651

 
4,925

 
4,003

 
3,955

 
17,534

 
4,536

 
4,479

 
4,725

 
5,015

 
18,755

Income tax (benefit) expense
(1,203
)
 
3,835

 
854

 
2,385

 
5,871

 
1,075

 
1,960

 
(115
)
 
(33,410
)
 
(30,490
)
Depreciation from continuing and discontinued operations
8,859

 
9,124

 
9,097

 
9,724

 
36,804

 
8,423

 
8,523

 
8,639

 
8,698

 
34,283

Amortization from continuing and discontinued operations
308

 
310

 
318

 
311

 
1,247

 
127

 
149

 
307

 
305

 
888

EBITDA
227,004

 
52,044

 
39,275

 
35,449

 
353,772

 
(1,753
)
 
(19,698
)
 
2,183

 
(36,375
)
 
(55,643
)
Gain on involuntary conversion
(4,000
)
 
(454
)
 

 
(3
)
 
(4,457
)
 

 

 
(942
)
 
(4,387
)
 
(5,329
)
Gain on sale of assets
(990
)
 

 
(13
)
 
(2
)
 
(1,005
)
 

 

 

 

 

Change in fair value of convertible debt conversion liability

 

 

 

 

 
172

 
32,546

 
(8,560
)
 
(5,325
)
 
18,833

Change in fair value of contingent consideration from continuing and discontinued operations
(1,540
)
 
(7,129
)
 
(4,566
)
 
444

 
(12,791
)
 
589

 
(24
)
 
1,433

 
486

 
2,484

Gain (loss) on debt extinguishment
232

 
(2,337
)
 
(788
)
 
(3,404
)
 
(6,297
)
 

 

 

 

 

Other income (expense), net
(222
)
 
(2,066
)
 
(486
)
 
(1,243
)
 
(4,017
)
 
320

 
(32
)
 
(12
)
 
742

 
1,018

Impairment of assets

 

 

 
879

 
879

 

 
1,341

 

 
48,532

 
49,873

Impairment loss on assets classified as held for sale

 

 

 
11,226

 
11,226

 

 

 

 

 

Loss on the Geismar lease termination

 

 

 

 

 

 
3,967

 

 

 
3,967

Straight-line lease expense
(33
)
 
(3
)
 
(61
)
 
(31
)
 
(128
)
 
(32
)
 
(85
)
 
(85
)
 
(35
)
 
(237
)
Executive severance
165

 
50

 

 

 
215

 

 

 
2,420

 
991

 
3,411

Non-cash stock compensation
1,794

 
2,203

 
1,227

 
1,188

 
6,412

 
1,308

 
1,688

 
2,023

 
1,890

 
6,909

Adjusted EBITDA excluding 2017 BTC allocation
$
222,410

 
$
42,308

 
$
34,588

 
$
44,503

 
$
343,809

 
$
604

 
$
19,703

 
$
(1,540
)
 
$
6,519

 
$
25,286

 Biodiesel tax credit (1)
(204,936
)
 

 

 

 
(204,936
)
 
36,728

 
59,365

 
56,505

 
52,338

 
204,936

Adjusted EBITDA
$
17,474

 
$
42,308

 
$
34,588

 
$
44,503

 
$
138,873

 
$
37,332

 
$
79,068

 
$
54,965

 
$
58,857

 
$
230,222

(1) On February 9, 2018, the Biodiesel Mixture Excise Tax Credit ("BTC") was retroactively reinstated for the 2017 calendar year. The retroactive credit for 2017 resulted in a net benefit to us that was recognized in the first quarter of 2018 for GAAP purposes. Because this credit relates to the 2017 full year operating performance and results, we removed the net benefit of the 2017 BTC from our 2018 results and allocated a portion of the net benefit of the tax credit to each of the four quarters of 2017 based upon gallons sold.
Adjusted EBITDA is a supplemental performance measure that is not required by, or presented in accordance with, generally accepted accounting principles, or GAAP. Adjusted EBITDA should not be considered as an alternative to net income or any other performance measure derived in accordance with GAAP, or as alternatives to cash flows from operating activities or a

43



measure of our liquidity or profitability. Adjusted EBITDA has limitations as an analytical tool, and should not be considered in isolation, or as a substitute for any of our results as reported under GAAP. Some of these limitations are:
Adjusted EBITDA does not reflect our cash expenditures or the impact of certain cash charges that we consider not to be an indication of our ongoing operations;
Adjusted EBITDA does not reflect changes in, or cash requirements for, our working capital requirements;
Adjusted EBITDA does not reflect the interest expense, or the cash requirements necessary to service interest or principal payments, on our indebtedness;
although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect cash requirements for such replacements;
stock-based compensation expense is an important element of our long term incentive compensation program, although we have excluded it as an expense when evaluating our operating performance; and
other companies, including other companies in our industry, may calculate these measures differently than we do, limiting their usefulness as a comparative measure.
Liquidity and Capital Resources
Sources of liquidity. At December 31, 2018 and 2017, the total of our cash and cash equivalents and marketable securities was $174.5 million and $77.6 million, respectively. At December 31, 2018, we had total assets of $1,107.1 million, compared to $1,005.6 million at December 31, 2017. At December 31, 2018, we had term debt before debt issuance costs of $185.8 million, compared to term debt before debt issuance costs of $228.6 million at December 31, 2017. Our debt is subject to various financial covenants. We were in compliance with all financial covenants associated with the borrowings as of December 31, 2018.
Our term debt (in thousands) is as follows:
 
December 31,
 
2018
 
2017
4.00% Convertible Senior Notes, $96,300 face amount, due in June 2036
$
75,477

 
$
116,255

2.75% Convertible Senior Notes, $67,527 face amount, due in June 2019
66,361

 
69,859

REG Danville term loan, secured, variable interest rate of LIBOR plus 4%, due in July 2022
8,964

 
11,460