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EX-32.2 - EXHIBIT 32.2 - Renewable Energy Group, Inc.regi-20171231xex322.htm
EX-32.1 - EXHIBIT 32.1 - Renewable Energy Group, Inc.regi-20171231xex321.htm
EX-31.2 - EXHIBIT 31.2 - Renewable Energy Group, Inc.regi-20171231xex312.htm
EX-31.1 - EXHIBIT 31.1 - Renewable Energy Group, Inc.regi-20171231xex311.htm
EX-23.1 - EXHIBIT 23.1 - Renewable Energy Group, Inc.regi-20171231xex231xdeloit.htm
EX-21.1 - EXHIBIT 21.1 - Renewable Energy Group, Inc.regi-20171231xex211xlistof.htm
EX-12.1 - EXHIBIT 12.1 - Renewable Energy Group, Inc.regi-20171231xex121stateme.htm
EX-10.24 - EXHIBIT 10.24 - Renewable Energy Group, Inc.regi-20171231xex1024amendm.htm
EX-10.22 - EXHIBIT 10.22 - Renewable Energy Group, Inc.regi-20171231xex1022amendm.htm
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, 2017
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (section 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 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.  x 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
¨
Accelerated filer
x
 
 
 
 
Non-accelerated filer
¨  (Do not check if a smaller reporting company)
Smaller reporting 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, 2017, the aggregate market value of Common Stock held by non-affiliates was $490,235,252.
As of February 28, 2018, 38,855,313 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 mandates 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;
progressing facilities currently under development to the construction and operational stages, including planned capital expenditures and our ability to obtain financing for such construction;
our ability to protect proprietary technology and trade secrets;
the development of competing alternative fuels, energy services and renewable chemicals;
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 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.
ITEM 1.
Business
General
We focus on providing cleaner, lower carbon products and services. 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 2017, we sold 587 million total gallons of fuel (including fuel purchased from third parties for resale) and generated revenues of $2.2 billion. We are also engaged in research and development efforts focused on the conversion of diverse feedstocks into various renewable chemicals, advanced biofuels

1



and other products. We believe our fully integrated approach, which includes acquiring feedstock, managing biorefinery facility construction and upgrades, operating biorefineries, and distributing through a network of terminals, positions us to serve the market for biomass-based diesel, other advanced biofuels and other products and services.
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 microbial fermentation facility used in connection with our development of renewable chemicals. Our thirteen biomass-based diesel production facilities have an aggregate nameplate production capacity of 520 million gallons per year ("mmgy").
Our development-stage industrial biotechnology business, REG Life Sciences is developing proprietary microbial fermentation processes to produce renewable chemicals, advanced biofuels and other products. Fatty acids are one of three product areas being focused on, along with esters and alcohols.
In January 2017, we completed the acquisition of the remaining minority interest in Petrotec AG. Our operations in Germany utilize used cooking oil and other waste feedstocks to produce biomass-based diesel at our two biorefineries in Emden and Oeding, Germany. Our nameplate production capacity in Germany is approximately 50 mmgy.
We own the following facilities in North America:
Property
 
Nameplate1
Production
Capacity (mmgy)
 
Effective Capacity 2 (mmgy)
 
REG
Operations
Commenced
 
Feedstock Capability
 
 
 
 
 
 
 
 
 
Ralston, Iowa 3
 
30
 
30.0
 
2002
 
Refined Oils and Fats
Albert Lea, Minnesota
 
30
 
42.4
 
2005
 
Crude, High FFA and Refined Oils and Fats
Newton, Iowa
 
30
 
31.5
 
2007
 
Crude, High FFA and Refined
Oils and Fats
Seabrook, Texas
 
35
 
35.0
 
2008
 
Refined Oils and Fats
Danville, Illinois
 
45
 
46.1
 
2009
 
Crude, High FFA and Refined
Oils and Fats
Seneca, Illinois
 
60
 
66.7
 
2010
 
Crude, High FFA and Refined
Oils and Fats
New Boston, Texas
 
15
 
15.2
 
2013
 
Crude, High FFA and Refined
Oils and Fats
Ellenwood, Georgia 4
 
15
 
n/a
 
n/a
 
N/A
Mason City, Iowa
 
30
 
30.2
 
2013
 
Crude, High FFA and Refined
Oils and Fats
Geismar, Louisiana
 
75
 
84.4
 
2014
 
Crude, High FFA and Refined
Oils and Fats
Okeechobee, Florida 5
 
n/a
 
n/a
 
2014
 
n/a
Grays Harbor, Washington
 
100
 
103.5
 
2015
 
Refined Oils and Fats
Madison, Wisconsin
 
20
 
21.9
 
2016
 
Crude, High FFA and Refined
Oils and Fats
Partially Constructed Facilities 6
 
 
 
 
 
% Complete
 
 
St. Rose, Louisiana (also known as New Orleans)
 
60
 
n/a
 
~45%
 
Crude, High FFA and Refined
Oils and Fats
Emporia, Kansas
 
60
 
n/a
 
~20%
 
Crude, High FFA and Refined Oils and Fats
Clovis, New Mexico
 
15
 
n/a
 
~50%
 
Crude, High FFA and Refined
Oils and Fats

2



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 
Ralston's recent expansion, completed on March 6, 2018, increased the facility's nameplate capacity from 12 mmgy to 30 mmgy.
4 
Idled by prior owner at time of our purchase and remains idled pending repairs or upgrades.
5 
Okeechobee is a demo-scale microbial fermentation facility for the development and production of renewable chemicals, fuels and other products.
6 
Clovis is currently being operated as a terminal. The carrying values of Emporia and New Orleans have been impaired due to the unlikelihood of these facilities being completed in the near term.

Our production network in Europe consists of the following facilities:
Property
 
Nameplate
Production
Capacity1 (million gallons)
 
Effective Capacity 2 (million gallons)
 
REG
Operations
Commenced
 
Feedstock Capability
Emden, Germany
 
27
 
30.9
 
2016
 
Crude, High FFA and Refined
Oils and Fats
Oeding, Germany
 
23
 
25.4
 
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. Our industrial biotechnology research and development activities, conducted in South San Francisco, are dedicated to the development of renewable chemicals, advanced biofuels and other products using our proprietary microbial fermentation technology.
Our Feedstocks and Other Inputs
We are a lower-cost biomass-based diesel producer. We primarily produce our biomass-based diesel from a wide variety of lower cost 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 are more widely available, but tend to be higher in price. We believe our ability to process a wide variety of feedstocks provides us with a cost advantage over many biomass-based diesel producers, particularly those that rely primarily on higher cost virgin vegetable oils.
Our ability to use a wide range of feedstocks gives us the flexibility to respond to changes in feedstock pricing to maintain our feedstock cost advantage. We have the ability to adjust our processing to accommodate different feedstocks and feedstock mixes. In 2017, approximately 73% of our total feedstock usage was lower cost inedible corn oil, used cooking oil or rendered animal fat feedstock and the remaining 27% 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

3



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 such as the JJ&A Methanol report or Southern Chemical report.
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 2017 is depicted below.


a2017distributionmovementflo.jpg
We lease over 500 railcars for transportation and lease biomass-based diesel storage tanks in 46 terminals as of December 31, 2017. 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 2017, REG sold products in 48 states in the U.S., five Canadian Provinces, Mexico and additional countries in Europe, South America and Asia.
We also sell petroleum-based heating oil and diesel fuel, which enables us to offer additional biofuel blends, while expanding our customer base. We sell heating oil and ultra-low sulfur diesel ("ULSD") at terminals throughout the northeastern U.S. as well as BioHeat® blended fuel at one of our existing Northeastern terminal locations. We sell additional biofuel blends to 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, the most important of which is Renewable Fuel Standard ("RFS2").

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Renewable Fuel Standard
On July 1, 2010, RFS2’s biomass-based diesel requirement became effective, 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, subject to the approval of the Office of Management and Budget, or OMB. For 2012 through 2016, the biomass-based diesel RVO was set (in gallons) at one billion, 1.28 billion, 1.63 billion, 1.73 billion, and 1.90 billion for 2012, 2013, 2014, 2015 and 2016, respectively. In November 2016, the EPA issued the final biomass-based diesel RVO volume for 2017 at 2.00 billion gallons. In November 2017, the EPA issued the final biomass-based diesel volume for 2018 at 2.1 billion gallons and set the 2019 RVO volume target at 2.1 billion 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 requirement was 2.88 billion gallons in 2015, 3.61 billion gallons in 2016, 4.28 billion gallons in 2017 and 4.29 billion gallons in 2018.
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 has an EEV of 1.5-1.7, 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, and require these Obligated Parties 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 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 2017, 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 range from a low of $1.19 per gallon, or 38%, in December to a high of $1.76 per gallon, or 56%, in August.

5



Biodiesel Tax Credit
The federal biodiesel mixture excise tax credit, or BTC, when in effect, provides a $1.00 per gallon excise tax credit to the first blender of biomass-based diesel with at least 0.1% 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 subsequently reinstated, in some cases on a retroactive basis, as detailed in the following table:
.
a2017btctimelinev2.jpg
The BTC is best thought of as an incentive shared across the entire value 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 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. In other words, excess CI reductions from one type of fuel (e.g. diesel) can be used to offset insufficient reductions in another fuel (e.g. gasoline).
We obtain CI credits when we sell qualified biomass-based diesel into California. During 2017, CI credits ranged from $69.5 per metric ton to $113.0 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 illustrates some of these 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 had in place 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 state excise tax, which results in a $0.20 per gallon incentive for B100.

Minnesota
 
Minnesota law requires a B5 biodiesel blend throughout the entire year. In 2014, the law required the state to increase blends to a B10 blend in the summer months; current law requires the state to move to B20 for the summer months beginning May 2018.
Oregon, 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 has been in the process of developing legislation on a low carbon fuel programs.
City of New York
 
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, 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") establishes a 20% target by 2020 for the use of renewable energy in the transport sector in European Union ("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.
Risk Management
The prices for feedstocks and biomass-based diesel 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.

7



Seasonality
Biodiesel producers have experienced seasonal fluctuations in demand for biodiesel. Biodiesel demand has tended to be lower during winter in most states due to blending concentrations being reduced. To mitigate some of these seasonal fluctuations in demand, we have upgraded our Newton and Danville biorefineries to produce distilled biodiesel from lower cost feedstocks, thus allowing that product to have improved cold-weather performance.
Renewable Identification Number, or 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 Renewable Volume Obligation, or 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.
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 quality and RIN quality, supply reliability and price. 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. In the United States and Canadian biomass-based diesel markets, we compete with 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 sourcing and marketing resources to be formidable competitors in the biodiesel industry. These agribusiness 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 producers of renewable diesel. For example, Neste Oil has greater resources than we do along with approximately 882 million gallons of renewable diesel production capacity in Asia and Europe. Another renewable diesel competitor is Diamond Green Diesel, LLC, the joint venture between Valero Energy Corp. and Darling International, which has approximately 160 million gallons of production capacity and announced plans to grow its capacity to 275 million gallons and beyond. Renewable diesel can also satisfy the RFS2 biomass-based diesel requirement if the renewable diesel meets the greenhouse gas reduction requirements and may satisfy Canadian renewable fuel requirements. Several refiners appear to be pursuing plans to co-process renewable feedstocks with petroleum crude oil at their refineries, which would add to the competitive marketplace.
In the RFS2 advanced biofuel market, we also compete with other producers and importers of advanced biofuels, such as Brazilian sugarcane ethanol producers and producers of biogas used in transportation. On a global level, we face increasing competition from imported biomass-based diesel and expect this to continue. In January 2015, the EPA announced the approval of a plan submitted by CARBIO, a consortium of Argentinean renewable fuel producers, which allows for Argentinian biodiesel made from soybean oil to generate RINs. Imported biomass-based diesel that does not qualify under RFS2, also competes in jurisdictions where there are biomass-based diesel blending requirements.
We also face competition from independent biodiesel producers, some of which are able to process lower-cost feedstocks. Most of these competitors own only one biodiesel plant and thus, do not enjoy the benefits of scale that we do. Many of these competitors own biodiesel plants that can process only higher cost virgin vegetable oils. Furthermore, in our marketing and distribution, we face competition from biomass-based diesel traders such as US Oil, NGL, Noble, Shell, Tenaska, Vitol and others. These 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.
Segment and Geographic Information
We re-assess our reportable segments on an annual basis. Prior to 2015, our business was organized into two reportable segments - the Biomass-based Diesel segment and the Services segment. As a result of the increased activities surrounding our renewable chemicals business, in 2015 we began reporting a new segment, Renewable Chemicals, which was previously included in the Biomass-based Diesel segment. The Biomass-base Diesel segment includes our operations both in the U.S. and internationally. Financial and geographic information regarding our segments can be found in Note 17 to our consolidated financial statements included under Part II, Item 8 of this report.
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.

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and REG, LLC. West Central is now known as Landus Cooperative. Set forth below is a summary of the significant events of our company since June 2008.

Date
 
Events
 
Description
June 2008
 
Houston facility
 
We acquired our Houston facility from U.S. Biodiesel Group, Inc., or USBG, through a transaction which included an equity investment in us by USBG.
February through April 2010
 
Danville, Newton and Seneca facilities
 
We acquired our Danville facility from Blackhawk Biofuels, LLC. We acquired our Newton Facility. We closed a transaction in which we agreed to lease and operate the Seneca facility and certain related assets.

July 2010
 
Tellurian Biodiesel, Inc. and American BDF, LLC
 
We acquired certain assets of Tellurian Biodiesel, Inc., or Tellurian, and American BDF, LLC, or ABDF. Tellurian was a California-based biodiesel company and marketer. ABDF was a joint venture owned by Golden State Service Industries, Restaurant Technologies, Inc., or RTI, and Tellurian. The purchase connected RTI’s national used cooking oil collection system with our national network of biodiesel manufacturing facilities.
September 2010
 
Clovis facility
 
We acquired the partially constructed Clovis facility.
July 2011
 
Albert Lea facility
 
We acquired all the assets and certain liabilities of SoyMor cooperative and SoyMor Biodiesel, LLC.
January 2012
 
REG IPO
 
We completed our initial public offering.
January 2012
 
Seneca facility
 
We purchased our Seneca facility, which we previously operated under lease.
October 2012
 
New Boston facility
 
We acquired a 15 mmgy nameplate biorefinery in New Boston from North Texas Bio Energy.
November 2012
 
Atlanta facility
 
We acquired substantially all the assets of BullDog Biodiesel, LLC.
July 2013
 
Mason City facility
 
We acquired a 30 mmgy nameplate capacity biodiesel facility located in Mason City, Iowa from Soy Energy, LLC.

January 2014
 
Life Sciences
 
We acquired substantially all of the assets and liabilities of LS9, a development-stage company focused on the use of proprietary technologies to make renewable chemicals and other products.
June 2014
 
Renewable Diesel and Geismar facility
 
We acquired substantially all the assets of Syntroleum, which consisted of a 50% limited liability company membership interest in Dynamic Fuels, a 75 mmgy renewable diesel production facility in Geismar, LA. Subsequently on June 6, 2014, we acquired the remaining 50% ownership interest in Dynamic Fuels from Tyson Foods.
December 2014
 
Europe investment
 
We acquired 69% equity ownership in Petrotec AG from its majority shareholder. As of December 31, 2016, we owned approximately 91% of Petrotec's shares. On January 2, 2017, we completed the acquisition of the remaining minority interest in Petrotec and own 100% of the equity in Petrotec.
August 2015
 
Grays Harbor facility
 
We acquired substantially all of the assets of Imperium Renewables, Inc., or Imperium, including a 100 mmgy nameplate biorefinery and terminal at the Port of Grays Harbor, Washington.
March 2016
 
Madison facility
 
We acquired a 20 mmgy nameplate capacity biomass-based refinery in DeForest, Wisconsin from Sanimax Energy.

Employees
As of December 31, 2017, we had 727 full-time employees in the U.S. and 126 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 an 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.

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Customer concentration
Our sales to one customer, Pilot Travel Centers LLC, or Pilot, were $182.2 million, $144.8 million and $114.0 million, representing approximately 8% of our total revenues for each of 2017, 2016, and 2015, 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 9%, 9% and 13% of our total sales in 2017, 2016 and 2015, respectively, based on the OPIS average RIN price for the year.
Research and development
We devote considerable resources to our research and development programs. Our biomass-based diesel research and development programs have been primarily targeted towards improving the quality and efficiency of the biomass-based diesel production process and developing applications for co-products. Our development-stage industrial biotechnology business conducts research and development involving the production of renewable chemicals, additional advanced biofuels and other products from our proprietary microbial fermentation process. Fatty acids are one of three product areas REG Life Sciences has focused on, along with esters and alcohols. In January 2016, ExxonMobil Research and Engineering Company and REG Life Sciences commenced a joint development collaboration to develop technology to produce biodiesel by fermenting renewable cellulosic sugars from sources such as agricultural waste. In October 2016, the Company delivered its first commercial product, a specialty fatty acid. REG developed, produced and delivered approximately one metric ton of the renewable, multi-functional chemical to Aroma Chemical Services International, a leading specialty manufacturer and supplier of flavor and fragrance ingredients. In September 2017, we signed a phase II joint development collaboration with ExxonMobil Research and Engineering to continue to develop technology to produce biodiesel by fermenting renewable cellulosic sugars from sources such as agricultural waste.
We expect our research and development expense to decrease in future periods as the business unit generates collaboration revenue. In November 2016, we commenced a strategic review of the life sciences business. We incurred research and development expense of $14.1 million, $18.2 million, and $16.9 million for the years ended December 31, 2017, 2016 and 2015, respectively.
Executive Officers of the Registrant
Randolph L. Howard, age 67, has served as our President and Chief Executive Officer since July 2017. Mr. Howard has served as a member of our Board of Directors since February 2007. From July 2004 until his retirement in September 2005, Mr. Howard served as the Senior Vice President for the Global Gas Division of Unocal Corporation, an oil company. Prior to that role, Mr. Howard served as Regional Vice President of Unocal’s International Energy Operations - North ASEAN and President of Unocal Thailand from May 1999 to June 2004. Mr. Howard served in various managerial roles at Unocal over 17 years including Vice President, Refining and Vice President, Supply, Trading and Transportation. Mr. Howard participated in the advanced executive program at Northwestern University and holds a B.S. in chemical engineering from University of California Berkeley.
Chad Stone, age 48, 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 secretary since November 2016.  Mr. Stone served on the executive Board of the Iowa Biodiesel Board from September 2010 to September 2016, serving as chair 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 55, 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 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.

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Gary Haer, age 64, 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 biomass-based diesel 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.
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
Federal and state governmental requirements for the use of biofuels could be repealed, curtailed or otherwise changed, which could have a material adverse effect on our revenues, operating margins and financial condition.
The biomass-based diesel industry relies substantially on federal programs requiring the consumption of biofuels. Biomass-based diesel has historically been more expensive to produce than petroleum-based diesel fuel, and governmental programs support a market for biomass-based diesel that might not otherwise exist.
We believe the Renewable Fuel Standard Program is the most important of these government programs in the United States. Under this program, the EPA promulgated a regulation commonly known as RFS2, which became effective on July 1, 2010 and applies through 2022. RFS2 requires consumption of biomass-based diesel fuel, including biodiesel and renewable diesel, at specified volumes, known as renewable volume obligations, or RVO.
Under RFS2, the EPA is required to set the RVO annually based on a variety of considerations. Over the past several years, the EPA has set the minimum annual consumption volume for biomass-based diesel at increasing levels from 1.28 billion gallons in 2013 to 1.90 billion gallons in 2016. For 2017, the EPA set the minimum annual consumption volume at 2.00 billion gallons and has set 2.10 billion gallons as the minimum annual consumption volume target for 2018.
We believe that much of the increase in demand for our biomass-based diesel since July 2010 is attributable to, and accelerated by, the existence and implementation of RFS2. In addition, we believe that biomass-based diesel prices have received significant support from RFS2 since July 2010.
State requirements and incentives for the use of biofuels increase demand for our biomass-based diesel within such states, but we believe that such state requirements and incentives have not increased overall demand for biofuels in excess of RFS2 requirements. Rather, we believe state requirements and tax incentives influence where petroleum refiners and petroleum fuel importers choose to consume the volume requirements established by the EPA under RFS2.
The United States Congress could repeal, curtail or otherwise change RFS2 in a manner adverse to us. Similarly, the EPA could curtail or otherwise change RFS2 in a manner adverse to us, including reducing the RVO to the statutory minimum level of 1 billion gallons. The petroleum industry has generally been opposed to RFS2 and is expected to continue to press for changes that eliminate or reduce its impact. We cannot predict what changes will be instituted or the impact, if any, of these changes to our business. Any repeal or reduction in the RFS2 requirements or reinterpretation of RFS2 resulting in our biomass-based diesel failing to qualify as a required fuel would materially decrease the demand for and price of our biomass-based diesel, which would materially and adversely affect our revenues, operating margins and financial condition.
In July 2017, the EPA announced that it has directed staff to begin technical analysis to inform a future rulemaking action to reset the RVO. For the first time, the EPA also proposed no increase in the biomass-based diesel RVO and proposed a reduction in the 2018 overall advanced biofuels RVO. These proposals may indicate a negative view of advanced biofuels by EPA and that if this is correct and EPA begins a process of reducing the advanced biofuel RVO and/or biomass-based diesel RVO, that such changes would be expected to harm our business and profitability.

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The governors of Pennsylvania, New Mexico, Texas and Delaware petitioned the EPA for a RFS waiver claiming the RFS was severely harming the regional economy. EPA has 90 days in which to review the waiver request, which has not been completed. All petitioning states were asked to submit additional information. It is uncertain how EPA will rule on this waiver request. If EPA reduces the RVOs as requested in the waiver, our business and profitability may be harmed.
On the state level, California has adopted The California Low Carbon Fuel Standard, or LCFS, which is designed to reduce greenhouse gas emissions associated with transportation fuels used in California by ensuring that the fuel sold meets declining targets for such emissions. The regulation quantifies lifecycle greenhouse gas emissions by assigning a “carbon intensity,” or CI, score to each transportation fuel based on that fuel’s lifecycle assessment. Each fuel provider, generally the fuel’s producer or importer, the “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. This obligation is tracked through credits and deficits. Fuels with a CI score lower than the annual standard earn a credit, and fuels that are higher than the standard result in a deficit. Credits can be traded between Regulated Parties. We receive LCFS credits when we sell qualified biomass-based diesel in California. Prices for LCFS credits ranged from $69.5 per metric ton to $113 per metric ton in 2017. Any repeal of LCFS would materially and adversely affect our revenues, operating margins and financial condition.

Loss of or reductions in tax incentives for biomass-based diesel production or consumption may have a material adverse effect on our revenues and operating margins.
Federal and state tax incentives have historically aided the biomass-based diesel industry. Prior to the 2010 implementation of RFS2, we and other participants in the biomass-based diesel industry relied principally on tax incentives to make the price of biomass-based diesel more cost competitive with the price of petroleum-based diesel fuel to the end user.
Federal
Biodiesel Tax Credit
The most significant tax incentive program has been the federal biodiesel mixture excise tax credit, referred to as the Biodiesel Tax Credit or BTC. Under the BTC, the entity to first blend pure biomass-based fuel, or B100, 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 not reinstated for 2018 and accordingly we are currently operating without the benefit of the BTC. In the past when the BTC has lapsed, we and others in the industry have operated without any assurance that a reinstatement would cover the lapsed period retroactively. There is no assurance that the BTC will be reinstated or, if reinstated, that its application will be retroactive, prospective or both.
Unlike RFS2, the BTC has a direct effect on federal government spending and could be changed or eliminated as a result of changes in the federal budget policy. We cannot predict what action, if any, Congress may take with respect to the BTC or whether such action would apply retroactively or prospectively. If the BTC is not reinstated, demand for our biomass-based diesel and the price we are able to charge for our product may decline significantly, harming revenues and profitability.
In addition, uncertainty regarding the extension or reinstatement of the BTC has caused, and may in the future cause, fluctuations in our operating results. Historically, sales have increased shortly before the BTC lapses and then decreased shortly thereafter. For example, we believe reduced demand in the first quarters of 2014 and 2015 resulted from the lapsing of the BTC at the end of 2013 and 2014, respectively. Moreover, we believe that the lapsing of the BTC on December 31, 2016 caused an acceleration of revenues in the fourth quarter of 2016, which resulted in a decline in demand during the first quarter of 2017.
When the BTC lapsed in the past, it has been retroactively reinstated by Congress. As a result of this history of retroactive reinstatement of the BTC, 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. The 2017 BTC was retroactively reinstated on February 9, 2018, resulting in a $205 million estimated net benefit to our Adjusted EBITDA for the year ended December 31, 2017. It is uncertain whether the BTC will be reinstated for 2018 and beyond and if reinstated, whether it would be reinstated retroactively or on the same terms. The lapsing or modification of the BTC would adversely affect our financial results.
State
Several states have enacted tax incentives for the use of biodiesel and/or biomass-based diesel. For example, we derive a significant portion of our revenues from operations in the State of Illinois. 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, or B11. State budget or other

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considerations could cause the modification or elimination of the tax incentive programs of Illinois and other states. The curtailment or elimination of such incentives could materially and adversely affect our revenues and profitability.

Increased industry-wide production of biomass-based diesel, including as a result of existing excess production capacity, could harm our financial results.
If the volume of excess biomass-based diesel RINs exceeds the volume mandated for use under RFS2, the demand for and price of our biomass-based diesel, and biomass-based diesel RINs may be reduced, which could adversely affect our revenues and cash flows.
According to the National Biodiesel Board, or NBB, as of May 6, 2016, 3.0 billion gallons per year of biodiesel 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. The annual production capacity of existing plants and plants under construction far exceeds both historic consumption of biomass-based diesel in the United States and required consumption under RFS2. If this excess production capacity was fully utilized for the U.S. market, it would increase competition for our feedstocks, increase the volume of biomass-based diesel on the market and may reduce biomass-based diesel gross margins, harming our revenues and profitability.
Increased biomass-based diesel production may result in the generation of RINs in excess of the volume of RINs mandated for consumption under RFS2. RIN prices can be expected to decrease as the calendar year progresses if the RIN market is oversupplied compared to that year’s RVO. For example, in 2015, which had a RVO for biomass-based diesel of 1.73 billion gallons, biomass-based diesel RIN prices, as reported by OPIS, trended downward when biomass-based diesel RIN generation neared the equivalent of 1.8 billion gallons, as reported by EMTS.

Changes in tax laws could materially affect our financial position, results of operations, and cash flows.
The income and non-income tax regimes we are subject to or operate under are unsettled and may be subject to significant change. Changes in tax laws, or changes in interpretations of existing laws, could materially affect our financial position, results of operations, and cash flows. For example, changes to U.S. tax laws enacted in December 2017 may significantly impact our tax obligations and effective tax rate. In addition, many countries globally, including those in which we operate today or may operate in the future, have recently proposed or recommended changes to existing tax laws or have enacted new laws that could significantly impact our tax obligations and affect where we do business or require us to change the manner in which we operate our business.

Uncertainties in the interpretation and application of the 2017 Tax Legislation could materially affect our tax obligations and effective tax rate. 
H.R. 1, formerly known as the Tax Cuts and Jobs Act (the “Tax Legislation”) was enacted on December 22, 2017, and significantly affected U.S. tax law by changing how the U.S. imposes income tax on multinational corporations. The U.S. Department of Treasury has broad authority to issue regulations and interpretative guidance that may significantly impact how we will apply the law and impact our results of operations in the period issued.
The Tax Legislation requires complex computations not previously provided in U.S. tax law. As such, the application of accounting guidance for such items is currently uncertain. Further, compliance with the Tax Legislation and the accounting for such provisions require accumulation of information not previously required or regularly produced. As a result, we have provided a provisional estimate on the effect of the Tax Legislation in our financial statements. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts, which could materially affect our tax obligations and effective tax rate.

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

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 influenced by the price of petroleum-based diesel fuel, adjusted for government incentives supporting renewable fuels, rather than biomass-based diesel production costs. If there is a lack of close correlation between production costs and biomass-based diesel prices, we may be unable to pass increased production costs on

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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 a result of a reduction in biomass-based diesel and RIN 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. The average price at which we sold our biomass-based diesel in 2017 decreased to $3.06 per gallon from $3.17 per gallon in 2016, mainly due to the impact of the lapsing of the BTC throughout 2017. 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 RINs. RIN prices as reported by OPIS ranged from $0.79 to $1.17 per RIN during 2017 while in 2016, RIN prices started the year at $0.75 per RIN and climbed to a high of $1.26 in December. In other years there was more significant volatility in RIN prices. 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 price we are able to charge 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. 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 these emerging technologies compete with biomass-based diesel for feedstocks, are more profitable or have greater governmental support than biomass-based diesel.
At elevated feedstock price levels, certain feedstocks may be uneconomical to use, as we may be unable to pass feedstock cost increases on to our customers. In addition, we generally are unable to enter into forward contracts at fixed prices for some of our feedstocks, such as animal fat, because markets for these feedstocks are less developed.
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, or B100, as reported by The Jacobsen Publishing Company, and the price for the amount of choice white grease necessary to produce one gallon of biomass-based diesel, a common inedible animal fat used by us to make biomass-based diesel, was $1.09 in 2015, $1.28 in 2016 and $1.20 in 2017, 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 biomass-based diesel, based on the nearby futures contract as reported on the Chicago Board of Trade, was $0.58 in 2015, $0.73 in 2016 and $0.64 in 2017, assuming 7.5 pounds of soybean oil yields one gallon of biomass-based diesel. For the periods from 2015 to 2017, approximately 85%, 72% and 73%, respectively, of our annual total feedstock usage was inedible corn oil, used cooking oil or inedible animal fat, and approximately 15%, 28% and 27%, respectively, was virgin vegetable oils. When the spread between biomass-based diesel prices and feedstock prices narrows, our profitability could 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, or 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 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.


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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, or Pilot, accounted for 8% of our revenues in each of 2017, 2016 and 2015. Our revenues from Pilot generally do not include the RINs associated with the gallons of biomass-based diesel sold to Pilot. The value of those RINs represented approximately an additional 9%, 9% and 13% of our total sales in 2017, 2016 and 2015, respectively, based on the OPIS average RIN price for the year. In the event we lose Pilot as a customer or Pilot significantly reduces the volume of biomass-based diesel bought from us, it could be difficult to replace the lost revenues from biomass-based diesel and RINs, 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 other 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 a fire at our Madison facility in June 2017. As a result of these fires, the affected facilities were shut down for lengthy periods while repairs and upgrades were completed.
A majority of our facilities are also located in the Midwest, which is subject to tornado activity. REG Life Sciences' research and development center is in South San Francisco, California, which is subject to earthquakes. In addition, 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. Each of our plants could incur damage from other natural disasters as well. If any of the foregoing events occur, we may incur significant additional costs including, among other things, loss of profits due to unplanned temporary or permanent shutdowns of our facilities, cleanup costs, liability for damages or injuries, legal expenses and reconstruction expenses, which would harm our results of operations and financial condition.

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 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.

Our business is primarily dependent upon two similar products. As a consequence, we may not be able to adapt to changing market conditions or endure any decline in the biomass-based diesel industry.
Our revenues are currently generated almost entirely from the production and sale of biodiesel and renewable diesel, collectively referred to as biomass-based diesel. Our reliance on biomass-based diesel means that we may not be able to adapt to changing market conditions or to withstand any significant decline in the size or profitability of the biomass-based diesel industry. Historically we were required to periodically idle our plants, particularly during the first quarter of the year due to insufficient demand at profitable price points. If we are required to idle our biomass-based diesel plants in the future or are unable to adapt to changing market conditions, our revenues and results of operations may be materially harmed.

We face competition from imported biodiesel and renewable diesel, which may reduce demand for biomass-based diesel produced by us and cause our revenues and profits to decline.
Biodiesel and renewable diesel imports into the United States have increased significantly and compete with biodiesel and renewable diesel produced in the United States. The imported fuels may benefit from production incentives or other financial incentives in foreign countries that offset some of their production costs and enable importers to profitably sell biodiesel or renewable diesel in the United States at lower prices than United States-based biodiesel and renewable diesel producers. Under RFS2, imported biodiesel and renewable diesel is eligible and, therefore, competes to meet the volumetric requirements for biomass-based diesel and advanced biofuels. If imports continue to increase, this could make it more challenging for us to market or sell biomass-based diesel in the United States, which would have a material adverse effect on

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our revenues. In January 2015, the EPA announced the approval for Argentinian biodiesel made from soybean oil to generate RINs. Imported biomass-based diesel that does not qualify under RFS2, also competes in jurisdictions where there are biomass-based diesel blending requirements.
In March 2017, the National Biodiesel Fair Trade Coalition ("Coalition") filed an antidumping and countervailing duty petition with the U.S. Department of Commerce and the U.S. International Trade Commission ("ITC"), arguing that Argentine and Indonesian companies were violating trade laws by flooding the U.S. market with dumped and subsidized biodiesel. The Coalition is made up of the National Biodiesel Board and U.S. biodiesel producers. In May 2017, the ITC agreed to proceed with an investigation regarding this matter. In relation to this antidumping and countervailing duty petition, the Coalition filed a new allegation in July 2017 that "critical circumstances" exist with respect to imports of biodiesel from Argentina. The critical circumstance provision in antidumping and countervailing duties laws allows for the imposition of duties on imports that enter the U.S. prior to preliminary determinations of subsidization and dumping. The Coalition found that imports of biodiesel from Argentina had jumped 144.5 percent since the March 2017 petition was filed.  In December 2017, the International Trade Commission voted 4-0 affirming countervailing duty rates of 34% to 72%.  In February 2018, the Department of Commerce issued a final decision affirming the agency’s earlier preliminary determination that Argentina and Indonesia had dumped biodiesel imports into the U.S.  Final anti-dumping rates were set at 60% to 267%.  A final vote by the International Trade Commission is expected in March or April 2018 which would conclude these proceedings.
If the preliminary rulings are not upheld and Argentine and Indonesian biodiesel imports resume, our business and profits may be harmed.

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. For example, some petroleum refiners are pursuing plans to co-process renewable feedstocks with petroleum crude oil in conventional petroleum refineries. Advances in the process of converting oils and fats into biodiesel and renewable diesel, including co-processing, 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 and retrofit our plants in order to incorporate new technologies and remain competitive. In order to execute our strategy to expand into the production of renewable chemicals, additional advanced biofuels, next generation feedstocks and related renewable products, we may need to acquire licenses or other rights to technology from third parties. We can provide no assurance that we will be able to obtain such 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 sell biomass-based diesel may be harmed, negatively impacting our revenues and profitability.

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

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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 2015 to mid-2016 we saw huge drops in diesel prices in the U.S. However, the last half of 2016 diesel started to trend upward. These movements can be drastic and unpredictable. In addition, rail car prices can be affected by a variety of factors, such as oil production from the Bakken Formation, which has significantly increased the demand for railcars in some of our markets. 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 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 have not generated significant revenues from sales of renewable chemicals to date and we expect to incur additional costs and face significant challenges to develop this business.
In January 2014, we entered the market for renewable chemicals through the acquisition of a development-stage company. To date, we have incurred significant costs and have not generated significant revenues from this business. In order to generate revenue from our renewable chemicals, there must be a willing market for the products and we must be able to produce sufficient quantities of our products, which we have not done to date and would not be able to do on our own without incurring significant capital expenditure to build a commercial scale production facility. There are multiple options for how we could pursue generating revenue from our renewable chemicals business. Some options would require additional capital expenditures prior to generating revenue.
In this market, we would still be selling renewable chemicals as an alternative to chemicals currently in use, and in some cases the chemicals that we seek to replace have been used for many years. The potential customers for our renewable chemical products generally have well developed manufacturing processes and arrangements with suppliers of the chemical components of their products and may resist changing these processes and components. These potential customers frequently impose lengthy and complex product qualification procedures on their suppliers. Factors that these potential customers consider during the product qualification process include consumer preference, manufacturing considerations such as process changes and

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capital, other costs associated with transitioning to alternative components, supplier operating history, regulatory issues, product liability and other factors, many of which are unknown to, or not well understood by, us. Some of our products may also require regulatory registrations and approvals from governmental authorities. The requirements for obtaining regulatory registrations and approvals may change or may take longer than we anticipate. Satisfying these processes may take many months or years.
If we are unable to convince these potential customers that our products are comparable to the chemicals that they currently use, or that the use of our products produce benefits to them, we will not be successful in these markets and our business will be adversely affected. In addition, in contrast to the tax incentives relating to biofuels, tax credits and subsidies are not currently available in the United States for consumer products or chemical companies who use renewable chemical products. We do not expect meaningful revenue from our sale of renewable chemicals in the near term.

The evaluation of strategic alternatives for our life sciences unit may adversely affect our business and may not result in any specific action or transaction.
In November 2016, we announced that our board of directors had authorized a review of strategic alternatives for our life sciences business to enhance value for stockholders. There can be no assurance that this ongoing strategic review will result in any specific action or transaction or that any action taken or transaction we may enter into will prove to be beneficial to stockholders. In addition, the pendency of this strategic review exposes us to risks and uncertainties, including potential difficulties in retaining and attracting key life sciences employees during the review process, distraction of our management from other important business activities, and potential difficulties in establishing or maintaining relationships between this business unit and third parties, all of which could harm our business.

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, 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 outside of the United States is limited. In addition, while the biodiesel market in

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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 restrictions that might restrict or prevent us from repatriating income earned in countries outside the United States;
political, economic and social instability;
higher costs associated with doing business internationally; and
export or import regulations as well as trade and tariff restrictions.
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 biomass-based diesel 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.
Growth in the biomass-based diesel industry depends on substantial 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 generally beyond our control. Also, we compete with other biofuel companies for access to some of the key infrastructure components such as pipeline and terminal capacity. As a result, increased production of biomass-based diesel 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 biomass-based diesel, impede delivery of our biomass-based diesel, 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 biomass-based diesel and any infrastructure disruptions could materially harm our business.

Risks related to the potential permanent idling of our facilities.
We perform strategic reviews of our business, which may include evaluating each of our facilities to assess their viability and strategic benefits. As part of these reviews, we may idle--whether temporarily or permanently--development or operations of certain of our facilities in order to reduce participation in markets where we determine that our returns are not acceptable.
We have three partially constructed plants, one near New Orleans, Louisiana, one in Emporia, Kansas and one in Clovis, New Mexico. We also own one non-operational plant near Atlanta, Georgia. If we decide to permanently idle or abandon development of these facilities or any other facilities or assets, we are likely to incur significant cash expenses, as well as substantial non-cash charges for impairment of those assets. In the fourth quarter of 2016, we recorded an impairment charge of $15.6 million, reflecting the difference between the carrying amount associated with the partially constructed Emporia facility and the estimated salvage value due to the probability that construction of this facility will not be completed in the near term. For the same reason, in the fourth quarter of 2017, we recorded an impairment charge of $44.6 million, reflecting the difference between the carrying amount associated with the partially constructed New Orleans facility and the estimated salvage value.


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We operate in a highly competitive industry and competition in our industry would increase if new participants enter the biomass-based diesel business.
We operate in a very competitive environment. The biomass-based diesel industry is primarily comprised of 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. 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 biomass-based diesel production. Such petroleum refiners include Neste Oil with approximately 882 million gallons of global renewable diesel production capacity in Asia and Europe and Valero Energy Corporation with its Diamond Green joint venture that operates an approximate 160 million-gallon renewable diesel plant and plans to expand the capacity to 275 million gallons. These and other competitors that are divisions of larger enterprises may have greater financial resources than we do.
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.
A volatile regulatory environment, lack of debt or equity investments and volatile biofuel prices and feedstock costs have likely contributed to the necessity of bankruptcy filings by biofuel producers. We may encounter new competition from buyers of distressed biodiesel properties that enter the industry at a lower cost than original plant investors or from competitors consolidating or otherwise growing. Our business has been, and in the future may be, negatively impacted by the industry conditions that influenced the bankruptcy proceedings of other biofuel producers. Our business and prospects may be significantly and adversely affected if we are unable to similarly increase our scale.

Our business is subject to seasonal fluctuations, which are likely to cause our revenues and operating results to fluctuate.
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 biodiesel when they can benefit from the agreed upon value sharing of the BTC with producers of biodiesel. Seasonal fluctuation also occurs in the colder months when historically there has been reduced demand for biodiesel in northern and eastern United States markets, which are the primary markets in which we currently operate.
Biodiesel typically has a higher cloud point than petroleum-based 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.

Our manufacturing facilities, like other fuel and chemical production facilities, are subject to various federal, state and local environmental laws and regulations, including those relating to the discharge of materials into the air, water and ground; the generation, storage, handling, use, transportation and disposal of hazardous materials; ecological and natural resources; and the health and safety of our employees, contractors and the public. These laws and regulations require us to obtain and comply with numerous environmental permits to construct and operate each facility. They can require expensive pollution control equipment or operational changes to limit actual or potential impacts to human health and the environment.

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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 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. 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.

The development of alternative fuels and energy sources may reduce the demand for biodiesel, resulting in a reduction in our revenues and profitability.
The development of alternative fuels, including a variety of energy alternatives to biodiesel has attracted significant attention and investment. Neste Oil operates four renewable diesel plants: a 300 million gallon per year plant in Singapore, a 300 million gallon per year plant in Rotterdam, Netherlands, and two 60 million gallon per year plants in Porvoo, Finland. In the United States, Diamond Green Diesel, LLC operates a 160 million gallon per year renewable diesel plant in Norco, Louisiana, which they have announced they will be expanding to 275 millions gallons per year. Several refiners appear to be pursing plans to co-process renewable feedstocks with petroleum crude oil at their refineries. Under RFS2, renewable diesel made from biomass meets the definition of biomass-based diesel and thus is eligible, along with biodiesel, to satisfy the RFS2 biomass-based diesel requirements. Furthermore, under RFS2, renewable diesel may receive up to 1.7 RINs per gallon, whereas biodiesel currently receives 1.5 RINs per gallon. As the value of RINs increases, this 0.2 RIN advantage may make renewable diesel more cost-effective, both as a petroleum-based diesel substitute and for meeting RFS2 requirements. If renewable diesel proves to be more cost-effective than biodiesel, revenues from our biodiesel plants and our results of operations would be adversely impacted.
In addition, the EPA may allow other fuels to satisfy the RFS2 requirements and allow RINs to be generated upon the production of these fuels. The EPA adopted regulations to amend the definition of “Home Heating Oil” under RFS2, which expands the scope of fuels eligible to generate RINs.
The biomass-based diesel industry will also face increased competition resulting from the advancement of technology by automotive, industrial and power generation manufacturers which are developing more efficient engines, hybrid engines and alternative clean power systems. Improved engines and alternative clean power systems offer a technological solution to address increasing worldwide energy costs, the long-term availability of petroleum reserves and environmental concerns. If and when these clean power systems are able to offer significant efficiency and environmental benefits and become widely available, the biomass-based diesel industry may not be able to compete effectively with these technologies and government requirements for the use of biofuels may be discontinued.

If automobile manufacturers and other industry groups express reservations regarding the use of biodiesel, our ability to sell biodiesel will be negatively impacted.
Because it is a relatively new product compared with petroleum diesel, research on biodiesel use in automobiles is ongoing. While most heavy duty automobile manufacturers have approved blends of up to 20% biodiesel, some industry groups have recommended that blends of no more than 5% biodiesel be used for automobile fuel due to concerns about fuel quality, engine performance problems and possible detrimental effects of biodiesel on rubber components and other engine parts. Although some manufacturers have encouraged use of biodiesel fuel in their vehicles, cautionary pronouncements by other manufacturers or industry groups may impact our ability to market our biodiesel.


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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 would 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, or the 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 biodiversity, invasive species and international impacts. The only such report to date was released in February 2012. The 2012 report concludes that (1) the extent of negative impacts 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. New technology diesel engines eliminate any such increase. Emissions from older vehicles while the fleet turns over 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 has adopted regulations that limits 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 our products 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, 2017, our total term debt before debt issuance costs was $228.6 million. This includes $116.3 million aggregate carrying value on our $152.0 million face amount, 4.00% convertible senior notes due in June 2036, which we refer to as the 2036 Convertible Notes, and $69.9 million aggregate carrying value on our $73.8 million face value, 2.75% convertible senior notes due in June 2019, which we refer to as the 2019 Convertible Notes. We also have short-term debt obligations under revolving credit agreements provided by certain banks. At December 31, 2017, there were $65.5 million of

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borrowings made under our revolving lines of credit. See "Note 10 - Debt" to our Consolidated Financial Statements for a description of our indebtedness.
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 Notes and 2019 Convertible 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 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 the 2036 Convertible Notes, the 2019 Convertible Notes or our other existing indebtedness 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, 2017, we had $53.5 million of undrawn availability under our line of credit with Wells Fargo Bank and Fifth Third Bank ("M&L and Services Revolver"), 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 Notes.
In connection with the issuance of our 2019 Convertible 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 Notes will have the right to require us to repurchase their 2019 or 2036 Convertible 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 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.

23



In addition, upon conversion of the 2019 or 2036 Convertible Notes, unless we elect to deliver solely shares of our common stock to settle such conversion (other than paying cash in lieu of delivering any fractional share), we will be required to make cash payments in respect of the 2019 or 2036 Convertible Notes being converted. 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 Notes upon a fundamental change or to settle conversion of the 2019 or 2036 Convertible Notes in cash.
In addition, our ability to repurchase the 2019 or 2036 Convertible Notes may be limited by law, by regulatory authority or by agreements governing our future indebtedness. Our failure to repurchase 2019 or 2036 Convertible 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 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 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 Notes could delay or prevent an otherwise beneficial takeover or takeover attempt of us.
Certain provisions in the 2019 or 2036 Convertible 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 Notes will have the right to require us to repurchase their 2019 or 2036 Convertible 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 Notes in connection with such takeover. In either case, and in other cases, our obligations under the 2019 or 2036 Convertible 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

24



Revolver is less than 10% of the total $150 million of current revolving loan commitments, or $15 million. As of December 31, 2017, availability under the M&L and Services Revolver was approximately $53.5 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, 2017, the fixed charge coverage ratio for our M&L and Services Revolver was approximately 0.014, 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 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; 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, 2016 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. For example, in connection with the preparation of our

25



quarterly report for the third quarter of 2016, we identified a material weakness in internal control over financial reporting relating to our biomass-based diesel sales contract review process, which has been subsequently remediated.
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:
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, or 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 Okeechobee, which is used by our Renewable Chemicals segment.

26



PRODUCTION FACILITIES - NORTH AMERICA
Location
 
Use
 
Nameplate
Production
Capacity
(mmgy)
Ralston, Iowa#
 
Biomass-based diesel production
 
30
Seabrook, Texas
 
Biomass-based diesel production
 
35
Danville, Illinois
 
Biomass-based diesel production
 
45
Newton, Iowa
 
Biomass-based diesel production
 
30
Seneca, Illinois
 
Biomass-based diesel production
 
60
Albert Lea, Minnesota
 
Biomass-based diesel production
 
30
New Boston, Texas
 
Biomass-based diesel production
 
15
Ellenwood, Georgia
 
Biomass-based diesel production
 
15
Mason City, Iowa
 
Biomass-based diesel production
 
30
Geismar, Louisiana*
 
Biomass-based diesel production
 
75
Grays Harbor, Washington
 
Biomass-based diesel production
 
100
DeForest, Wisconsin
 
Biomass-based diesel production
 
20
Okeechobee, Florida
 
Fermentation facility
 
N/A
# Ralston's expansion, which was completed on March 6, 2018, increased the facility's nameplate capacity from 12 mmgy to 30 mmgy.
* This facility produces renewable diesel, naphtha, and liquid petroleum gas.
Our Ellenwood, Georgia facility was idled by the previous owners prior to our acquisition and will remain so until repairs or upgrades are made and the facility meets our standards. We have not yet set a production date for our Ellenwood facility.
PRODUCTION FACILITIES - EUROPE
Location
 
Use
 
Nameplate
Production
Capacity
(mmgy)
Emden, Germany
 
Biomass-based diesel production
 
27
Oeding, Germany
 
Biomass-based diesel production
 
23
The following table lists our partially constructed or idled biomass-based diesel production facilities, the planned nameplate capacity and the approximate level of completion. The Clovis facility is currently being operated as a terminal. We recorded an impairment charge relating to our Emporia and New Orleans facilities due to them not likely being completed in the near term.
PARTIALLY CONSTRUCTED FACILITIES
Location
 
Use
 
Nameplate Production
Capacity
(mmgy)
 
Approximate
Completion
Level
St. Rose, Louisiana
 
Biomass-based diesel production
 
60
 
45%
Emporia, Kansas
 
Biomass-based diesel production
 
60
 
20%
Clovis, New Mexico
 
Biomass-based diesel production
 
15
 
50%
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.

27



ITEM 3.
Legal Proceedings
We are not a party to any material pending legal proceeding, nor is any of our property the subject of any material pending legal proceeding, except ordinary routine litigation arising in the ordinary course of our business and incidental to our business, none of which is expected to have a material adverse impact upon our 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. The table below sets forth the high and low sales price of our common stock in each quarter of 2017 and 2016.
2017
High
 
Low
Fourth Quarter
$
12.55

 
$
10.45

Third Quarter
$
13.55

 
$
10.76

Second Quarter
$
13.05

 
$
9.82

First Quarter
$
10.50

 
$
8.25

 
 
 
 
2016
High
 
Low
Fourth Quarter
$
10.60

 
$
8.10

Third Quarter
$
9.90

 
$
7.90

Second Quarter
$
10.43

 
$
8.31

First Quarter
$
9.59

 
$
6.53

Holders
As of February 28, 2018, there were approximately 2,032 holders of record of our common stock.
Dividends
We have never paid, and do not intend to pay in the future, a cash dividend on our common stock. We have entered into agreements that contractually restrict certain of our subsidiaries from paying dividends, making distributions or making loans to our parent company or to any other subsidiaries.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides certain information as of December 31, 2017, with respect to our equity compensation plans:
PLAN CATEGORY
NUMBER OF
SECURITIES
TO BE ISSUED
UPON
EXERCISE OF
OUTSTANDING
OPTIONS,
WARRANTS
AND RIGHTS
 
 
WEIGHTED
AVERAGE
EXERCISE
PRICE OF
OUTSTANDING
OPTIONS,
WARRANTS
AND RIGHTS
 
 
NUMBER OF
SECURITIES
REMAINING
AVAILABLE
FOR FUTURE
ISSUANCE
UNDER EQUITY
COMPENSATION
PLANS
Equity compensation plans approved by stockholders
2,944,778

1 
 
$
10.20

2 
 
1,175,066

Equity compensation plans not approved by stockholders

 
 

 
 

Total
2,944,778

 
 
$
10.20

 
 
1,175,066

1
Includes 888,391 shares underlying outstanding restricted stock units, 355,118 shares underlying outstanding performance restricted stock units, and 1,701,269 shares underlying outstanding stock appreciation rights.

28



2
Restricted stock units and performance restricted stock units do not have an exercise price and therefore have not been included in the calculation of weighted average exercise price.
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.
The following graph shows a comparison of the cumulative total returns from January 19, 2012 to December 31, 2017, for us, the Elements MLCX Biofuels ETN Index and the Russell 3000 Index. 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.
a2017graphstockperf02.jpg
 
01/19/2012

 
12/31/2012

 
12/31/2013

 
12/31/2014

 
12/31/2015

 
12/31/2016

 
12/31/2017

REGI
$
100.00

 
$
58.60

 
$
114.60

 
$
97.10

 
$
92.50

 
$
97.00

 
$
104.50

Elements MLCX Biofuels ETN
100.00

 
108.00

 
93.44

 
84.57

 
72.32

 
73.77

 
79.56

Russell 3000
100.00

 
109.17

 
142.96

 
157.50

 
155.58

 
171.77

 
180.78

Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.



29



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.
The selected consolidated balance sheet data as of December 31, 2017 and 2016, and the selected consolidated statements of operations data for each year ended December 31, 2017, 2016 and 2015, 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, 2015, 2014 and 2013, and the selected consolidated statements of operations data for the years ended December 31, 2014 and 2013 have been derived from our audited consolidated financial statements not included in this annual report.
 
Year Ended December 31,
 
2017(1)
 
2016 (2)
 
2015 (3)
 
2014 (4)
 
2013
 
(In thousands, except per share amounts)
Consolidated Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total revenues
$
2,158,243

 
$
2,041,232

 
$
1,387,344

 
$
1,273,831

 
$
1,498,138

Net income (loss) attributable to the company's common stockholders
(79,079
)
 
43,453

 
(151,392
)
 
81,620

 
165,254

Net income (loss) per share attributable to common stockholders
 
 
 
 
 
 
 
 
 
Basic
(2.04
)
 
1.06

 
(3.44
)
 
2.00

 
5.00

Diluted
(2.04
)
 
1.06

 
(3.44
)
 
1.99

 
5.00

 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheet Data:
 
Total assets
$
1,005,596

 
$
1,136,603

 
$
1,223,620

 
$
1,367,736

 
$
740,855

Long-term debt
208,536

 
196,203

 
247,251

 
242,031

 
27,151

Redeemable preferred stock

 

 

 

 
3,963


(1)
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 11, respectively, of Item 8 - Financial Statements and Supplementary Data.
(2)
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 10 and Note 2, respectively, of Item 8 - Financial Statements and Supplementary Data.
(3)
Includes the impact of goodwill impairment as further described in Note 2 of Item 8 - Financial Statements and Supplementary Data.
(4)
Includes the issuance of the convertible senior notes on June 3, 2014 as further described in Note 10 of Item 8 - Financial Statements and Supplementary Data.

30



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 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 products and services. 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 are also engaged in research and development efforts focused on the conversion of diverse feedstocks into various renewable chemicals, advanced biofuels and other products. 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 biomass-based diesel, other advanced biofuels and other products and services.
During 2017, we sold 587 million gallons of fuel, which included 52 million biomass-based gallons we purchased from third parties, 38 million biomass-based diesel gallons produced by REG Germany and 83 million petroleum-based diesel gallons. During 2016, we sold 567 million gallons, including 77 million gallons we purchased from third parties and resold, 45 million biomass-based diesel gallons by REG Germany and 54 million petroleum-based diesel gallons.
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 microbial fermentation facility used in connection with our development of renewable chemicals. Our thirteen biomass-based diesel production facilities have an aggregate nameplate production capacity of 520 million gallons per year (“mmgy”).
In January 2017, we completed the acquisition of the remaining minority interest in Petrotec AG. Our operations in Germany utilize used cooking oil and other waste feedstocks to produce biomass-based diesel at our two biorefineries in Emden and Oeding, Germany. Our nameplate production capacity in Germany is approximately 50 mmgy.
We are a lower-cost biomass-based diesel producer. We primarily produce our biomass-based diesel from a wide variety of lower cost 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 are more widely available, but tend to be higher in price. We believe our ability to process a wide variety of feedstocks 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 additional biofuel blends, while expanding our 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 2015, we expanded our sales of biofuel blends to Midwest terminal locations and look to potentially expand in other areas across North America.
Our development-stage industrial biotechnology business is developing proprietary microbial fermentation processes to produce renewable chemicals, fuels and other products. Fatty acids are one of three product areas that we are focused on, along with esters and alcohols.
Our businesses are organized into three reportable segments - the Biomass-based Diesel segment, the Services segment and the Renewable Chemicals segment. As the activities surrounding our renewable chemicals business increase, we began reporting in 2015 a new segment - Renewable Chemicals, which was previously included in the Biomass-based Diesel segment.
Biomass-based Diesel Segment
Our Biomass-based Diesel segment, as reported herein, includes:
the operations of the following biomass-based diesel production facilities:
a 30 mmgy nameplate biomass-based diesel production facility located in Ralston, Iowa;
a 35 mmgy nameplate biomass-based diesel production facility located near Houston, Texas;
a 45 mmgy nameplate biomass-based diesel production facility located in Danville, Illinois;
a 30 mmgy nameplate biomass-based diesel production facility located in Newton, Iowa;
a 60 mmgy nameplate biomass-based diesel production facility located in Seneca, Illinois;
a 30 mmgy nameplate biomass-based diesel production facility located near Albert Lea, Minnesota;

31



a 15 mmgy nameplate biomass-based diesel production facility located in New Boston, Texas;
a 30 mmgy nameplate biomass-based diesel production facility located in Mason City, Iowa;
a 75 mmgy nameplate renewable diesel production facility located in Geismar, Louisiana;
a 27 mmgy nameplate biomass-based diesel production facility located in Emden, Germany;
a 23 mmgy nameplate biomass-based diesel production facility located in Oeding, Germany;
a 100 mmgy nameplate biomass-based diesel production facility located in Grays Harbor, Washington; and
a 20 mmgy nameplate biodiesel production facility located in DeForest, Wisconsin.
purchases and resale of biomass-based diesel, petroleum-based diesel, Renewable Identification Numbers, or RINs, California Low Carbon Fuel Standard Credits, or 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 glycerin, free fatty acids, naphtha and other co-products of the biomass-based diesel production process. In 2017 and 2016, our revenues from the sale of co-products were less than five percent of our total Biomass-based diesel segment revenues. During 2017 and 2016, 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 at wholly owned facilities or purchased from third parties, were approximately 7% and 5% 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 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. We generally attach 1.5 to 1.7 RINs when we sell a gallon of biomass-based diesel. As a result, 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 with gallons of biomass-based diesel, may be separated by the acquirer and sold separately. We regularly acquire RINs from third parties for resale. The value of these RINs obtained from third parties 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, 2017, we had approximately 37.8 million biomass-based diesel RINs and 1.2 million advanced biofuel RINs available to be sold, as compared to 16.8 million biomass-based diesel RINs and 0.2 million advanced biofuel RINs held for sale at December 31, 2016, respectively. According to the Oil Pricing Information System ("OPIS"), the median closing price at December 31, 2017 for biomass-based diesel RINs and advanced biofuel RINs was $0.79 and $0.78, respectively, compared to $1.05 and $1.06, respectively, at December 31, 2016.
We generate Low Carbon fuel Standard credits for our low carbon fuels or blendstocks when our qualified low carbon fuels are imported into California. LCFS credits are used to track compliance with California’s LCFS. As a result, a portion of the selling price for a gallon of biomass-based diesel sold into California 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, 2017, we held for sale approximately 5,700 LCFS credits, an increase from 5,000 credits at December 31, 2016. According to OPIS, the median closing price per LCFS credit at December 31, 2017 and December 31, 2016 was $113.00 and $93.00, respectively.
Services Segment
Our Services 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 as well as other clean-tech companies; and
construction management services, whereby we act as the construction management and general contractor for the construction of biomass-based diesel production facilities.
During recent years, we have utilized our construction management expertise internally to upgrade our facilities, such as our facilities located in Albert Lea, New Boston, Mason City and Newton. In October 2016, we completed a $34.5 million

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upgrade to our Danville facility. In November 2016, we started a $24 million expansion project at our Ralston facility, which was completed ion March 6, 2018. In June 2017, we completed the $20 million 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.
Renewable Chemicals Segment
Our Renewable Chemicals segment includes:
research and development activities focusing on microbial fermentation to develop and produce renewable chemicals, additional advanced biofuels and other products;
collaborative research and development and other service activities to continue to build out the technology platform; and
the operations of a demonstration scale fermentation facility located in Okeechobee, Florida since its acquisition in January 2014.
In January 2016, ExxonMobil Research and Engineering Company entered into an agreement with us to develop technology for the production of biodiesel by fermenting renewable cellulosic sugars from sources such as agricultural waste. In September 2017, we signed a phase II joint development collaboration with ExxonMobil Research and Engineering to continue to develop technology to produce biodiesel fermenting renewable cellulosic sugars from sources such as agricultural waste. In October 2016, we sold and delivered our first commercial product, a specialty fatty acid. We developed, produced, sold, and delivered approximately one metric ton of the renewable, multi-functional chemical to Aroma Chemical Services International. Fatty acids are one of three product areas we have focused on, along with esters and alcohols. During November 2016, the Company's Board of Directors authorized a review of strategic alternatives for our Life Sciences business. There can be no assurance that this ongoing strategic review will result in any specific action or transaction or that any action taken or transaction we may enter into will prove to be beneficial to stockholders.
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 biomass-based diesel.
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.
On July 1, 2010, RFS2 was implemented, 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 production meets three categories of an Obligated Party’s annual renewable fuel required volume obligation, or RVO—biomass-based diesel, undifferentiated advanced biofuel and renewable fuel. The final RVO targets for the biomass-based diesel volumes for the years 2015 to 2019 as set by the EPA are as follows:
 
2015
2016
2017
2018
2019
Biomass-based diesel
1.73 billion gallons
1.90 billion gallons
2.00 billion gallons
2.10 billion gallons
2.10 billion gallons
Actual production or imports increased significantly in 2016 and modestly decreased in 2017 due to the preliminary result of the trade case as illustrated by the EMTS data noted below:
 
2015
2016
2017
Biomass-based diesel volume produced or imported
1.81 billion gallons
2.60 billion gallons
2.50 billion gallons

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The federal biodiesel mixture excise tax credit, or the BTC, has generally 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 Protecting Americans from Tax Hikes Act of 2015 was signed into law, which reinstated and extended a set of tax provisions, including the retroactive reinstatement for 2015 and extension for 2016 of the BTC. The BTC lapsed again on December 31, 2016.
As a result of this history of retroactive reinstatement of the BTC, 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. The 2017 BTC was retroactively reinstated on February 9, 2018, but has not been enacted for 2018. We estimate that the reinstatement of the 2017 BTC will result in a net benefit to our Adjusted EBITDA for the year ended December 31, 2017 by approximately $205 million, with another $11 million related to sales delivered and recognized after year end largely to be recognized during the quarter ending March 31, 2018. It is uncertain whether the BTC will be reinstated for 2018 and beyond, and if reinstated, whether it would be reinstated on the same terms. The lapsing or modification of the BTC could have a material adverse effect on our financial results.
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 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 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 2015, 2016 and 2017 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.
rinpricevsb100pricecharta18.jpg
 

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Value of RINs acquired from third parties and held in inventory remained fairly stable in 2017 and resulted in a $4.5 million write-down to the lower of cost or net realizable value for the year ended December 31, 2017. The fluctuations in the value of RINs during 2016 and 2015 resulted in write-downs of $19.4 million and $9.0 million, respectively, on RIN inventory acquired from third parties. At December 31, 2017, the write-down to lower of cost or net realizable value of RINs was $2.6 million. See “Note 8 – Other Assets” to our Condensed Consolidated Financial Statements. We enter into forward contracts to sell RINs and we use risk management position limits to manage RIN exposure.
During 2017, feedstock expense accounted for 80% of our production cost, while methanol and chemical catalysts expense accounted for 3% and 4% of our costs of goods sold, respectively.
Feedstocks for biomass-based diesel production, such as inedible corn oil, used cooking oil, inedible animal fat 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 fuels. There are a number of factors that influence the supply and price our feedstocks, such as the following: export demand; biomass-based diesel capacities and demand; government policies and subsidies; weather conditions; ethanol production; cooking habits and eating habits; number of restaurants near collection facilities; hog/beef/poultry slaughter kills; palm oil supply; crop production both U.S. and South America; and soybean meal demand and/or production among others.
During 2017 and 2016, 73% and 72% of our feedstocks, respectively, were comprised of inedible corn oil, used cooking oil and inedible animal fats with the remainder coming from virgin vegetable oil.
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 a lower cost feedstock for the period December 2012 through December 2017. 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.
graphsbospreada30.jpg
(1)
Used cooking oil prices 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 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 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) 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 of choice white grease and soybean oil on a per gallon basis compared to the sale price data for biodiesel, and the spread between the two, from December 2012 to December 2017.

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graphspreadpricinga29.jpg
(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 the fourth quarter of 2017, NY Harbor ULSD prices ranged from a high of $2.0755 per gallon in December to a low of $1.7352 per gallon in October with the average price for the quarter of $1.8870 per gallon. Energy prices increased throughout the fourth quarter of 2017, which was driven by consistent draws in domestic crude supplies coupled with a weakening U.S. dollar. These items helped lead to a 17% price increase in ULSD during the fourth quarter of 2017. European used cooking oil methyl ester prices declined during the fourth quarter of 2017, as there was an increase in imports from Argentina during the quarter. Feedstock supplies were larger than prior year, which were offset by strong demand that drove pricing higher until the second half of December. Soybean oil prices ranged from a high of $0.3537 per pound in November to a low of $0.3228 per pound in October with an average price for the quarter of $0.3372 per pound. Soybean oil prices traded within a $0.0309 range during the quarter and trended lower at the end of the quarter mainly due to the near-record soybean crop production and slightly lower soybean exports. 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 slaughter numbers in the fourth quarter of 2017 were again higher than the prior year.
In March 2017, the National Biodiesel Fair Trade Coalition ("Coalition") filed an antidumping and countervailing duty petition with the U.S. Department of Commerce and the U.S. International Trade Commission ("ITC"), arguing that Argentine and Indonesian companies were violating trade laws by flooding the U.S. market with dumped and subsidized biodiesel. The Coalition is made up of the National Biodiesel Board and U.S. biodiesel producers. In May 2017, the ITC agreed to proceed with an investigation regarding this matter. In relation to this antidumping and countervailing duty petition, the Coalition filed a new allegation in July 2017 that "critical circumstances" exist with respect to imports of biodiesel from Argentina, which would allow for the imposition of duties on imports that enter the U.S. prior to preliminary determinations of subsidization and dumping. The Coalition found that imports of biodiesel from Argentina had jumped 144.5% since the March 2017 petition was filed.  In December 2017, the International Trade Commission voted 4-0 affirming countervailing duty rates of 34% to 72%.  In February 2018, the Department of Commerce issued a final decision affirming the agency’s earlier preliminary determination that Argentina and Indonesia had dumped biodiesel imports into the U.S.  Final anti-dumping rates were set at 60% to 267%.  A final vote by the International Trade Commission is expected in March or April 2018 which would conclude these proceedings.

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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, including 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 each of 2015, 2016 and 2017. 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 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 futures 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 fuel and 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 and value at risk to manage RIN exposure.
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 when 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 losses of $23.4 million from our derivative financial instrument trading activity for the year ended December 31, 2017, compared to risk management losses of $35.4 million for the year ended December 31, 2016. 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 2017 and 2016, risk management losses resulted mostly from the significant volatility in the energy market and accounted for a loss of $0.04 and $0.06 per gallon sold, respectively. In general, these losses were largely off-set with physical product sales that benefit from the higher energy prices which drove the risk management losses.
Seasonality
Our operating results are influenced by seasonal fluctuations in the demand for biodiesel. Biodiesel demand tends to decrease during the winter season in the Northern and Midwestern states due to reduced blending concentrations because colder temperatures can cause the higher cloud point biodiesel we make from inedible animal fats to become cloudy and eventually

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gel at a higher temperature than petroleum-based diesel or 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 higher cloud point biodiesel. In addition, most of our production facilities are located in colder Midwestern states and our costs of shipping increases as more biodiesel is transported to warmer climate states during winter. The seasonable demand factor is somewhat offset by higher blended heating oil demand in the Northeastern United States.
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 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 decrease as the calendar year progresses if the RIN market is oversupplied compared to that year's RVO and prices may 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.
Year
 
RIN Generation (D4 Biomass-based Diesel)
 
Finalized RVO level for D4 Biomass-based Diesel
2015
 
1.81 billion gallons
 
1.73 billion gallons
2016
 
2.60 billion gallons
 
1.90 billion gallons
2017
 
2.50 billion gallons
 
2.00 billion gallons
Industry capacity and production
Our operating results are influenced by our industry’s capacity and production, including in relation to RFS2 production requirements. According to EMTS data, approximately 1.1 billion gallons of biomass-based diesel was produced in the United States in 2011, primarily reflecting the recommencement of, or increase in, operations at underutilized facilities in response to RFS2 requirements. Such production was in excess of the 800 million gallon RFS2 requirement for 2011. During 2012, according to EMTS data, approximately 1.1 billion gallons of biomass-based diesel was produced, which also was above RFS2 required volumes of 1 billion gallons of biomass-based diesel for 2012. As reported by EMTS, the biomass-based diesel RIN generation was 1.78 billion gallons in 2013 when the RVO for biomass-based diesel was 1.28 billion. Biomass-based diesel production, as reported by EMTS was 1.81 billion gallons for 2015, 600 million gallons higher than 2014. In 2016, according to EMTS data, 2.6 billion gallons of biomass-based diesel was produced and/or imported into the U.S. The amount of biomass-based diesel produced and/or imported into the U.S in 2017 was 2.50 billion gallons.
During 2017 and 2016, 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, based on the information from the Energy Information Administration. Imported gallons will likely make up less of a percentage of the RVO, as the EPA has approved a plan to allow Argentinian biodiesel made from soybean oil to qualify for RINs generation however mitigated by the anti-dumping and countervailing duty trade case mentioned previously. Under RFS2, Obligated Parties are entitled to satisfy up to 20% of their annual requirement with prior year RINs.
Components of Revenues and Expenses
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 biodiesel produced at our wholly owned facilities;
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:

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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.
We derive revenues in our Renewable Chemicals segment from the following sources:
collaborative research and development and other service revenue for research and development activities to continue to build out the technology platform; and
sales of renewable chemical products.
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 finished goods 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
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.
Cost of goods sold for our Renewable Chemicals segment includes:
research and development activities specifically related to the collaborative research and development projects; and
with regards to our production of renewable chemical 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.
Selling, general and administrative expense consists of expenses generally involving corporate overhead functions and operations at our Ames, Iowa, international operations and regional offices.
Research and development expenses are mainly related to activities of our Renewable Chemicals segment, which is seeking to bring industrial biotechnology products to market and drive growth.
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, 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.

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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 provide 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:
Revenue recognition.
We recognize revenues from the following sources:
the sale of biomass-based diesel, including RINs, LCFS credits, biomass-based diesel co-products and raw material feedstocks purchased by us or produced by us at owned manufacturing facilities, leased manufacturing facilities and manufacturing facilities with which we have tolling arrangements;
resale of finished biomass-based diesel, including RINs, LCFS credits 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 items further blended with biodiesel produced at our facilities or purchased from third parties;
fees received under toll manufacturing agreements with third parties;
fees received from federal and state incentive programs for renewable fuels;
fees received for the marketing and sales of biomass-based diesel produced by third parties; and
revenue from collaborative research and development and other service activities.
Biomass-based diesel sales as well as RINs, LCFS credits and raw material feedstock revenues are recognized when there is persuasive evidence of an arrangement, delivery has occurred, the price has been fixed or is determinable and collectability can be reasonably assured.
Revenues associated with governmental incentive programs are recognized when the amount to be received is determinable, collectability is reasonably assured and the sale of product giving rise to the incentive has been recognized. Our revenue from governmental incentive programs is generally comprised of amounts received from the USDA Advanced Biofuel Program, or the USDA Program, and the biodiesel tax credit. For a discussion of the biodiesel tax credit, see the section entitled “Risk factors-Loss of or reductions in tax incentives for biomass-based diesel production or consumption may have a material adverse effect on industry revenues and operating margins” and “Factors Influencing Our Results of Operations-Governmental programs favoring biomass-based diesel production and use.” In connection with the biodiesel tax credit, we file a claim with the Internal Revenue Service, or IRS, for a refund of excise taxes each week for gallons we have blended to B99.9 and sold during the prior week. The biodiesel tax credit provided a $1.00 refundable tax credit per gallon. On December 18, 2015, the Protecting Americans from Tax Hikes Act of 2015 was signed into law, which reinstated and extended a set of tax provisions, including the retroactive reinstatement for 2015 and extension for 2016 of the federal biodiesel mixture excise tax credit, which lapsed after December 31, 2016. The 2017 BTC was retroactively reinstated on February 9, 2018, and has not been reinstated for 2018. We estimate that the reinstatement of the 2017 BTC will result in a net benefit to our Adjusted EBITDA for the year ended December 31, 2017 by approximately $205 million and another $11 million to be recognized during the year ending December 31, 2018.
Fees for managing ongoing operations of third party plants, marketing biomass-based diesel produced by third party plants and from other services are recognized as services are provided. We also have performance-based incentive agreements that are included as management service revenues. These performance incentives are recognized as revenues when the amount to be received is determinable and collectability is reasonably assured.
Effective January 1, 2018, we will be required to adopt the new guidance of ASC Topic 606, Revenue from Contracts with Customers (Topic 606), which will supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition. Topic 606 requires us to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new guidance requires us to apply the following steps: (1) identify the contract with a customer; (2) identify the performance

40



obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when, or as, we satisfy a performance obligation. We have substantially completed our impact assessment and determined that the majority of our contracts will continue to be recognized at a point in time and that the number of performance obligations and the accounting for variable consideration are not expected to be significantly different from current practice. Additionally, we will adopt Topic 606 on a modified retrospective basis and provide additional disclosures of the amount by which each financial statement line item is affected in the current reporting period, as compared to the guidance that was in effect before the change, and an explanation of the reasons for significant changes. The adoption of this new guidance will require expanded disclosures in our consolidated financial statements.
Income Taxes
The Company’s income tax provision, deferred income tax assets and liabilities, and liabilities for uncertain tax benefits represent the company’s best estimate of current and future income taxes to be paid. The annual tax rate is based on income tax laws, statutory tax rates, taxable income levels and tax planning opportunities available in various jurisdictions where the company operates. 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 the company’s 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 the company determines 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, such as determining the transition tax, re-measuring our U.S. deferred tax assets and liabilities as well as reassessing the net realizability of our deferred tax assets and liabilities.
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. Since the Tax Legislation was passed late in the fourth quarter of 2017 and ongoing guidance and accounting interpretation is expected over the next 12 months, we consider the accounting for the transition tax, global intangible low-taxed income (“GILTI”) and a new base erosion anti-abuse tax (“BEAT”) to be incomplete due to the forthcoming guidance and our ongoing analysis of final year-end data and tax positions. In accordance with SAB 118, we recorded a provisional tax benefit of $13.7 million, and we expect to complete our analysis and establish applicable accounting policies regarding GILTI and BEAT within the measurement period.
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. As a result of the enactment of the Tax Legislation, management’s judgment is that the Company is provisionally no longer indefinitely reinvested in the undistributed earnings of non-US subsidiaries at December 31, 2017. The change in assertion regarding undistributed non-US earnings does not have a material impact on the company’s consolidated financial statements. Although the Company is not indefinitely reinvested in the earnings of its non-US subsidiaries, a provision for U.S. income taxes or foreign withholding taxes has not been recorded due to provisional accumulated tax deficits outside of the U.S causing the outside tax basis to be in excess of the financial reporting carrying amount for the non-U.S. subsidiaries. For further information on income taxes, see Note 11 to the consolidated financial statements.

41



Results of Operations
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 B100 price per gallon
$
3.06

 
$
3.17

 
 
 
 
Revenues
$
2,158,243

 
$
2,041,232

Costs of goods sold
2,074,662

 
1,869,716

Gross profit
83,581

 
171,516

Selling, general and administrative expenses
93,425

 
88,285

Research and development expense
14,091

 
18,163

Impairment of property, plant and equipment
49,873

 
17,893

Income (loss) from operations
(73,808
)
 
47,175

Other income (expense), net
(35,761
)
 
1,806

Income tax benefit (expense)
30,490

 
(4,268
)
Net income (loss)
(79,079
)
 
44,713

Less—Net income (loss) attributable to noncontrolling interests

 
386

Net income (loss) attributable to the Company
(79,079
)
 
44,327

Effects of participating share-based awards

 
(874
)
Net income (loss) attributable to the Company’s common stockholders
$
(79,079
)
 
$
43,453

Revenues. Our total revenues increased $117.0 million, or 6%, to $2,158.2 million for the year ended December 31, 2017, from $2,041.2 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 throughout 2017 and lower average selling price. The majority of the increase in 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 of in 2017 as the 2017 BTC was not reinstated until February 9, 2018. Our average B100 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.
Our other segments had an increase of $2.5 million in revenues, which was mainly related to the joint development collaboration progress at our life sciences business.
Costs of goods sold. Our costs of goods sold increased $204.9 million, or 11%, to $2,074.7 million for the year ended December 31, 2017, from $1,869.7 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

42



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. The three-year average for the 2017 period, which incorporates 2017 risk management losses, represents an average loss of $0.01 per gallon sold, as compared to the prior year's three-year average gain of $0.05 per gallon. 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 each of 2017 and 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.
Research and development expense. Our research and development expenses were $14.1 million for the year ended December 31, 2017, compared to $18.2 million for the year ended December 31, 2016. The majority of the research and development expenses involved our life sciences business. The decrease from the prior year is attributable to cost reductions implemented in connection with management's ongoing cost containment efforts.
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 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. 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 $35.8 million for the year ended December 31, 2017, compared to other income of $1.8 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 $37.6 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 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, offset by a lower loss in fair value of contingent considerations of $5.4 million.
Income tax benefit (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 the U.S. corporate income tax rate from 35% to 21%, including a re-measurement of deferred tax liabilities and the release of valuation allowance due to the reclassification of the 2036 Convertible 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. We have an income tax receivable of $6.4 million and $4.5 million as of December 31, 2017 and 2016, respectively.
Effects of participating share-based awards. Effects of participating restricted stock units was $0.0 and $0.9 million for the years ended December 31, 2017 and 2016, respectively.
Fiscal years ended December 31, 2016 and December 31, 2015
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:

43



 
Twelve Months Ended
December 31,
 
2016
 
2015
Gallons sold
567.1

 
374.7

Average B100 price per gallon
$
3.17

 
$
2.97

 
 
 
 
Revenues
$
2,041,232

 
$
1,387,344

Costs of goods sold
1,869,716

 
1,276,801

Gross profit
171,516

 
110,543

Selling, general and administrative expenses
88,285

 
73,397

Research and development expense
18,163

 
16,851

Impairment of property, plant and equipment
17,893

 

Impairment of goodwill

 
175,028

Income (loss) from operations
47,175

 
(154,733
)
Other income (expense), net
1,806

 
(5,678
)
Income tax benefit (expense)
(4,268
)
 
8,701

Net income (loss)
44,713

 
(151,710
)
Less---Net income (loss) attributable to noncontrolling interest
386

 
(318
)
Net income (loss) attributable to the Company
44,327

 
(151,392
)
Effects of participating share-based awards
(874
)
 

Net income (loss) attributable to the Company’s common stockholders
$
43,453

 
$
(151,392
)
Revenues. Our total revenues increased $653.9 million, or 47%, to $2,041.2 million for the year ended December 31, 2016, from $1,387.3 million for the year ended December 31, 2015. This increase was primarily due to a 51% increase in gallons sold and increased government incentives revenues, as well as improving average selling prices throughout the year as a result of a more stable energy market. The majority of the increase in the gallons sold was a result from the Grays Harbor and Geismar operating throughout 2016 and the Madison facility from March 2016.
Biomass-based diesel revenues including government incentives increased $651.9 million, or 47%, to $2,039.1 million during the year ended December 31, 2016, from $1,387.1 million for the year ended December 31, 2015. The BTC contributed $100.8 million to the increase in biomass-based diesel revenue for the year ended December 31, 2016. Our average B100 sales price per gallon increased $0.20, or 7%, to $3.17 during the year ended December 31, 2016, compared to $2.97 during the year ended December 31, 2015. The increase in average sales price from 2015 to 2016 contributed to a $74.9 million revenue increase when applied to the number of gallons sold during 2015. Gallons sold increased 192.4 million, or 51%, to 567.1 million during the year ended December 31, 2016, compared to 374.7 million during the year ended December 31, 2015. The increase in gallons sold for the year ended December 31, 2016 accounted for a revenue increase of $609.9 million using 2016 average sales pricing. During 2016, we recorded $15.1 million in an initial and partial settlement of our business interruption insurance claim related to the September 2015 fire at our Geismar facility as an increase to our biomass-based diesel revenues. Sales of separated RIN inventory were $274.8 million and $186.5 million for the years ending December 31, 2016 and 2015, respectively.
Costs of goods sold. Our costs of goods sold increased $592.9 million, or 46%, to $1,869.7 million for the year ended December 31, 2016, from $1,276.8 million for the year ended December 31, 2015. Costs of goods sold as a percentage of revenues were 92% for the years ended December 31, 2016 and 2015.
Biomass-based diesel costs of goods sold increased in 2016 due to a 51% increase in gallons sold. Average lower cost feedstocks prices for the year ended December 31, 2016 were $0.28 per pound, compared to $0.27 per pound for the year ended December 31, 2015. Average soybean oil costs for the year ended December 31, 2016 were $0.33 per pound in comparison to $0.32 per pound for the year ended December 31, 2015. We recorded risk management losses of $35.4 million from our derivative financial instrument activity in 2016, compared to risk management gains of $36.0 million for 2015. This fluctuation in risk management gains and losses was mainly due to the volatility in the commodities market. The current three-year average, which incorporates 2016 risk management losses, represents an average income of $0.05 per gallon sold. In addition, the movements in the value of RINs during 2016 resulted in a $19.4 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 $9.0 million during 2015. Costs of goods sold for separated RIN inventory sales excluding lower of cost write-downs were $231.4 million and $173.7 million for the years ending December 31, 2016 and 2015, respectively.

44



Selling, general and administrative expenses. Our selling, general and administrative, or SG&A, expenses were $88.3 million for the year ended December 31, 2016, compared to $73.4 million for the year ended December 31, 2015. SG&A expenses increased $14.9 million, or 20%, for the year ended December 31, 2016 as compared to the year ended December 31, 2015. As a percentage of revenues, our SG&A expenses were 4.3% and 5.3% for the year ended December 31, 2016 and 2015, respectively. The increase year over year was primarily due to a $11.6 million increases in employee related expenses as headcount increased from prior year acquisitions supporting growth and a $3.3 million increase in professional services expenses, largely associated with international expansion, the Geismar fire and to support our growth.
Research and development expense. Our research and development expenses were $18.2 million for the year ended December 31, 2016, compared to $16.9 million for the year ended December 31, 2015. The majority of the research and development expenses involved our Life Sciences business.
Impairment of property, plant and equipment. Late during the year ended December 31, 2016, we recorded impairment charges of $15.6 million against property, plant and equipment assets at our partially completed facility in Emporia, Kansas. The impairment charge resulted from competition from foreign, imported product and the probability of that project being completed in the near term is unlikely. In addition, we recorded impairment charges of $2.3 million against certain plant property, plant and equipment at our other facilities as the carrying amounts of these amounts were deemed not recoverable given the assets deteriorating physical conditions identified in the last quarter of 2016. The amount of property, plant and equipment impairment recorded in 2015 was approximately $12.4 million due to the April and September 2015 fires at our Geismar facility, which was offset in full by our property insurance proceeds.
Impairment of goodwill. We recorded a non-cash impairment charge of $175.0 million of goodwill for the year ended December 31, 2015. There were no impairments of goodwill recorded during 2016.
Other income (expense), net. Other income was $1.8 million for the year ended December 31, 2016 compared to other expense of $5.7 million for the year ended December 31, 2015. 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 income of $7.5 million was mainly due to a gain on debt extinguishment of $2.3 million related to the repurchase of $69.9 million principal amount of the 2019 Convertible Notes, changes in fair value of convertible debt conversion liability of $13.0 million related to the newly issued 2036 Convertible Notes and gain on involuntary conversion of $9.9 million, which represented the amount of insurance proceeds in excess of the net book value of the property damage recorded by us related to the April 2015 and September 2015 fires at our Geismar facility. Our insurance policies cover replacement costs incurred to replace the property damaged by the fires. The overall increase in other income in 2016 was partially offset with the change in fair value of contingent consideration related to previous acquisitions in the amount of $7.9 million and a $4.1 million increase in interest expense as a result of the issuance of the 2036 Convertible Notes.
Income tax expense. There was an income tax expense recorded during the year ended December 31, 2016 of $4.3 million, compared to an income tax benefit of $8.7 million for the year ended December 31, 2015. At December 31, 2016 and 2015, we had net deferred income tax assets of approximately $344.8 million and $231.0 million, respectively, with a valuation allowance of $365.0 million and $250.2 million, respectively. As a result, our effective tax rate was 8.7% and 5.4% for the years ended December 31, 2016 and 2015, respectively. We have an income tax receivable of $4.5 million and $1.8 million as of December 31, 2016 and 2015, respectively.
Effects of participating share-based awards. Effects of participating restricted stock units was $0.9 million and $0.0 million for the years ended December 31, 2016 and 2015, respectively.
Non - GAAP Financial Measures

Adjusted Net Income (Loss) and Adjusted EPS Reconciliation
The Company believes supplementing its consolidated financial statements presented in accordance with GAAP with non-GAAP measures provides investors with useful information regarding the Company's short-term and long-term trends. Adjusted net income and adjusted diluted earnings per common share are derived from GAAP results by excluding the non-cash impacts related to the change in the estimated fair value of the convertible debt conversion liability, change in fair value of contingent considerations, impairment of assets, and stock compensation, coupled with other items that are not related to our operating activities. The Company excludes these non-operating, non-cash impacts as the Company believes they are not indicative of its core operating results or future performance. Adjusted net income, adjusted diluted earnings per common share and other non-GAAP financial measures used and presented by the Company may be calculated differently from, and therefore may not be comparable to, similarly titled measures used by other companies. Investors should consider non-GAAP measures in addition to, and not as a substitute for, or as superior to, financial performance measures prepared in accordance with GAAP.

45



($ in thousands, except for per share amounts)

1Q-2017

 
2Q-2017

 
3Q-2017

 
4Q-2017

 
Year ended December 31, 2017
 
1Q-2016

 
2Q-2016

 
3Q-2016

 
4Q-2016

 
Year ended December 31, 2016
Net income (loss) attributable to the Company
$
(15,914
)
 
$
(34,809
)
 
$
(11,373
)
 
$
(16,983
)
 
$
(79,079
)
 
$
(6,918
)
 
$
7,606

 
$
23,442

 
$
20,197

 
$
44,327

Gain on involuntary conversion

 

 
(942
)
 
(4,387
)
 
(5,329
)
 
(3,543
)
 
(997
)
 
(3,470
)
 
(1,884
)
 
(9,894
)
Change in fair value of convertible debt conversion liability
172

 
32,546

 
(8,560
)
 
(5,325
)
 
18,833

 

 
(13,432
)
 
(3,013
)
 
3,400

 
(13,045
)
Change in fair value of contingent considerations
589

 
(24
)
 
1,433

 
486

 
2,484

 
(15
)
 
3,571

 
1,124

 
3,224

 
7,904

Loss on the Geismar lease termination

 
3,967

 

 

 
3,967

 

 

 

 

 

Other (income) expense, net
320

 
(32
)
 
(12
)
 
742

 
1,018

 
88

 
(2,306
)
 
314

 
(854
)
 
(2,758
)
Impairment of assets

 
1,341

 

 
48,532

 
49,873

 

 

 

 
17,893

 
17,893

Straight-line lease expense
(32
)
 
(85
)
 
(85
)
 
(35
)
 
(237
)
 
(94
)
 
(80
)
 
(73
)
 
(38
)
 
(285
)
Executive severance payment

 

 
2,420

 
991

 
3,411

 

 

 

 

 

Non-cash stock compensation
1,308

 
1,688

 
2,023

 
1,890

 
6,909

 
1,076

 
858

 
2,133

 
1,829

 
5,896

Biodiesel tax credit
36,728

 
59,365

 
56,505

 
52,338

 
204,936

 

 

 

 

 

Adjusted net income (loss) attributable to the Company
$
23,171

 
$
63,957

 
$
41,409

 
$
78,249

 
$
206,786

 
$
(9,406
)
 
$
(4,780
)
 
$
20,457

 
$
43,767

 
$
50,038

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss) per share attributable to common stockholders
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted
$
(0.41
)
 
$
(0.90
)
 
$
(0.29
)
 
$
(0.44
)
 
$
(2.04
)
 
$
(0.14
)
 
$
0.18

 
$
0.59

 
$
0.51

 
$
1.06

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Adjusted net income (loss) per share attributable to common stockholders
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Diluted
$
0.59

 
$
1.61

 
$
1.04

 
$
1.97

 
$
5.21

 
$
(0.21
)
 
$
(0.11
)
 
$
0.52

 
$
1.00

 
$
1.20


Adjusted EBITDA
EBITDA and Adjusted EBITDA are not measures of financial performance under generally accepted accounting principles ("GAAP"). We use earnings before interest, taxes, depreciation and amortization ("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.

46



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-2017
 
2Q-2017
 
3Q-2017
 
4Q-2017
 
2017
 
1Q-2016
 
2Q-2016
 
3Q-2016
 
4Q-2016
 
2016
Net income (loss)
$
(15,914
)
 
$
(34,809
)
 
$
(11,373
)
 
$
(16,983
)
 
$
(79,079
)
 
$
(6,888
)
 
$
7,714

 
$
23,505

 
$
20,382

 
$
44,713

Adjustments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest expense
4,536

 
4,479

 
4,725

 
5,015

 
18,755

 
3,311

 
3,738

 
4,487

 
4,451

 
15,987

Income tax (benefit) expense
1,075

 
1,960

 
(115
)
 
(33,410
)
 
(30,490
)
 
728

 
1,296

 
(1,203
)
 
3,447

 
4,268

Depreciation
8,423

 
8,523

 
8,639

 
8,698

 
34,283

 
7,674

 
7,824

 
7,949

 
8,378

 
31,825

Amortization
127

 
149

 
307

 
305

 
888

 
(140
)
 
(134
)
 
(129
)
 
46

 
(357
)
EBITDA
(1,753
)
 
(19,698
)
 
2,183

 
(36,375
)
 
(55,643
)
 
4,685

 
20,438

 
34,609

 
36,704

 
96,436

Gain on involuntary conversion

 

 
(942
)
 
(4,387
)
 
(5,329
)
 
(3,543
)
 
(997
)
 
(3,470
)
 
(1,884
)
 
(9,894
)
Change in fair value of convertible debt conversion liability
172

 
32,546

 
(8,560
)
 
(5,325
)
 
18,833

 

 
(13,432
)
 
(3,013
)
 
3,400

 
(13,045
)
Change in fair value of contingent consideration
589

 
(24
)
 
1,433

 
486

 
2,484

 
(15
)
 
3,571

 
1,124

 
3,224

 
7,904

Other income (expense), net
320

 
(32
)
 
(12
)
 
742

 
1,018

 
88

 
(2,306
)
 
314

 
(854
)
 
(2,758
)
Impairment of assets (1)

 
1,341

 

 
48,532

 
49,873

 

 

 

 
17,893

 
17,893

Loss on the Geismar lease termination

 
3,967

 

 

 
3,967

 

 

 

 

 

Straight-line lease expense
(32
)
 
(85
)
 
(85
)
 
(35
)
 
(237
)
 
(94
)
 
(80
)
 
(73
)
 
(38
)
 
(285
)
Executive severance

 

 
2,420

 
991

 
3,411

 

 

 

 

 

Non-cash stock compensation
1,308

 
1,688

 
2,023

 
1,890

 
6,909

 
1,076

 
858

 
2,133

 
1,829

 
5,896

 Biodiesel tax credit (2)
36,728

 
59,365

 
56,505

 
52,338

 
204,936

 

 

 

 

 

Adjusted EBITDA
$
37,332

 
$
79,068

 
$
54,965

 
$
58,857

 
$
230,222

 
$
2,197

 
$
8,052

 
$
31,624

 
$
60,274

 
$
102,147

(1)
Represents the impairment charge to write down the carrying value of certain assets, mostly attributed to the Company's New Orleans and Emporia facilities for the years ended December 31, 2017 and 2016, respectively, to remaining salvage values.
(2)
On February 9, 2016, the H.R.1892 was signed into law, which, among other things, reinstated the BTC for the 2017 calendar year. The retroactive credit for 2017 resulted in a net benefit to us that will be recognized in our financial statements for the quarter ending March 31, 2018 for GAAP purposes. However because this credit relates to the 2017 operating performance and results, we have allocated the net benefit 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 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 clauses 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;

47



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, 2017 and 2016, the total of our cash and cash equivalents was $77.6 million and $116.2 million, respectively. At December 31, 2017, we had term debt before debt issuance costs of $228.6 million, compared to term debt before debt issuance costs of $217.9 million at December 31, 2016. This term debt is due in various tranches and the maturities are reflected in the contractual obligations table below. The debt is subject to various financial covenants. We were in compliance with the restrictive financial covenants associated with the borrowings as of December 31, 2017.
Our term debt before debt issuance costs (in millions) is as follows (total balance may not foot due to rounding):
 
December 31,
 
2017
 
2016
4.00% Convertible Senior Notes, $152,000 face amount, due in June 2036
$
116.3

 
$
113.4

2.75% Convertible Senior Notes, $73,838 face amount, due in June 2019
69.9

 
67.3

REG Danville term loan
11.5

 
8.2

REG Newton term loan
8.2

 
13.1

REG Mason City term loan
1.2

 
2.7

REG Ralston term loan
6.2

 

REG Ames term loans

 
3.6

REG Grays Harbor term loan
7.9

 
9.3

REG Capital term loan
7.4

 

Other

 
0.3

Total term debt before debt issuance costs
$
228.6

 
$
217.9

In addition, we had revolving debt (in millions) as follows:
 
December 31,
 
2017
 
2016
Total revolving loans (current)
$
65.5

 
$
52.8

Maximum remaining available to be borrowed under revolving lines of credit
$
60.8

 
$
100.2

2019 Convertible Notes
In June 2014, the Company issued $143.8 million in convertible senior notes (the “2019 Convertible Notes”) with a maturity date of June 15, 2019, unless earlier converted or repurchased. The 2019 Convertible Notes bear interest at a rate of 2.75% per annum, payable semi-annually in arrears, beginning December 15, 2014.
The initial conversion rate is 75.3963 shares of Common Stock per $1 principal amount of 2019 Convertible Notes, which represents an initial conversion price of approximately $13.26 per share. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. Certain corporate events that occur prior to the stated maturity date can cause the Company to increase the conversion rate for a holder.
Prior to December 15, 2018, holders may convert all or any portion of their 2019 Convertible Notes only under certain limited circumstances where the sale price of Common Stock for a period of time is (i) greater than or equal to 130% of the conversion price of the 2019 Convertible Notes on each applicable trading day; (ii) less than 98% of the product of the last reported sale price of the Common Stock and the conversion rate of the 2019 Convertible Notes on each applicable trading day; or (iii) upon the occurrence of specified corporate events. On or after December 15, 2018 until the close of business on the second scheduled trading day immediately preceding the maturity date of the 2019 Convertible Notes, holders may convert their 2019 Convertible Notes at any time, regardless of the foregoing circumstances. Upon conversion, the Company will pay or deliver, as the case may be, cash, shares of Common Stock or a combination of cash and shares of Common Stock, at the

48



Company’s election. The Company's current intent is to settle the principal amount of the 2019 Convertible Notes in cash upon conversion. If the conversion value exceeds the principal amount, the Company would deliver shares of its common stock in respect to the remainder of its conversion obligation in excess of the aggregate principal amount (conversion spread).
The 2019 Convertible Notes are not redeemable at the Company’s option prior to maturity.
We may, from time to time, depending on market conditions and other factors, repurchase our outstanding indebtedness, including our 2019 Convertible Notes, whether or not such indebtedness trades above or below its face amount, for cash and/or in exchange for other securities or other consideration, in each case in open market purchases and/or privately negotiated transactions.
During 2016, we bought back $69.9 million principal amount of the 2019 Convertible Notes in privately negotiated transactions using proceeds from the issuance of the 2036 Convertible Notes discussed below.

2036 Convertible Notes
In June 2016, we issued $152.0 million aggregate principal amount of 4.00% Convertible Senior Notes due 2036 (the “2036 Convertible Notes”) in a private offering to qualified institutional buyers. The 2036 Convertible Notes bear interest at a rate of 4.00% per year payable semi-annually in arrears on June 15 and December 15 of each year, beginning December 15, 2016. The notes will mature on June 15, 2036, unless repurchased, redeemed or converted in accordance with their terms prior to such date.
Prior to December 15, 2035, the 2036 Convertible Notes will be convertible only upon satisfaction of certain conditions and during certain periods as stipulated in the indenture. On or after December 15, 2035 until the close of business on the second scheduled trading day immediately preceding the maturity date, holders of the 2036 Convertible Notes may convert their notes at any time. The 2036 Convertible Notes may be settled in cash, our common shares or a combination of cash and our common shares, at our election. We may not redeem the 2036 Convertible Notes prior to June 15, 2021. Holders of the 2036 Convertible Notes will have the right to require us to repurchase for cash all or some of their notes at 100% of their principal, plus any accrued and unpaid interest on each of June 15, 2021, June 15, 2026 and June 15, 2031. Holders of the 2036 Convertible Notes will have the right to require the Company to repurchase for cash all or some of their notes at 100% of their principal, plus any accrued and unpaid interest upon the occurrence of certain fundamental changes. The initial conversion rate is 92.8074 common shares per $1,000 principal amount of 2036 Convertible Notes (equivalent to an initial conversion price of approximately $10.78 per common share).

REG Ralston
In April 2017, REG Ralston, LLC ("REG Ralston") entered into a construction loan agreement ("Construction Loan Agreement") with First Midwest Bank. The Construction Loan Agreement allows REG Ralston to borrow up to $20.0 million during the construction period at REG Ralston and convert it into an amortizing term debt thereafter. The loan has a maturity date of October 19, 2025. The loan requires monthly principal payments after the construction period and interest to be charged using prime rate plus 0.5% per annum. The loan agreement contains various loan covenants. At December 31, 2017, the effective interest rate on the amount borrowed under this Loan Agreement was 5.00% per annum.

REG Danville
On July 28, 2017, REG Danville, LLC ("REG Danville") entered into an amended loan agreement ("Danville Loan Agreement") with Fifth Third Bank. The outstanding principal under the Danville Loan Agreement is $11.5 million with a maturity date of July 28, 2022. The loan requires monthly principal payments and bears LIBOR-based variable interest rates. The loan agreement contains various loan covenants. At December 31, 2017, the effective interest rate on the amount borrowed under this Loan Agreement was 5.38% per annum.

REG Capital
In December 2017, REG Capital, LLC ("REG Capital") entered into a mortgage refinancing loan agreement ("Mortgage Refinancing Loan Agreement") with First National Bank to refinance existing mortgages on our office buildings in Ames, IA. The outstanding principal under the Mortgage Refinancing Loan Agreement is $7.4 million with a maturity date of January 3, 2028. The loan requires monthly principal payments and bears a fixed interest rate of 3.999% per annum.

M&L and Services Revolver

49



Our wholly owned subsidiaries, REG Services Group, LLC and REG Marketing & Logistics, LLC, are borrowers under a Credit Agreement dated as of December 23, 2011 with the lenders party thereto ("Lenders") and Wells Fargo Capital Finance, LLC, as the agent (as amended, the “M&L and Services Revolver”). The maximum commitment of the Lenders under the M&L and Services Revolver to make revolving loans is $150.0 million, subject to an accordion feature which allows the borrowers to request commitments for additional revolving loans in aggregate amount not to exceed $50.0 million, the making of which is subject to customary conditions, including the consent of Lenders providing such additional commitments. The maturity date of the M&L and Services Revolver is September 30, 2021. Loans advanced under the M&L and Services Revolver bear interest based on a one-month LIBOR rate (which shall not be less than zero), plus a margin based on Quarterly Average Excess Availability (as defined in the Revolving Credit Agreement), which may range from 1.75% per annum to 2.25% per annum.
The M&L and Services Revolver contains various loan covenants that restrict each subsidiary borrower’s ability to take certain actions, including restrictions on incurrence of indebtedness, creation of liens, mergers or consolidations, dispositions of assets, repurchase or redemption of capital stock, making certain investments, making distributions to us unless certain conditions are satisfied, entering into certain transactions with affiliates or changing the nature of the subsidiary’s business. In addition, the subsidiary borrowers are required to maintain a fixed charge coverage ratio of at least 1.0 to 1.0 if excess availability under the M&L and Services Revolver is less than 10% of the total $150.0 million of current revolving loan commitments, or $15 million currently. The M&L and Services Revolver is secured by our subsidiary borrowers’ membership interests and substantially all of their assets. In addition, the M&L and Services Revolver is secured by the accounts receivable and inventory of REG Albert Lea, LLC, REG Houston, LLC, REG New Boston, LLC, and REG Geismar, LLC (collectively, the “Plant Loan Parties”) subject to a $40.0 million limitation with respect to each of the Plant Loan Parties. We guarantee the obligations of the borrowers under the M&L and Services Revolver.
Cash flow. The following table presents information regarding our cash flows and cash and cash equivalents for the years ended December 31, 2017, 2016 and 2015:
 
Year Ended
December 31,
 
2017
 
2016
 
2015
 
 
 
(in thousands)
 
 
Net cash flows provided from operating activities
$
15,597

 
$
75,303

 
$
80,160

Net cash flows used in investing activities
(59,870
)
 
(63,765
)
 
(67,922
)
Net cash flows provided from (used in) financing activities
4,042

 
58,174

 
(27,274
)
Net change in cash and cash equivalents
(40,231
)
 
69,712

 
(15,036
)
Cash and cash equivalents, end of period
$
77,627

 
$
116,210

 
$
47,081

The historical cash flows shown above illustrate that we have consistently generated positive cash flows from operations. In 2017, we generated $15.6 million of cash from operating activities, a reduction from 2016 and 2015 mainly due to the lack of the BTC throughout 2017. In 2017, we received approximately $86.5 million related to the 2016 BTC receivable, of which $2.1 million was paid to our vendors and customers. In addition, approximately $12.0 million of operating cash was generated from lower average inventory level. Our net cash flows used in investing activity in 2017 was impacted by the Geismar land purchase and payments of $67.6 million for our continued investments in our plant and office facilities and the release of our restricted cash related to our petroleum-based sales. The cash receipts from property insurance coverage of $8.0 million helped offset the cash amounts used in other aforementioned investing activities. Our investing activity has historically focused on acquisitions and plant upgrade projects. In early 2017, we paid about $3.7 million to acquire the remaining interest in our Germany subsidiary. Financing activities have been directly correlated with our investing activities. The 2017 financing activities were mainly related to our repayments under the Danville and Newton borrowings and activities under the M&L and Services Revolver and the Uncommitted Facility Agreement (defined below), together with consideration payments made for our past acquisitions. In 2016, our financing activities were impacted by the issuance of the 2036 Convertible Notes and the early redemption of the GOZone Bonds. Total proceeds from the issuance of the 2036 Convertible Notes after issuance costs were approximately $147.4 million, $60.9 million of which was used to extinguish a portion of the 2019 Convertible Notes and $35.1 million of which was used to fund additional share repurchases, in addition to payments made under our share repurchase programs and the additional $6 million repurchase of the 2019 convertible notes in September 2016. In 2015, there was no significant debt obtained while we spent approximately $23.3 million on our share repurchase program.
Capital expenditures: During 2017, our capital expenditures were