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, 2014
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.  ¨
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, 2014, the aggregate market value of Common Stock held by non-affiliates was $376,856,000.
As of February 27, 2015, 44,422,881 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

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.


Table of Contents

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 prospectus, 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 and energy services;
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 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 are also subject to risks and uncertainties that could cause actual results to differ materially from those expected. These risks and uncertainties include, but are not limited to, those risks discussed in Item 1A of this report.
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 are a leading producer of advanced biofuels and are expanding into production of renewable chemicals. We are currently the largest producer of biomass-based diesel in the United States. We participate in each aspect of biomass-based diesel production, from acquiring feedstock, managing construction and operating biomass-based diesel production facilities to

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marketing, selling and distributing biomass-based diesel and its co-products. During 2014, we sold 287 million gallons of biomass-based diesel and had total revenues of $1.3 billion.
We operate a network of nine biomass-based diesel plants, with an aggregate nameplate production capacity of 332 million gallons per year, or mmgy, and one fermentation facility. We believe our fully integrated approach, which includes acquiring feedstock, managing biorefinery facility construction and upgrades, operating biorefineries, marketing renewable products and distributing through a network of terminals, positions us to capitalize on growing demand for biomass-based diesel, renewable chemicals, other advanced biofuels along with other products and services.
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, which are more widely available and 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, such as soybean oil or canola oil.
In January 2014, we acquired substantially all of the assets and certain liabilities of LS9, Inc., or LS9, as part of our strategy to expand into the production of renewable chemicals, additional advanced biofuels and other products. REG Life Sciences, formerly LS9, is a research and development stage company focused on harnessing the power of microbial fermentation to develop and produce renewable chemicals, fuels and other products. The assets acquired consist mainly of in-process research and development, intellectual property and fixed assets. We are currently focused on developing a series of specialty chemicals.
We expanded our selling of petroleum-based heating oil and diesel fuel in February 2014. 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 our existing terminal locations. We are expanding our sales of additional biofuel blends to Minnesota and Iowa terminal location and potentially in other locations across North America.
In June 2014, we expanded into the renewable hydrocarbon diesel business through our acquisition of a 75 mmgy nameplate renewable hydrocarbon diesel biorefinery located in Geismar, Louisiana. Our Geismar facility had been idled by its previous owners and began operating again by us in October 2014 after our completion of certain upgrades.
We expanded our business to Europe in December 2014 by acquiring a majority interest in Petrotec AG, or Petrotec. Petrotec is a fully-integrated biodiesel company and produces biodiesel at its two biorefineries in Emden and Oeding, Germany.  Petrotec’s nameplate production capacity is approximately 56 million gallons (185,000 metric tons or MT) per year. 
Plant Network

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Our production network consists of the following facilities:
Property
 
Nameplate
Production
Capacity1
 
Production
Capacity
for Current
Feedstock
Mix
 
REG
Operations
Commenced
 
Feedstock Capability
Completed
 
 
 
 
 
 
 
 
Ralston, Iowa
 
12
 
12
 
2003
 
Refined Oils and Fats
Albert Lea, Minnesota
 
30
 
30
 
2006
 
Crude, High FFA and Refined Oils and Fats
Newton, Iowa 2
 
30
 
24
 
2007
 
Crude, High FFA and Refined
Oils and Fats
Seabrook, Texas
 
35
 
33
 
2008
 
Refined Oils and Fats
Danville, Illinois
 
45
 
37
 
2009
 
Crude, High FFA and Refined
Oils and Fats
Seneca, Illinois
 
60
 
55
 
2010
 
Crude, High FFA and Refined
Oils and Fats
New Boston, Texas
 
15
 
12
 
2013
 
Crude, High FFA and Refined
Oils and Fats
Ellenwood, Georgia 3
 
15
 
n/a
 
n/a
 
Refined Oils and Fats
Mason City, Iowa 4
 
30
 
30
 
2013
 
Crude, High FFA and Refined
Oils and Fats
Geismar, Louisiana 5
 
75
 
75
 
2014
 
Crude, High FFA and Refined
Oils and Fats
Okeechobee 6
 
n/a
 
n/a
 
2014
 
n/a
Partially Constructed
 
 
 
 
 
% Complete
 
 
St. Rose, Louisiana
 
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
1 
The nameplate capacity listed above is based on soybean oil.
2 
The $15.8 million upgrade and storage expansion to this facility to produce biomass-based diesel using crude and high FFA oils and fats was completed on budget in December 2014.
3 
Idled by prior owner at time of our purchase and remained idled pending repairs or upgrades. We have not yet set a production date.
4 
The $20 million upgrade to this facility to produce biomass-based diesel using crude and high FFA oils and fats was completed on budget in October 2014.
5 
Idled by prior owner at time of our purchase and began operating by us in October 2014.
6 
Okeechobee is a demo-scale microbial fermentation facility for the development and production of renewable chemicals, fuels and other products.

Petrotec's production network consists of the following facilities:
Property
 
Nameplate
Production
Capacity
 
Production
Capacity
for Current
Feedstock
Mix
 

Operations
Commenced
 
Feedstock Capability
Completed
 
 
 
 
 
 
 
 
Emden, Germany
 
30
 
30
 
2008
 
Crude, High FFA and Refined
Oils and Fats
Oeding, Germany
 
25.5
 
25.5
 
2001
 
Crude, High FFA and Refined
Oils and Fats


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In addition to the production facilities and fermentation facility listed above, we also maintain a testing laboratory at our corporate headquarters in Ames, Iowa. The testing laboratory allows us to test various feedstocks for conversion into biomass-based diesel, as well as various manufacturing processes available in the production of biomass-based diesel. Our industrial biotechnology research and development activities are conducted in South San Francisco to allow us to expand into the production of renewable chemicals, advanced biofuels and other products.
Our Feedstocks and Other Inputs
Our ability to use a wide range of feedstocks gives us the flexibility to quickly respond to changes in feedstock pricing to maintain our feedstock cost advantage. We have the ability to rapidly change our processing techniques to accommodate different feedstocks and feedstock mixes. In 2014, approximately 85% of our total feedstock usage was lower cost inedible corn oil, used cooking oil or inedible animal fat feedstock and 15% was from refined vegetable oils, such as soybean oil or canola oil.
We procure our feedstocks from numerous vendors in small to medium quantities. There is no established futures market for lower cost feedstocks. Inedible corn oil and used cooking oil can be purchased in nearby forward positions of three to twelve months on fixed priced contracts or sometimes indexed to the New York Mercantile Exchange, or NYMEX, heating oil index. We generally purchase inedible animal fats on a freight delivered basis and purchase in one to four week forward positions. We maintain both long-term contractual arrangements and long-term trading relationships with key feedstock suppliers, which we believe provides us with an advantage. Some of these relationships are with our investors, such as West Central. Soybean oil can be purchased on a spot or forward contract basis from a number of suppliers.
We work with developers of next generation feedstocks, such as algae and camelina, to assist them in bringing these new feedstocks to market. We have converted several of these feedstocks, as well as other second generation feedstocks, into high quality biomass-based diesel in our laboratory and production facilities. We believe we are well positioned to incorporate these new feedstocks into our production process as they become commercially available.
We procure methanol, chemical catalysts 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 of methanol plus or minus a negotiated basis.
Distribution
We have established a national distribution system to supply biomass-based diesel throughout the United States. Each of our biodiesel facilities are equipped with an on-site rail loading system, a truck loading system, or both, and a logistics and supply chain management staff. Our Seneca biorefinery near the Illinois River has direct barge access supplying customers using the inland waterways system. Our Houston biorefinery has barge and deep-water ship loading capability. We also manage some customers’ biomass-based diesel storage tanks and replenishment process. We lease more than 442 railcars for transportation and lease biomass-based diesel storage tanks in 28 terminals as of December 31, 2014. 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 leases typically have one- to three-year terms and are generally renewable subject to certain terms and conditions. We have sold biomass-based diesel in 46 states and three provinces in Canada.
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 we 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 gives us a more sophisticated and global view of the fluctuating commodity markets for raw materials and energies, which we then can incorporate into our risk management strategies.
Seasonality

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Biodiesel producers have historically experienced seasonal fluctuations in demand for biodiesel. Biodiesel demand has tended to be lower during the winter in Northern and Midwestern states due to lack of infrastructure to properly handle biodiesel in winter and concerns about biodiesel’s ability to operate optimally in cold weather, as compared to the most commonly used petroleum-based diesel fuel. This seasonal fluctuation is strongest for biodiesel made from inedible animal fats and used cooking oil. Biodiesel made from those feedstocks has a higher cloud point, the point at which a fuel begins to gel, than biodiesel produced from soybean oil, canola oil or inedible corn oil, which may cause cold weather performance issues.
Competition
We face competition in the distillate fuel market from producers and suppliers of petroleum-based diesel fuel and in the biomass-based diesel sub-market from other biomass-based diesel producers, marketers, traders and distributors. Our principal methods of competition are product quality, both biomass-based diesel and Renewable Identification Number, or RIN, quality, supply reliability and price. We also face competition in the biomass-based diesel RIN compliance market from producers of renewable hydrocarbon 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 hydrocarbon diesel, such as Neste Oil, which has approximately 600 million gallons of renewable hydrocarbon diesel production capacity in Asia and Europe and Diamond Green Diesel, LLC, the joint venture between Valero Energy Corp. and Darling International with 135 million gallons of renewable diesel. Renewable hydrocarbon diesel can also satisfy the RFS2 biomass-based diesel requirement if the renewable hydrocarbon diesel meets the greenhouse gas reduction requirements and may satisfy Canadian renewable fuel requirements. Neste Oil and Diamond Green Diesel, LLC, have greater financial resources than we do.
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. We face increasing competition from imported biomass-based diesel and expect this to continue. The EPA recently announced that it has approved a plan that will enable Argentinian biodiesel made from soybean oil to earn RINs.
We also face competition from independent biodiesel producers. Unlike us, most of these competitors own only one biodiesel plant and thus, do not enjoy the benefits of scale that we do. Many of our 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, Morgan Stanley, Tenaska and Vitol. 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.
The biomass-based diesel industry is also in competition with the petroleum-based diesel fuel industry. 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.
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 RFS2.
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 hydrocarbon diesel. RFS2 required the use of one billion gallons of biomass-based diesel in 2012, required 1.28 billion gallons in 2013 and at least one billion gallons each year thereafter, with such higher amounts subject to the United States Environmental Protection Agency, or EPA, proposals and the Office of Management and Budget, or OMB, approval. As of this filing, the EPA has not finalized the 2014 biomass-based diesel requirement. In November 2013, the EPA proposed a 2014 biomass-based diesel required volume obligation, or RVO, of 1.28 billion gallons and a reduced Advanced Biofuel RVO of 2.0 to 2.51 billion gallons rather than the original Energy Independence and Security Act of 2009, or EISA, volume of 3.75 billion gallons of advanced biofuels for 2014. The EPA later issued a "notification of delay in issuing standards", effectively withdrawing the proposal. As of the date of this filing, the RVO for 2014 and 2015 had not been proposed nor finalized. Notwithstanding these issues, we expect RFS2 to continue to create demand for biomass-based diesel.

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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 hydrocarbon 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 additional volumes of advanced biofuels can be satisfied by any advanced biofuel, including biodiesel, renewable hydrocarbon diesel, biogas used in transportation, biobutanol, cellulosic ethanol or sugarcane-based ethanol, so long as it meets the 50% greenhouse gas reduction requirement. The additional advanced biofuel requirement was 500 million gallons in 2012, one billion gallons in 2013. The requirement for 2014 and 2015 has not yet been established. Biomass-based diesel comprises the majority of advanced biofuel produced in the United States and we expect the RFS2 advanced biofuel requirement to increase demand for biomass-based diesel.
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 RHD 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 Obligated Parties 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 requires these Obligated Parties to incorporate into their petroleum-based fuel a certain percentage of renewable fuel or purchase credits in the form of 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 and Shell, represent the majority of the total RVOs, with the remainder made up of smaller refiners and importers.
Renewable Identification Numbers
The EPA created the renewable identification number, or 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 the 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. As of December 31, 2011, RINs contributed approximately $1.83, or 38% of the average Jacobsen B100 Upper Midwest spot price of a gallon of biomass-based diesel. During 2012, the value of RINs, as reported by OPIS, have contributed to the average B100 spot price of a gallon of biomass-based diesel, as reported by The Jacobsen, and range from a low of $0.63 per gallon, or 24%, in October to a high of $2.39, or 50%, per gallon in January. During 2013, the value of RINs, as reported by OPIS, have contributed to the average B100 spot price of a gallon of biomass-based diesel, as reported by The Jacobsen, and range from a low of $0.35 per gallon, or 9%, in October to a high of $2.20 per gallon, or 43%, in January. During 2014, the value of RINs, as reported by OPIS, contributed to the average B100 spot price of a gallon of biomass-based, as reported by The Jacobsen, and range from a low of $0.64 per gallon, or 19%, in January to a high of $1.15 per gallon, or 34%, in December. There was a significant decline in RIN prices during the second and third quarters of 2014. The prices rose in the fourth quarter and finished the year at their peak.
Biodiesel Tax Credit
The federal biodiesel mixture excise tax credit ("BTC"), when in place, 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 biodiesel tax credit 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 became effective January 1, 2005 and then lapsed January 1, 2010 before being reinstated

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retroactively on December 17, 2010. The BTC again expired as of December 31, 2011 and on January 2, 2013, it was again reinstated, retroactively for 2012 and through December 31, 2013. The BTC expired again on December 31, 2013 and was retroactively reinstated for 2014 on December 19, 2014. Unlike prior years, Congress did not grant a two year reinstatement, but rather only reinstated the BTC for 2014. Accordingly, the BTC expired again on December 31, 2014. It is uncertain whether The BTC will be reinstated and if reinstated, whether or not it would be reinstated retroactively.
State Programs
Several states have enacted legislation providing incentives for the use of biomass-based diesel, requiring the use of biomass-based diesel, or both. For example, 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, 2018. Illinois’ program has made that state the largest biomass-based diesel market in the country. Since 2006, Iowa has had in place a retailer’s incentive for blended fuel which has been modified over time. In 2012, retailers earned $0.02 per gallon for B2 blends or $0.045 per gallon for B5 blends. For 2013 through 2017, retailers earn $0.045 per gallon of B5. 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. In 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. In addition, regulatory changes in 2012 by the Texas Department of Revenue and Texas Commission on Environmental Equality have removed regulatory barriers and eliminated limitations to blending biomass-based diesel under the Texas Low Emissions Diesel program. In addition, California has adopted a low carbon fuel standard, which requires an increasing reduction in the carbon intensity of transportation fuels, which has created an incentive for the use of lower carbon intensity biomass-based diesel. In addition, Oregon and Washington state have been in the process of developing and implementing their own low carbon fuel programs. Oregon is currently engaged in the rulemaking process.
According to the U.S. Department of Energy, more than 40 states currently have implemented various programs that encourage the use of biomass-based diesel through blending requirements as well as various tax incentives. Currently, 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. Oregon has implemented a B5 biodiesel blend requirement. New Mexico, Pennsylvania and Washington have all adopted legislation requiring biomass-based diesel blends beginning at B2 (and B5 in New Mexico) with incremental increases, provided certain feedstock or production minimums are met. Several northeast states, including Connecticut and Vermont, have adopted legislation requiring biomass-based diesel blends in home heating oil. The City of New York has adopted legislation requiring biomass-based diesel blends at a 2% rate for heating oil legislation increasing that requirement to B5 biodiesel has recently been introduced.
Although we believe that state requirements for the use of biofuels increase demand for our biomass-based diesel within such states, 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 states that have use requirements or tax incentive programs.
Environmental Matters
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. A violation of these laws, regulations or permit conditions could result in substantial fines, natural resource damage, criminal sanctions, permit revocations and or facility shutdowns. However, we do not currently have any such proceedings either pending or threatened against our facilities that would materially affect our business or financial condition. Furthermore, we do not anticipate a material adverse effect on our business or financial condition as a result of our efforts to comply with these requirements as presently in effect.
History
Our predecessor, REG Biofuels, LLC, formerly named REG Biofuels Inc., which was formerly named Renewable Energy Group, Inc., was formed under the laws of the State of Delaware in August 2006 upon acquiring the assets and operations of the biodiesel division of West Central Cooperative, or West Central, and two of West Central’s affiliated companies, InterWest, L.C. and REG, LLC. Set forth below is a summary of the significant events of our company since June 2008.

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Date
 
Events
 
Descriptions
June 2008
 
Houston facility
 
We acquired our Houston facility, which has access to deepwater ports, 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 by merger from Blackhawk Biofuels, LLC. On March 8, 2010, we acquired our Newton Facility, through the purchase of substantially all of the assets and liabilities of Central Iowa Energy, LLC. On April 8, 2010, 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 connects RTI’s national used cooking oil collection system, with more than 16,000 installations, with our national network of biodiesel manufacturing facilities.
September 2010
 
Clovis facility
 
We acquired for stock the partially constructed Clovis facility.
July 2011
 
SoyMor
 
We acquired for stock all the assets and certain liabilities of SoyMor cooperative and SoyMor Biodiesel, LLC.
January 2012
 
REG IPO
 
We completed our initial public offering in which we sold 6.8 million shares of our Common Stock at a price to the public of $10.00 per share. Our Common Stock is currently traded publicly on the NASDAQ Global Market under the symbol “REGI.”
January 2012
 
Seneca facility
 
We exercised an option to purchase our Seneca facility, which we previously operated under lease.
October 2012
 
North Texas Bio Energy, LLC
 
We acquired substantially all the assets of North Texas Bio Energy, LLC, or NTBE.
November 2012
 
BullDog Biodiesel, LLC
 
We acquired substantially all the assets of BullDog Biodiesel, LLC, or BullDog.
July 2013
 
Soy Energy, LLC
 
We acquired substantially all of the assets of Soy Energy, LLC's, or the Soy Energy Assets. The Soy Energy Assets consisted of a 30 mmgy nameplate capacity biodiesel facility and related assets located in Mason City, Iowa. We began producing biodiesel on October 1, 2013.

2013
 
Series B Preferred Stock
 
Certain Series B Preferred Stockholders exercised their option to convert 2,333,428 shares of Series B Preferred Stock into 4,716,043 shares of Common Stock. In addition, we opted to cause 50% of the then-outstanding shares of Series B Preferred Stock to be converted as provided for in our certificate of incorporation.

January 2014
 
LS9
 
We acquired substantially all of the assets and liabilities of LS9.
March 2014
 
Series B Preferred Stock
 
We redeemed all outstanding shares of Series B Preferred Stock.
June 2014
 
Syntroleum/Dynamic Fuels
 
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 hydrocarbon diesel production facility in Geismar, LA. Subsequently on June 6, 2014, we acquired the remaining 50% ownership interest in Dynamic Fuels from Tyson Foods. At closing, we renamed Dynamic Fuels, REG Geismar, LLC or REG Geismar.
December 2014
 
Petrotec AG
 
We acquired 69% equity ownership in Petrotec AG from its majority shareholder. We made a cash tender offer for all other Petrotec shares.

Employees
As of December 31, 2014, we employed 502 full-time employees. None of our 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, trade secrets, and licenses related to our biomass-based diesel and industrial biotechnology businesses and expect that number to grow as we continue to pursue technological innovations.
Customer concentration
We have one customer, Pilot Travel Centers LLC, or Pilot, which accounts for 10% or more of our total revenues. Sales to Pilot were $231.8 million, $243.3 million and $363.4 million, representing approximately 18%, 16% and 36%, respectively, of our total revenues for 2014, 2013, and 2012. Our revenues from Pilot generally do not include the RINs associated with the gallons

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of biomass-based diesel sold. The value of those RINs represented approximately an additional 7% of our total sales, 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 process and developing applications for co-products. Our industrial biotechnology business has added additional resources towards our research and development surrounding microbial fermentation and renewable chemicals, additional advanced biofuels and other products. We expect our research and development expense associated with these programs to increase in future periods. We incurred research and development expense of $12.4 million, $0.26 million, and $0.01 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Executive Officers of the Registrant
Daniel J. Oh, age 49, has served as our Chief Executive Officer and as a Director since September 2011 and President since April 2009. Mr. Oh served as our Chief Operating Officer from June 2007 to September 2011, our Chief Financial Officer and Executive Vice President from June 2006 to June 2007 and as Secretary from August 2006 until March 2009. From May 2004 to May 2006, Mr. Oh served at Agri Business Group, Inc., or ABG, an agribusiness management consulting firm, including as Associate Director, Director and Vice President. Prior to joining ABG, Mr. Oh served in several different positions, including Senior Financial Analyst, Financial Team Member and Manager, in the Corporate Finance and Investment Banking area of the Corporate Strategy and Business Development Group at Eli Lilly and Company, a global pharmaceutical company, from August 2001 to May 2004. From 2000 to August 2001, Mr. Oh served as a consultant with McKinsey & Company, a leading consulting firm, where he focused on the pharmaceutical industry. From 1987 to 1998, Mr. Oh served as an officer in the United States Army, earning the rank of Major. Mr. Oh holds an M.B.A. from the University of Chicago with concentrations in finance, accounting and strategic management as well as a B.S. with a concentration in economics from the United States Military Academy. Mr. Oh serves as a director on Petrotec AG's supervisory board. Mr. Oh’s employment agreement with us provides that he will serve as a director.
Chad Stone, age 45, has served as our Chief Financial Officer since August 2009. Prior to joining us, he was a Director at Protiviti Inc., a global business consulting and internal audit firm, from October 2007 to May 2009. From August 1997 to September 2007, Mr. Stone served as Director with PricewaterhouseCoopers and worked at Arthur Andersen from July 1992 to August 1997, departing as a manager. Mr. Stone has served on executive Board of the Iowa Biodiesel Board since 2011 and was named chair in September 2014. 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 52, has served as our Vice President, Manufacturing since February 2008. Mr. Albin also served as Vice President of Construction Services from April 2007 through February 2008. From September 2006 through April 2007, Mr. Albin served as Director, Construction. Prior to joining us, Mr. Albin served as General Manager for West Central, one of our predecessors from July 2006 through September 2006. From November 2002 to January 2006, Mr. Albin served as Executive Director of Operations for Material Sciences Corporation, where he directed multi-plant operations that served the 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 serves on the board of the Iowa Renewable Fuels Association and was the President in 2012, as well as, Vice President in 2011. Mr. Albin serves as a director on Petrotec AG's supervisory board. 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.
David Elsenbast, age 53, has served as our Vice President, Supply Chain Management since April 2009. From August 2006 to April 2009, Mr. Elsenbast served as our Vice President, Procurement. Prior to joining us, Mr. Elsenbast served in the same role for West Central, since April 2006. Mr. Elsenbast has also served on the Board of the American Fats and Oils Association since October 2009. From 1990 to March 2006, Mr. Elsenbast served in various roles for Milk Specialties Company, an animal nutrition company, including Vice President of Business Development, Vice President of Operations and Purchasing and General Manager. Mr. Elsenbast has over 30 years in agricultural business development, supply chain management, operations, and purchasing. Mr. Elsenbast holds a B.S. in agricultural business from Iowa State University.

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Gary Haer, age 61, 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 and was responsible for developing the marketing and distribution infrastructure for biomass-based diesel sales in the United States. Mr. Haer has over 15 years of experience in the biomass-based diesel industry. Mr. Haer currently serves on the Executive Committee of the National Biodiesel Board’s Governing Board as Past Chairman and has been elected to various officer positions during his tenure from 1998 to 2014. Mr. Haer holds a 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, and as a result, the trading price of our common stock could decline.
Risk Associated With Our Business
Loss or reductions of governmental requirements for the use of biofuels could have a material adverse effect on our revenues and operating margins.
The biomass-based diesel industry relies substantially on federal requirements and state policies for use of biofuels. Since biomass-based diesel has been more expensive to produce than petroleum-based diesel fuel over the past few years, the biomass-based diesel industry depends on governmental programs that support a market for biomass-based diesel that might not otherwise exist.
The most important of these government programs in the United States is RFS2, which requires that a certain volume of biomass-based diesel fuel, which includes biodiesel and renewable hydrocarbon diesel, be consumed. RFS2 became effective on July 1, 2010 and applies through 2022. We believe that much of the increase in demand for our biomass-based diesel since July 2010 is attributable to and accelerated by the implementation of RFS2. In addition, we believe that biomass-based diesel prices since July 2010 benefited significantly from RFS2.
The EPA is required to determine the volume of biomass-based diesel that will be required each year based on the EPA’s consideration of a variety of factors, with a minimum biomass-based diesel annual volume requirement be at least 1 billion gallons . The biomass-based diesel volume requirement for 2013 was 1.28 billion gallons.
There can be no assurance that the United States Congress will not repeal, curtail or otherwise change, or that the EPA will not curtail or otherwise change the RFS2 program in a manner adverse to us. The petroleum industry is generally opposed to RFS2 and can be expected to continue to press for changes that eliminate or reduce its impact. 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 harm our revenues and cash flows.
If Congress decides to repeal or curtail RFS2, or if the EPA is not able or willing to enforce RFS2 requirements, the demand for our biomass-based diesel based on this program and any increases in demand that we expect due to RFS2 would be significantly reduced or eliminated and our revenues and operating margins would be materially harmed. In addition, although we believe that state requirements for the use of biofuels increase demand for our biomass-based diesel within such states, they generally may not increase overall demand in excess of RFS2 requirements. Rather, existing demand for our biofuel from petroleum refiners and petroleum fuel importers in the 48 contiguous states or Hawaii, which are defined as “Obligated Parties” in the RFS2 regulations, in connection with federal requirements, may shift to states that have use requirements or tax incentive programs.
As of the date of this filing, the EPA has not finalized the 2014 or 2015 Renewable Volume Obligations, or RVOs. The EPA originally proposed a 2014 and 2015 biomass-based diesel RVO of 1.28 billion gallons in each of those years and a reduced Advanced Biofuel RVO of 2.0 to 2.51 billion gallons rather than the original Energy Independence and Security Act of 2009, or EISA, volume of 3.75 billion gallons for 2014. The EPA received significant negative feedback to their proposal number and subsequently issued a "notification in delay in issuing standards." Before the RVO can be finalized, the OMB has to approve EPA’s proposal, based on the same factors outlined above. Due to the delay in publishing the proposal, which the EPA was required to determine and publish by November 30 two years prior, it is possible that the 2014 and 2015 RVOs will be

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challenged in court which may further delay any final determination of such RVOs, which could reduce the demand for and price of our biomass-based diesel and could harm our revenues and cash flows.
Our financial results may be harmed in the event biodiesel production exceeds the RVO.
Notwithstanding the lack of a finalized 2014 RVO, according to EMTS data, RINs representing 1.75 billion gallons of biomass-based diesel were generated for the twelve months ended December 31, 2014. According to EMTS data, 1.78 billion gallons of biomass-based diesel was produced and imported into the U.S. in 2013. Adding the 2012 carry-over to the 2013 RIN generation results in an estimated total biomass-based diesel RIN availability of approximately 2.04 billion gallons, which is approximately 760 million gallons more than required to satisfy the 1.28 billion gallon 2013 biomass-based diesel RVO. The originally proposed 2014 biomass-based diesel RVO of 1.28 billion gallons, would have limited the 2014 carryover to 256 million gallons, or 20%, of 1.28 billion, thus resulting in an excess supply of 504 million gallons of biomass-based diesel RINs. Excess biomass-based diesel RINs may be used to fulfill the advanced biofuel RVO or the renewable fuel RVO. If the volume of excess biomass-based diesel RINs exceeds the volume the Obligated Parties desire to use to fulfill their advanced biofuel and renewable fuel requirements, the demand for and price of our biomass-based and biomass-based diesel RINs may be reduced, which could harm revenues and cash flows.
Our gross margins are dependent on the spread between biomass-based diesel prices and feedstock costs.
Our gross margins depend on the spread between biomass-based diesel prices and feedstock costs. 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, or The Jacobsen, and the price per gallon for the amount of choice white grease, a common inedible animal fat used by us to make biomass-based diesel, was $1.26 in 2012, $1.61 in 2013 and $0.92 in 2014 assuming 8.0 pounds of choice white grease yields one gallon of biomass-based. The average monthly spread for the amount of crude soybean oil required to produce one gallon of biomass-based, based on the nearby futures contract as reported on the Chicago Board of Trade, or CBOT, was $0.65 in 2012, $1.19 in 2013 and $0.58 in 2014 assuming 7.7 pounds of soybean oil yields one gallon of biomass-based. For 2012, 2013 and 2014, approximately 84%, 83% and 85%, respectively, of our total feedstock usage was inedible corn oil, used cooking oil or inedible animal fat and 16%, 17% and 15%, respectively, was virgin vegetable oils.
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. Energy prices, particular the market price for crude oil, significantly decreased throughout fourth quarter 2014. A lack of close correlation between production costs and biomass-based diesel prices means that we may be unable to pass increased production costs on to our customers in the form of higher prices. Any decrease in the spread between biomass-based diesel prices and feedstock costs, whether as a result of an increase in feedstock prices or a reduction in biomass-based diesel prices, including, but not limited to, a reduction in the value of RINs would adversely affect our gross margins, cash flow and results of operations.
The costs of raw materials that we use as feedstocks are volatile and our results of operations could fluctuate substantially as a result.
The cost of feedstocks is a significant uncertainty for our business. The success of our operations is dependent on the price of feedstocks and certain other raw materials that we use to produce 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. At elevated price levels, these feedstocks may be uneconomical to use, as we may be unable to pass feedstock cost increases on to our customers.
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. The significance and relative impact of these factors on the price of feedstocks is difficult to predict, especially without knowing what types of feedstock materials will be optimal for use in the future, particularly at new facilities that we may construct or acquire.
The price of our feedstocks can vary significantly based on market conditions. Since January 1, 2008, the cost per pound of choice white grease, an inedible animal fat commonly used by us in the production of biomass-based diesel, has traded in a range of $0.0950 to $0.5250 based on the closing nearby futures prices on the CBOT. If biomass-based diesel production continues to increase in response to RFS2, we expect that more biomass-based diesel producers will seek to use lower cost feedstocks, potentially increasing our costs of production. In addition, because the market for animal fat is less developed than markets for vegetable oils such as soybean oil, we generally are unable to enter into forward contracts at fixed prices.

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Inedible corn oil and used cooking oil are not generally available in quantities sufficient to cover all of our operations. If more ethanol plants do not acquire and utilize corn oil extraction equipment, if extraction yields do not improve, if ethanol plants are idled, or ethanol plants begin using the feedstock in their own operations, we may not be able to obtain the volumes of inedible corn oil we desire for use in our production of biomass-based diesel at economical prices and may be forced to utilize higher cost feedstocks to meet increased demand, which may not be economical.
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.
The biomass-based diesel industry has historically been substantially aided by federal and state tax incentives. Prior to RFS2, the biomass-based diesel industry relied principally on these tax incentives to bring the price of biomass-based diesel more in line with the price of petroleum-based diesel fuel to the end user. The most significant tax incentive program has been the federal biodiesel mixture excise tax credit, or BTC. The BTC provided a $1.00 refundable tax credit per gallon of pure biomass-based, or B100, to the first blender of biomass-based with petroleum-based diesel fuel. The BTC came into existence on January 1, 2005, had been continuously reinstated until it expired on December 31, 2009 and was reinstated following the lapse in December 2010, retroactively for all of 2010 and prospectively for 2011. The BTC expired again on December 31, 2011 and was again reinstated on January 2, 2013, retroactively for all of 2012 and prospectively for 2013, expired again December 31, 2013 and was again reinstated on December 19, 2014. Unlike prior reinstatement, this last reinstatement was only for one year, retroactive for 2014, rather than two years as has previously been the case. It is generally understood that Congress decided to only enact a one year extenders package, which included the BTC, because Congress wanted to take up tax reform in 2015. There is no assurance that the BTC will be reinstated. 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. It is uncertain what action, if any, Congress may take with respect to reinstating the BTC or when such action might be effective. If Congress does not reinstate the credit, demand for our biomass-based diesel and the price we are able to charge for our product may be significantly reduced, harming revenues and profitability. When the BTC expired on December 31, 2011, we experienced an industry-wide acceleration of gallons sold in the fourth quarter of 2011, which was further influenced by the ability of Obligated Parties to satisfy up to 20% of their current RVO with prior year RINs. We believe this increase in production at the end of the year resulted in a buildup of biomass-based diesel inventories and reduced gallons sold in the first quarter of 2012. With the expiration of the BTC at the end of 2013 and 2014, the industry experienced a similar increase in biomass-based diesel production in the fourth quarter of 2013 and 2014, which we believe reduced demand in the first quarter of 2014 and is reducing demand on the first quarter of 2015. In response to the regular lapsing and reinstatement of the BTC, the biomass-based diesel industry and its customers have adopted arrangements for sharing the BTC if reinstated.
In addition, several states have enacted tax incentives for the use of biodiesel and/or biomass-based diesel. For example, Illinois offers an exemption from the generally applicable 6.25% sales tax for biodiesel blends that incentivizes blending at 11% biodiesel, or B11. Like the BTC, the Illinois tax incentive program and the tax incentive programs of other state could be changed as a result of state budget considerations or otherwise. Reduction or elimination of such incentives could materially and adversely harm our revenues and profitability.
Risk management transactions could significantly increase our operating costs and working capital requirements and may not be effective.
In an attempt to partially offset the effects of volatile feedstock costs and biomass-based diesel fuel prices, we may enter into contracts that establish market positions in feedstocks, such as inedible corn oil, used cooking oil, inedible animal fats and soybean oil, and 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. Risk management arrangements also 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. 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. 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.
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 18%, 16% and 36% of our revenues in 2014, 2013 and 2012, respectively. Our revenues from Pilot generally do not include the RINs associated with the gallons of biomass-based sold to Pilot. The value of those RINs represented approximately an additional 7% of our total sales, based on the OPIS average RIN price for 2014. In the event we lose Pilot as a customer or Pilot significantly reduces the volume of biomass-based

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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.
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 hydrocarbon 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. For example, in 2009 and the beginning of 2010, we were required to periodically idle our plants due to insufficient demand at profitable price points which materially affected our revenues. If we are required to idle our plants in the future or are unable to adapt to changing market conditions, our revenues and results of operations may be materially harmed.
Technological advances and changes in production methods in the biomass-based diesel industry could render our plants obsolete and adversely affect our ability to compete.
It is expected that technological advances in biomass-based diesel production methods will continue to occur and new technologies for biomass-based diesel production may develop. Advances in the process of converting oils and fats into biodiesel and renewable hydrocarbon diesel could allow our competitors to produce biomass-based diesel faster and more efficiently and at a substantially lower cost. 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. There is no assurance that third-party licenses for any proprietary technologies that we would need access to in order to remain competitive for either existing processes or new technology will be available to us on commercially reasonable terms or that any new technologies could be incorporated into our plants. 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, we may not be able to successfully execute our strategy and our results of operations could be substantially harmed.
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 our intellectual property. To accomplish this, we rely on a combination of intellectual property rights, including patents, copyrights, trademarks and trade secrets in the United States and in selected foreign countries where we believe filing for such protection is advantageous and cost-justified. Our ability to use and prevent others from using our intellectual property is important to our success. Effective patent, copyright, trademark and trade secret protection may be unavailable, limited or not applied for in some countries. Some of our products and technologies are not covered by any patent or patent application.
If we pursue litigation to assert our intellectual property rights, an adverse judicial decision in any of these legal actions 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.  
Any intellectual property rights claim against us, with or without 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. Any of these events could seriously harm our business, operating results and financial condition.
If we are unable to respond to changes in ASTM or customer standards, our ability to sell biomass-based may be harmed.
We currently produce biomass-based diesel to conform to or exceed standards established by ASTM. ASTM standards for biomass-based diesel and biomass-based diesel blends may be modified in response to new observations from the industries involved with diesel fuel. New tests or more stringent standards may require us to make additional capital investments in, or modify, plant operations to meet these standards. In addition, some biomass-based customers have developed their own biomass-based standards which are stricter than the ASTM standards. If we are unable to meet new ASTM standards or our biomass-based customers’ standards cost effectively or at all, our production technology may become obsolete, and our ability to sell biomass-based may be harmed, negatively impacting our revenues and profitability.
Increases in our transportation costs or disruptions in our transportation services could have a material adverse effect on our business.

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Our business depends on transportation services to deliver our products to our customers and to deliver raw materials to us. The costs of these transportation services are affected by the volatility in fuel prices, such as those caused by recent geopolitical and economic events. For example, in 2012, the market rates of leasing new rail cars nearly doubled as a result of increased demand to move domestically drilled crude oil from new supply fields in the upper Midwest to various refineries. 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 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 critical talent whereby the loss of any of these persons could adversely affect our results of operations.
We are highly dependent upon key members of our management team along with critical talent possessing unique technical skills for the execution of our business plan. We believe that our future success is highly dependent on the contributions of these key employees. There can be no assurance that any individual will continue in his or her capacity for any particular period of time. The loss of any of these key 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 and certain subsidiaries have indebtedness, which subjects us to potential defaults, 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, 2014, our total long-term debt was $252.9 million. This includes $121.4 million aggregate principal amount of 2.75% convertible senior notes due 2019 that we issued in June 2014, or the Convertible Notes, and $100.0 million of GOZone Bonds for which our newly acquired subsidiary, REG Geismar, is obligated. Our obligation with respect to the GOZone Bonds is secured by the deposit of $101.3 million with the financial institution whose letter of credit supports payments on the bonds. We also have short-term debt obligations under a revolving credit agreement provided by a bank group. At December 31, 2014, there was $16.7 million borrowings made under our revolving line of credit, all of which we guarantee. See "Note 12 - 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;
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 Convertible Notes, depends on our future performance, which is subject to 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 and any future indebtedness we may incur and 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 Convertible Notes, the GOZone Bonds, our other existing indebtedness or future indebtedness will depend on the capital markets and our financial condition at such time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our current or future indebtedness.
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, and our future debt may contain limitations on our ability to repurchase the Convertible Notes.
Holders of the Convertible Notes will have the right to require us to repurchase their 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. In addition, upon conversion of the 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

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to make cash payments in respect of the 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 Convertible Notes upon a fundamental change or to settle conversion of the Convertible Notes in cash.
In addition, our ability to repurchase the Convertible Notes may be limited by law, by regulatory authority or by agreements governing our future indebtedness. Our failure to repurchase Convertible Notes at a time when the repurchase is required by the indenture would constitute a default under the indenture governing the 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 Convertible Notes could delay or prevent an otherwise beneficial takeover or takeover attempt of us.
Certain provisions in the 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 notes will have the right to require us to repurchase their 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 notes in connection with such takeover. In either case, and in other cases, our obligations under the 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 subject to counterparty risk with respect to the capped call transactions.
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 have generated no revenue from sales of renewable chemicals to date and we face significant challenges to developing this business.
We have only recently entered the market for renewable chemicals with our acquisition of LS9, Inc.'s assets in January 2014. To date, we have not generated any revenues from this business which is still at a pre-commercial stage. In order to generate revenue from our renewable chemicals, we must be able to produce sufficient quantities of our products, which we have not done to date.
In entering this market, we intend to sell 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 capital and 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. 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 produces benefits to them, we will not be successful in these markets and our business will be adversely affected. Additionally, 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.
If we fail to expand effectively in international markets, where we have limited operating history, our revenues and our business may be harmed.
Historically, we have generated nearly all of our revenues from the United States. In December 2014, we acquired a 69% interest in Petrotec, which owns two biorefineries in Germany. We have made a cash tender offer for the remaining Petrotec shares but there is no assurance that we will be able to acquire these shares. If we are unable to complete the tender offer, our ability to control the operations of Petrotec may be limited.

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We have no experience operating a biorefinery outside of the United States. Our ability to recognize the benefit of our investment in Petrotec, or any other international operations we invest in, will require the attention of management and is subject to a number of risks. Specifically, the biodiesel market in Europe benefits from regulations that encourage the use of biodiesel. As is the case in the United States, 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; and trade and tariff restrictions.
These factors and other factors could harm our ability to gain future international revenues. Our failure to successfully manage any international operations and the associated risks effectively could have an adverse effect on our operating results and financial condition.
We might require additional capital to support business growth, and this capital might not be available on acceptable terms, or at all.
We intend to continue to make investments to support our business growth and may require additional funds to respond to business challenges, including the need to develop our renewable chemicals business or expand or enhance our biomass-based operations or acquire complementary businesses and technologies. Accordingly, we may need to engage in equity or debt financing to secure additional funds. If we raise additional funds through further issuances of equity or convertible debt securities, our stockholders could suffer significant dilution, and any new equity securities we issue could have rights, preferences and privileges superior to those of holders of our common stock. Any debt financing could involve restrictive covenants, which may restrict our flexibility in operating our business and make it more difficult for us to obtain additional capital and to pursue business opportunities, including potential acquisitions. We may not be able to obtain additional financing on terms favorable to us, if at all. If we are unable to obtain adequate financing on terms satisfactory to us, when we require it, our ability to continue to support our business growth and to respond to business challenges could be significantly limited, and our business, operating results, financial condition and prospects could be adversely affected.
We may encounter difficulties in effectively integrating the businesses we acquire.
We may face significant challenges in effectively integrating entities and businesses that we acquire, including our acquisition of substantially all of LS9's assets in January 2014, as well as our acquisition of Syntroleum Corporation and Dynamic Fuels, LLC in June 2014, and our anticipated acquisition of the remaining ownership of Petrotec 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;

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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.
We may not successfully identify and complete acquisitions and other strategic relationships on favorable terms in order to execute our strategy to grow and diversify our business.
We regularly review domestic and international acquisitions of biofuel production facilities and have acquired most of our facilities from third parties. However, we may be unable to identify suitable acquisition candidates in the future. Even if we identify appropriate acquisition candidates, we may be unable to complete such acquisitions on favorable terms, if at all. If we are unable to successfully acquire other businesses or facilities, we may not be able to grow our business as planned.
We may require additional capital to fund future acquisitions. If we are unable to obtain such capital on satisfactory terms, or if such capital is otherwise unavailable, we may be unable to complete such acquisitions and our business may be harmed.
We may not realize the benefit of our investment in the renewable chemicals market.
We have only recently expanded our business into the production of renewable chemicals from biomass feedstocks through the acquisition of certain assets. The renewable chemicals market is underdeveloped. Any chemicals that we produce from renewable sources may not prove to be as effective as chemicals produced from conventional sources and, regardless of their effectiveness, renewable chemicals may not be accepted in the chemical marketplace. If this were to occur, we would not realize the benefit of our investment in renewable chemicals and our results of operations could be harmed.
We have three partially constructed plants, one non-operational plant, and planned upgrades to our operating plants, each of which would require capital that we may not be able to raise and that may result in an impairment that could negatively impact our financial position, results of operations and future cash flows.
We have three partially constructed plants, one near New Orleans, Louisiana, one in Emporia, Kansas and one in Clovis, New Mexico and one non-operational plant near Atlanta, Georgia. We may choose to invest approximately $165 to $180 million in the aggregate, excluding working capital requirements, before these four plants would be able to commence production. Our Clovis plant is currently being operated as a terminal facility. In order to complete construction these facilities as planned, we will require additional capital. In November 2012, we acquired the above mentioned biomass-based facility near Atlanta, Georgia, which had been idled prior to our acquisition and will remain so until certain repairs or upgrades are made. While we intend to finance certain upgrades to our existing facilities from our cash flow from operations, we will need to raise significant capital to complete construction of the three partially constructed or non-operational facilities and to fund related working capital requirements. It is uncertain when or if financing will be available. It is also likely that the terms of any project financing would include customary financial and other covenants restricting our project subsidiaries, including restrictions on the ability to make distributions, to guarantee indebtedness and to incur liens on the plants of such subsidiaries.
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. Our sales tend to decrease during the winter season due to perceptions that biodiesel will not perform adequately in colder weather. Colder seasonal temperatures can cause the higher cloud point biodiesel we make from inedible animal fats to become cloudy and eventually gel at a higher temperature than petroleum-based diesel or lower cloud point biodiesel made from soybean, canola, used cooking 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 may 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 biodiesel to warmer climates generally increase in cold weather months.
In addition, our RINs also have an element of seasonality to them. Since only 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, one would expect RIN prices to decrease as the calendar year progresses if the RIN market is oversupplied compared to that year’s RVO and increase if it is undersupplied. For example, in 2012, which had a RVO for biomass-based diesel of one billion gallons, biomass-based diesel RIN prices, as reported by OPIS, began to decrease in September when biomass-based diesel

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RIN generation neared the equivalent of 900 million gallons, as reported by EMTS. Similarly, in September of 2013 when biomass-based diesel RIN generation reached approximately 960 million gallons compared to a 2013 RVO of 1.28 billion gallons, biomass-based diesel RIN prices, as reported by OPIS, began to decline. As a result of these seasonal fluctuations, comparisons of operating measures between consecutive quarters may not be as meaningful as comparisons between longer reporting periods.
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.
The biomass-based diesel industry is subject to extensive federal, state and local laws and regulations related to the general population’s health and safety and compliance and permitting obligations, including those related to the use, storage, handling, discharge, emission and disposal of municipal solid waste and other waste, pollutants or hazardous substances, discharges, air and other emissions, as well as land use and development. Existing laws also impose obligations to clean up contaminated properties or to pay for the cost of such remediation, often upon parties that did not actually cause the contamination. 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. These costs and liabilities could adversely affect our operations.
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.
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, or if current or prior operations were conducted consistent with accepted standards of practice. Such liabilities can be significant and, if imposed, could have a material adverse effect on our financial condition or results of operations.
In addition to the regulations mentioned above, 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 evolving, requiring us to periodically update our compliance systems. For example, in 2008, we unintentionally generated duplicate RINs as a result of a change to the software we use to manage RIN generation. We voluntarily reported this violation to the EPA and followed EPA guidance in correcting the issue promptly. In 2011, we entered into an administrative settlement agreement with the EPA regarding this violation and paid a fine for this inadvertent violation. Any violation of these regulations by us, inadvertently or otherwise, 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. For a detailed description of RINs, see “Business-Government Programs Favoring Biodiesel Production and Use-Renewable Identification Numbers.”
In response to certain cases of RIN fraud whereby biomass-based producers were selling biomass-based diesel RINs without having produced the required renewable fuel, the EPA is in the process of implementing a quality assurance program for RIN compliance. Compliance with these or any new regulations or Obligated Party verification procedures could require significant expenditures to attain and maintain compliance. Failure to comply could result in the imposition of penalties, fines, restrictions on operations, loss of customers and remedial liabilities. These costs and liabilities may 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 any additional regulatory or customer requirements which may be adopted in the future, including whether any such regulations or verification procedures would significantly increase our cost of doing business or affect our operations in any area.
Our business may suffer if we are unable to attract or retain talented personnel.
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 have a relatively small management team and employee base, and the inability to attract suitably qualified replacements or additional staff could adversely affect our business. No assurance can be given that our management team or employee base will continue their employment, or that replacement personnel with comparable skills could be found. If we are unable to attract and retain key personnel and additional employees, our business may be adversely affected.
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.

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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, 2014 that our internal control over financial reporting provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, because of its inherent limitations, internal control over financial reporting may not prevent or detect fraud or misstatements. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our results of operations or cause us to fail to meet our reporting obligations. If we or our independent registered public accounting firm discover a material weakness, the disclosure of that fact could harm the value of our stock and our business.
A natural disaster, leak, fire or explosion at any of our production plants or customer’s facilities could increase our 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. A majority of our facilities are also located in the Midwest, which is subject to tornado activity. Furthermore, 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 location, are vulnerable to hurricanes, which may cause plant damage, injury to employees and others and interruption of operations and all of our plants could incur damage from other natural disasters. 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, clean-up costs, liability for damages or injuries, legal expenses and reconstruction expenses, which would seriously 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.
Confidentiality agreements with employees and others may not adequately prevent disclosures of confidential information, trade secrets and other proprietary information.
We rely in part on trade secret protection to protect our confidential and proprietary information and processes. However, trade secrets are difficult to protect. We have taken measures to protect our trade secrets and proprietary information, but these measures may not be effective. For example, we require new employees and consultants to execute confidentiality agreements upon the commencement of their employment or consulting arrangement with us. These agreements generally require that all confidential information developed by the individual or made known to the individual by us during the course of the individual’s relationship with us be kept confidential and not disclosed to third parties. These agreements also generally provide that knowhow and inventions conceived by the individual in the course of rendering services to us are our exclusive property. Nevertheless, these agreements may be breached, or may not be enforceable, and our proprietary information may be disclosed. Further, despite the existence of these agreements, third parties may independently develop substantially equivalent proprietary information and techniques. Accordingly, it may be difficult for us to protect our trade secrets. Costly and time-consuming litigation could be necessary to enforce and determine the scope of our proprietary rights, and failure to obtain or maintain trade secret protection could adversely affect our competitive business position.
Moreover, we cannot assure you that our technology does not infringe upon any valid claims of patents that other parties own. In the future, if we are found to be infringing on a patent owned by a third party, we might have to seek a license from such third party to use the patented technology. We cannot assure you that, if required, we would be able to obtain such a license on terms acceptable to us, if at all. If a third party brought a legal action against us or our licensors, we could incur substantial costs in defending ourselves, and we cannot assure you that such an action would be resolved in our favor. If such a dispute were to be resolved against us, we could be subject to significant damages.
We are a holding company and there are limitations on our ability to receive dividends and distributions from our subsidiaries.

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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.
Risks Related to the Biomass-based diesel Industry
The market price of biomass-based diesel is influenced by the price of petroleum-based distillate fuels, such as ultra-low sulfur diesel, and decreases in the price of petroleum-based distillate fuels or RIN values would very likely decrease the price we can charge for our biomass-based diesel, which could harm our revenues and profitability.
Historically, biodiesel prices have been strongly correlated to petroleum-based diesel prices and in particular ULSD, regardless of the cost of producing biomass-based diesel itself. We market our biofuel as an alternative to petroleum-based fuels. Therefore, if the price of petroleum-based diesel falls, the price of biomass-based diesel could decline, and we may be unable to produce products that are an economically viable alternative to petroleum-based fuels. 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. Additionally, demand for liquid transportation fuels, including biomass-based diesel, is impacted by economic conditions.
Just as a small reduction in the real or anticipated supply of crude oil can have a significant upward impact on the price of petroleum-based fuels, a perceived reduction of such threats can result in a significant reduction in petroleum-based fuel prices. A reduction in petroleum-based fuel prices may have a material adverse effect on our revenues and profits if such price decrease reduces the price we are able to charge for our biomass-based diesel.
There was a significant decline in RIN prices during the second and third quarters of 2014, but the price went back up in the fourth quarter and finished the year at its peak at $0.77 per RIN, as reported by OPIS. In 2013, RIN prices decreased sharply from $1.09 per RIN on July 1, 2013 to $0.35 per RIN at December 31, 2013. A reduction in RIN values, such as those experienced in 2013 and remaining low throughout the majority of 2014, may have a material adverse effect on our revenues and profits as such price decrease reduce the price we are able to charge for our biomass-based diesel.
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, which includes Neste Oil with approximately 600 million gallons of global renewable hydrocarbon diesel production capacity in Asia and Europe and Valero Energy Corporation with its Diamond Green joint venture renewable hydrocarbon diesel plant. These and other competitors that are divisions of larger enterprises may have greater financial resources than we do. We also have many smaller competitors. If our competitors consolidate or otherwise grow and we are unable to similarly increase our scale, our business and prospects may be significantly and adversely affected.
In addition, 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, 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.
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 hydrocarbon diesel plants: a 240 million gallon per year plant in Singapore, a 240 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 137 million gallon per year renewable hydrocarbon diesel plant in Norco, Louisiana in 2013. Under RFS2, renewable hydrocarbon 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 requirement described in “Business-Government Programs Favoring Biodiesel Production and Use.” Furthermore, under RFS2, renewable hydrocarbon 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 hydrocarbon diesel more cost-effective, both as a

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petroleum-based diesel substitute and for meeting RFS2 requirements. If renewable hydrocarbon 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 recently 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 not continue.
The development of alternative fuels and renewable chemicals also puts pressure on feedstock supply and availability to the biomass-based diesel industry. If these emerging technologies compete with biomass-based diesel for feedstocks, are more profitable or have greater governmental support than biomass-based diesel does, then the biomass-based diesel industry may have difficulty in procuring the feedstocks necessary to be successful.
Increased industry-wide production of biomass-based diesel could have a negative effect on our margins and there remains excess production capacity in the biomass-based diesel industry.
According to the National Biodiesel Board, or NBB, as of September 12, 2012, 2.7 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 more gallons of U.S. based biomass-based diesel production capacity was registered by non-NBB members and another 1.2 billion gallons of biomass-based diesel production was registered by foreign producers. Furthermore, plants under construction and expansion in the United States as of December 31 2011, if completed, could add an additional several hundred million gallons of annual biodiesel production capacity. 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.
The European Commission has imposed anti-dumping and countervailing duties on biodiesel blends imported into Europe, which have effectively eliminated our ability to sell those biodiesel blends in Europe.
In March 2009, as a response to the BTC, the European Commission imposed anti-dumping and anti-subsidy tariffs on biodiesel produced in the United States. These tariffs have effectively eliminated European demand for 20% biodiesel blends, or B20, or higher imported from the United States. The European Commission has extended these tariffs through 2014. In May 2011, the European Commission imposed similar anti-dumping and countervailing duties on biodiesel blends below B20. These duties significantly increase the price at which we and other United States biodiesel producers will be able to sell such biodiesel blends in European markets, making it difficult or impossible to compete in the European biodiesel market. These anti-dumping and countervailing duties therefore decrease the demand for biodiesel produced in the United States and increase the supply of biodiesel available in the United States market. Such market dynamics may negatively impact our revenues and profitability.
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.
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

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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 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 first such triennial report was released in February 2012. The 2012 report concludes that (1) the extent of negative impacts to date are limited in magnitude and are primarily associated with the intensification of corn production; (2) whether future impacts are positive or negative will be determined by the choice of feedstock, land use change, cultivation and conservation practices; and (3) realizing potential benefits will require implementation and monitoring of conservation and best management practices, improvements in production efficiency, and implementation of innovative technologies at commercial scales. Should future EPA triennial studies, or other analyses find that biofuel production and use has resulted in, or could in the future result in, adverse environmental impacts, such findings could also negatively impact public perception of biofuel 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.
Problems with product performance, in cold weather or otherwise, could cause consumers to lose confidence in the reliability of biodiesel which, in turn, would have an adverse impact on our ability to successfully market and sell biodiesel.
Concerns about the performance of biodiesel could result in a decrease in customers and revenues and an unexpected increase in expenses. 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 is the conventional indicator of a fuel’s potential for cold weather problems. The lower the cloud point, the better the fuel should perform in cold weather. According to an article published by Iowa State University Extension, the cloud point of biodiesel is typically between 30 °F and 60 °F, while the cloud point of the most common form of pure petroleum-based diesel fuel is typically less than 20 °F. It is our experience that when biodiesel is mixed with pure petroleum-based diesel to make a two percent biodiesel blend, the cloud point of the blended fuel can be 2 °F to 6 °F higher than petroleum-based diesel and the cloud point of a twenty percent biodiesel blend can be 15 °F to 35 °F higher than petroleum based diesel, depending on the individual cloud points of the biodiesel and petroleum-based diesel. Cold temperatures can therefore cause biodiesel blended fuel to become cloudy and eventually to gel when pure petroleum-based diesel would not, and this can lead to plugged fuel filters and other fuel handling and performance problems for customers and suppliers. The consequences of these higher cloud points may cause demand for biodiesel in northern and eastern United States markets to diminish during the colder months, which are the primary markets in which we currently operate.
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. This and other performance problems, including the possibility of particulate formation above the cloud point of a blend of biodiesel and petroleum-based diesel, may also 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.
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

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distribution of increasing volumes of biomass-based diesel and any infrastructure disruptions could materially harm our business.
We face competition from imported biodiesel and renewable hydrocarbon diesel, which may reduce demand for biomass-based produced by us and cause our revenues and profits to decline.
Biodiesel and renewable hydrocarbon diesel imports into the United States have increased significantly and compete with United States produced biodiesel. The imported fuels may benefit from production incentives or other financial incentives in their home countries that offset some of their production costs and enable them to profitably sell biodiesel or renewable hydrocarbon diesel in the United States at lower prices than United States-based biodiesel producers. Under RFS2, imported biodiesel and renewable hydrocarbon 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 our revenues. In January 2015, the EPA announced the approval for Argentinian biodiesel made from soybean oil to earn RINs. Imported biomass-based diesel that does not qualify under RFS2, also competes in jurisdictions where there are biomass-based diesel blending requirements.
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 recently adopted regulations that may limit the volume of biodiesel that can be used or require 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 hydrocarbon 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.
Several biofuels companies throughout the United States have filed for bankruptcy over the last several years due to industry and economic conditions.
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. 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, or we may encounter new competition from buyers of distressed biodiesel properties who enter the industry at a lower cost than original plant investors.
Risks Related to Our Common Stock
The market price for our common stock may be volatile.
Although there is currently an active and liquid trading market for our common stock, 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;

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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 generally and from time to time experience significant price and volume fluctuations 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. 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.
We have never paid dividends on our common stock and we do not anticipate paying any cash dividends in the foreseeable future.
We have paid no cash dividends on any of our classes of common stock to date, have contractual restrictions against paying cash dividends and currently intend to retain our future earnings to fund the development and growth of our business. As a result, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur. Investors seeking cash dividends should not invest in our common stock.
Delaware law and our amended and restated certificate of incorporation and bylaws will 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.

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If securities or industry analysts issue an adverse or misleading opinion regarding our stock or do not publish research or reports about our business, our stock price and trading volume could decline.
The trading market for our common stock relies in part on the research and reports that equity research analysts publish about us and our business. It is difficult for companies such as ours to attract independent equity research analysts to cover our common stock. We do not control these analysts or the content and opinions included in their reports. The price of our common stock could decline if one or more equity research analysts downgrade our common stock or if those analysts issue other unfavorable commentary or cease publishing reports about us or our business. Although there is currently an active and liquid trading market for REG common stock, if one or more equity research analysts ceases coverage of our company, we could lose visibility in the market, which in turn could cause our stock price to decline and the market for our common stock to become illiquid.
ITEM 1B.
Unresolved Staff Comments
None.
ITEM 2.
Properties
The following table lists each of our production facilities and their location, use, and nameplate production capacity. Each facility listed below is used by our Biomass-based diesel Segment.
COMPLETED PRODUCTION FACILITIES
Location
 
Use
 
Nameplate
Production
Capacity
(mmgy)
Ralston, Iowa
 
Biomass-based diesel production
 
12
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
Okeechobee, Florida
 
Fermentation facility
 
N/A
Our Ellenwood facility was idled by the previous owners prior to our acquisition and will remain so until repairs or upgrades are made where the facility meets our standards. We have not yet set a production date for our Ellenwood facility.
PETROTEC'S COMPLETED PRODUCTION FACILITIES
Location
 
Use
 
Nameplate
Production
Capacity
(mmgy)
Emden, Germany
 
Biomass-based diesel production
 
30
Oeding, Germany
 
Biomass-based diesel production
 
25.5
The following table lists our partially constructed or idled biomass-based diesel production facilities, the planned nameplate capacity and the approximate level of completion.
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 another building located at 215 Alexander Avenue, Ames, Iowa 50010 which is comprised of 12,000 square feet of office space.
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.

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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 began trading on the NASDAQ Global market on January 19, 2012. Prior to that time, there was no public market for our stock. The table below sets forth the high and low sales price of our common stock.
2014
High
 
Low
Fourth Quarter
$
10.97

 
$
8.67

Third Quarter
$
12.30

 
$
9.98

Second Quarter
$
12.66

 
$
9.75

First Quarter
$
12.89

 
$
9.61

 
 
 
 
2013
High
 
Low
Fourth Quarter
$
16.00

 
$
8.51

Third Quarter
$
16.50

 
$
12.77

Second Quarter
$
14.80

 
$
7.69

First Quarter
$
8.20

 
$
5.90

Holders
As of February 27, 2015, there were approximately 2,484 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. In addition, 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, 2014, 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 security holders
2,512,722

1 
 
$
11.24

2 
 
1,780,122

Equity compensation plans not approved by security holders

 
 

 
 

Total
2,512,722

 
 
$
11.09

 
 
1,780,122

1
Includes stock options of 87,026, restricted stock units of 616,394 and stock appreciation rights of 1,809,302.
2
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.

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The following graph shows a comparison of the cumulative total returns from January 19, 2012 to December 31, 2014, for us, the Clean Tech Index and the Russell 3000 Index. The graph assumes that $100 was invested on January 18, 2012 in our common stock, the Clean Tech Index and the Russell 3000 Index, and that all dividends were reinvested.
 
01/19/2012

 
12/31/2012

 
12/31/2013

 
12/31/2014

REGI
$
100.00

 
$
58.60

 
$
114.60

 
$
97.10

Clean Tech Index
100.00

 
99.59

 
136.55

 
124.91

Russell 3000
100.00

 
109.17

 
142.96

 
157.50

Sales of Unregistered Securities
On January 22, 2014, we issued 2,230,559 shares of our common stock to LS9 pursuant to the terms of that certain Asset Purchase Agreement, dated as of January 18, 2014, by and among LS9, REG, REG Life Sciences and Fortis Advisors LLC, solely in its capacity as the representative of LS9 and the indemnity securityholders named therein.
On February 25, 2014, we issued 49,662 shares of common stock with respect to the intangible supply agreement in connection with the purchase of substantially all Tellurian Biodiesel, Inc. and American BDF, LLC assets.
On June 3, 2014, we issued 3,493,613 shares of common stock to Syntroleum Corporation pursuant to the terms of the Asset Purchase Agreement, dated December 17, 2013, by and among REG, REG Synthetic Fuels and Syntroleum Corporation.
On December 24, 2014, we issued 2,070,538 shares of common stock to IC Green Energy Ltd. pursuant to the terms of the Agreement for the Sale and Purchase of Shares and Loan in Petrotec AG, dated December 9, 2014, by and among REG, REG European Holdings B.V., and IC Green Energy Ltd.
Issuer Purchases of Equity Securities
As of December 31, 2014, there were no authorized repurchase programs in effect under which we may repurchase shares of our outstanding common stock.
On February 19, 2015, the Company's board of directors approved a share repurchase program of up to $30 million of the Company's shares of common stock. Under the program, REG may repurchase shares from time to time in open market transactions, privately negotiated transactions or by other means. The timing and amount of repurchase transactions will be determined by the Company's management based on its evaluation of market conditions, share price, legal requirements and other factors. The program may be suspended, modified or discontinued at any time without prior notice.


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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, 2014 and 2013, and the selected consolidated statements of operations data for each year ended December 31, 2014, 2013 and 2012, 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, 2012, 2011 and 2010, and the selected consolidated statements of operations data for the years ended December 31, 2011 and 2010 have been derived from our audited consolidated financial statements not included in this annual report.
 
Year Ended December 31,
 
2014(1)
 
2013 (2)
 
2012 (3)
 
2011 (4)
 
2010(5)
 
(In thousands, except per share amounts)
Consolidated Statement of Operations Data:
 
 
 
 
 
 
 
 
 
Total revenues
$
1,273,831

 
$
1,498,138

 
$
1,015,034

 
$
824,031

 
$
216,455

Net income (loss) attributable to the company's common stockholders
81,620

 
165,254

 
43,482

 
42,753

 
(119,122
)
Net income (loss) per share attributable to common stockholders
 
 
 
 
 
 
 
 
 
Basic
2.00

 
5.00

 
1.53

 
3.14

 
(4.28
)
Diluted
1.99

 
5.00

 
0.27

 
3.14

 
(4.28
)
 
 
 
 
 
 
 
 
 
 
Consolidated Balance Sheet Data:
 
Total assets
$
1,372,888

 
$
740,855

 
$
495,784

 
$
484,447

 
$
369,643

Long-term debt
247,183

 
27,151

 
31,806

 
73,079

 
61,024

Redeemable preferred stock

 
3,963

 
83,043

 
147,779

 
122,436

(1)
Reflects the acquisitions of LS9 as of January 22, 2014, Syntroleum and Dynamic Fuels on June 3, 2014 and June 6, 2014, respectively, and Petrotec as of December 24, 2014 as further described in Note 5 of Item 8 - Financial Statements and Supplementary Data. In addition, the results reflect the issuance of the convertible senior notes on June 3, 2014 as further described in Note 12 of Item 8 - Financial Statements and Supplementary Data.
(2)
Reflects the acquisition of Soy Energy as of July 30, 2013 as further described in Note 5 of Item 8 - Financial Statements and Supplementary Data.
(3)
Reflects the acquisition of North Texas Bio Energy as of October 26, 2012 and BullDog Biodiesel on November 16, 2012 as further described in Note 5 of Item 8 - Financial Statements and Supplementary Data.
(4)
Reflects the acquisition of SoyMor as of July 12, 2011.
(5)
Reflects the deconsolidation of Blackhawk as of January 1, 2010, the acquisition of Blackhawk as of February 26, 2010, acquisition of CIE as of March 8, 2010, acquisition and consolidation of Seneca Landlord as of April 8, 2010, acquisition of Tellurian and ABDF as of July 16, 2010, and the acquisition of Clovis as of September 21, 2010.
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 are a leading North American advanced biofuels producer and are expanding into the development of renewable chemicals. We have been a leader in the biomass-based diesel industry since 1996. We utilize a nationwide production, distribution and logistics system as part of an integrated value chain model to focus on converting natural fats, oils and greases into advanced biofuels and converting diverse feedstocks into renewable chemicals. We own and operate nine biomass-based

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diesel production facilities with aggregate nameplate production capacity of 332 million gallons per year, or mmgy, as well as one fermentation facility.
During 2014, we sold 287 million gallons of biomass-based diesel, including 42 million gallons we purchased from third parties and resold. During 2013, we sold 259 million gallons, including 48 million gallons we purchased from third parties and resold.
We are expanding into the production of renewable chemicals, additional advanced biofuels and other products through our acquisition of LS9, Inc., or LS9, in January 2014. This industrial biotechnology business is a development stage company focusing on harnessing the power of microbial fermentation to develop and produce renewable chemicals, fuels and other products. The assets we acquired consist mainly of in-process research and development, fixed assets and goodwill.
We began selling petroleum-based heating oil and diesel fuel, and 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 our existing Northeast terminal locations in February 2014. We are expanding our sales of additional biofuel blends to Minnesota and Iowa terminal locations and potentially in other areas across North America.
We acquired a 75 mmgy nameplate capacity renewable hydrocarbon diesel biorefinery located in Geismar, Louisiana in June 2014. Our Geismar facility had been idled by its previous owner and began operating again by us in October 2014 after our completion of certain upgrades.
We also expanded our business internationally by acquiring a majority interest in Petrotec AG in December 2014. We have made a cash tender offer for the remaining Petrotec shares, which had not closed as of the date of this filing. Petrotec is a fully-integrated company utilizing more than 15,000 collection points to gather used cooking oil and other waste feedstocks to produce biomass-based diesel at its two biorefineries in Emden and Oeding, Germany.  Petrotec’s nameplate production capacity is approximately 56 mmgy.
We derive revenues from two reportable business segments: Biomass-based diesel and Services
Biomass-based diesel Segment
Our Biomass-based diesel segment, as reported herein, includes:
the operations of the following biomass-based diesel production facilities:
a 12 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;
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 hydrocarbon diesel production facility located in Geismar, Louisiana, since its acquisition in June 2014;
a 30 mmgy nameplate biomass-based diesel production facility located in Emden, Germany since its 69% majority ownership was acquired in December 2014;
a 26 mmgy nameplate biomass-based diesel production facility located in Oeding, Germany since its 69% majority ownership was acquired in December 2014; and
a demonstration scale facility located in Okeechobee, Florida since its acquisition in January 2014.
purchases and resale of biomass-based diesel, Renewable Identification Numbers, or RINs, and raw material feedstocks acquired from third parties;
our 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 2014 and 2013, our revenues from the sale of co-products were less than five percent of our total Biomass-based diesel segment revenues. During 2014, 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

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wholly owned facilities were less than 2% of our total Biomass-based diesel segment revenues. We have not derived any revenues to date from our renewable chemicals business.
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. From time to time, we may obtain these 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 market 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.
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.
We have utilized our construction management expertise internally to upgrade our facilities. In October 2014, we completed a $20 million upgrade to our Mason City facility, enabling the plant to run on lower cost feedstocks in addition to refined vegetable oils the plant was originally designed to process. In December 2014, we completed a $15.8 million upgrade and storage expansion to our Newton facility. In 2013, we completed a $22 million upgrade to our Albert Lea facility and spent $4 million and $1 million in repairs of our recently acquired New Boston and Mason City facilities, respectively. We anticipate external revenues derived from construction management services will be minimal in future periods. Demand for our construction management and facility management and operational services depend on capital spending by potential customers and existing customers, which is directly affected by trends in the biomass-based diesel industry. We have not received any orders or provided services to outside parties for new facility construction services since 2009.
Factors Influencing Our Results of Operations
The principal factors affecting our segments 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 than petroleum-based diesel, excluding biomass-based diesel incentives and credits. The biomass-based diesel industry’s growth has largely been the result of federal and state programs that require or incentivize biomass-based diesel, which allows biomass-based diesel to compete with petroleum-based diesel on price.
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 hydrocarbon diesel production meets two categories of an Obligated Party’s annual renewable fuel required volume obligation, or RVO—biomass-based diesel and undifferentiated advanced biofuel. The RFS2 program required the domestic use of one billion gallons of biomass-based diesel in 2012 and 1.28 billion gallons in 2013. As of this filing, the EPA has not finalized the 2014 or the 2015 RVO. In November 2013, the EPA proposed that the 2014 and 2015 biomass-based diesel RVO be 1.28 billion gallons for each of those years and a reduced Advanced Biofuel RVO of 2.20 billion gallons rather than the original EISA volume of 3.75 for 2014, a proposal whereby the EPA has issued a "notification of delay in issuing standards." Our sales volumes and revenues have benefited from our increased production capacity, as well as demand relating to the implementation of RFS2.

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Volumes of biomass-based diesel produced increased from 2010 to 2013. From 2013 through 2014 volumes of biomass-based diesel were flat. According to EMTS data, 1.78 billion gallons of biomass-based diesel was produced and imported into the U.S. in 2013. Notwithstanding the lack of a finalized 2014 RVO, according to EMTS data, 1.75 billion gallons of biomass-based diesel was produced and imported into the U.S. in 2014.
The BTC provided a $1.00 refundable tax credit per gallon of 100% pure biomass-based diesel, or B100, to the first blender of biomass-based diesel with petroleum-based diesel fuel. The BTC became effective January 1, 2005 and then lapsed January 1, 2010 before being reinstated retroactively on December 17, 2010. The BTC again expired as of December 31, 2011 and on January 2, 2013, it was again reinstated, retroactively for 2012 and through December 31, 2013. The BTC expired again on December 31, 2013 and was retroactively reinstated for 2014 on December 19, 2014. Unlike prior years, Congress did not grant a two year reinstatement, but rather only reinstated the BTC for 2014. Accordingly, the BTC expired again on December 31, 2014. We recognized a net benefit from the BTC of $78.8 million in 2014 and expect to recognize a net benefit of $16.5 million in 2015 relating to 2014 activity. It is uncertain whether the BTC will be reinstated and if reinstated, whether or not it would be reinstated retroactively. The expiration of the BTC along with any amendments that may be made if the BTC is reinstated or a similar credit is enacted, could adversely affect our financial results in the future.
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, like RINs and the BTC 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. During 2013, the value of RINs, as reported by OPIS, have contributed to the average B100 spot price of a gallon of biomass-based diesel, as reported by The Jacobsen, and range from a low of $0.35 per gallon, or 9%, in October to a high of $2.20, or 43% per gallon in January. During 2014, the value of RINs, as reported by OPIS, have contributed to the average B100 spot price of a gallon of biomass-based diesel, as reported by The Jacobsen, from a low of $0.64 per gallon, or 19%, in January to a high of $1.15, or 34%, per gallon in December. There was a significant decline in RIN prices during the second and third quarters of 2014, but the prices went back up in the fourth quarter and finished the year at their peak.
This decrease in the value of RINs during 2014 and 2013 resulted in a $4.3 million and $3.2 million, respectively, write-down to lower of cost or market on RIN inventory acquired from third parties that occurred throughout the year. See “Note 10 – Other Assets” to our consolidated financial statements. We enter into forward contracts to sell RINs and we use risk management position limits to manage RIN exposure. Because of EPA rules limiting the amount of assigned RINs we can hold at any one time, the value of these assigned RINs held in inventory does not have a material effect on margins from period to period.
During 2014, feedstock expense accounted for 80% of our production cost, while methanol and chemical catalysts expense accounted for 5% and 3% of our costs of goods sold, respectively.
Feedstocks for biomass-based diesel production, such as inedible 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. The following table outlines some of the factors influencing supply and price for each feedstock:

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Feedstock
 
Factors Influencing Supply and Price
 
 
 
Inedible Corn Oil
 
Demand for inedible corn oil from biomass-based diesel and other markets
 
 
Ethanol production
 
 
Export demand
 
 
Extraction system yield
 
 
Implementation of inedible corn oil separation systems into existing and new ethanol facilities
 
 
 
Used Cooking Oil
 
Biomass-based diesel demand
 
 
Export demand
 
 
Population
 
 
Number of restaurants in the vicinity of collection facilities and terminals which is dependent on population density
 
 
Cooking methods and eating habits, which can be impacted by the economy
 
 
 
Inedible Animal Fat
 
Export demand
 
 
Number of slaughter kills in the United States
 
 
Demand for inedible animal fat from biomass-based diesel and other markets
 
 
 
Soybean Oil
 
Export demand
 
 
Weather conditions
 
 
Soybean meal demand
 
 
Farmer planting decisions
 
 
Government policies and subsidies
 
 
Crop disease
 
 
Biomass-based diesel demand
During 2014 and 2013, 85% and 83%, respectively, of our feedstocks 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 2011 through December 2014. The results were derived using assumed conversion factors for the yield of each feedstock and subtracting the cost of producing one gallon of biodiesel made from each respective lower cost feedstock from the cost of producing one gallon of biodiesel made from soybean oil.

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(1)
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 7.7 pounds per gallons).
(2)
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).
(3)
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).
(4)
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).
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 2011 to December 2014.

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(1)
Biodiesel prices are based on the monthly average of the midpoint of the high and low prices of B100 (Upper Midwest) as reported by The Jacobsen.
(2)
Soybean oil (crude) prices are based on the monthly average of the daily closing sale price of the nearby soybean oil contract as reported by CBOT (based on 7.7 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.
Feedstock prices began to decline in June 2014 which continued throughout 2014. Palm oil prices also moved lower in third quarter and traded in a sideways-pattern in fourth quarter 2014. A record corn and soybean harvest coupled with lower energy prices helped push feedstock prices lower in the last-half of 2014. US cattle slaughter numbers continued at a historically low rate as a result of the two year drought in the southern plains. Hog slaughter saw a seasonal increase in the last half of 2014, though numbers stayed below the previous year due to impact on the herd size related to the PED virus. Feedstock price declines were offset by a sharp decrease in energy prices mainly driven by a decrease in crude oil prices beginning in October.
Risk Management
The profitability of the biomass-based diesel production business largely depends on the spread between prices for feedstocks and biomass-based diesel, including RINs and BTC, each of which is subject to fluctuations due to market and policy factors and each of which is not significantly correlated. Adverse price movements for these commodities directly affect our operating results. We attempt to protect operating margins by entering into risk management contracts that mitigate price volatility of our feedstocks, such as inedible corn oil, used cooking oil and inedible animal fat and energy prices. 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 heating oil and 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.
Inedible corn oil, used cooking oil and inedible animal fat are the primary feedstocks we used to produce biomass-based diesel in 2012, 2013 and 2014. 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 limited efforts to risk manage against changing inedible corn oil, used cooking oil and

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inedible animal fat prices have involved entering into futures contracts, swaps or options on other commodity products, such as soybean oil or heating oil. 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. For example, most of the feedstock requirements for our Ralston facility were supplied under an agreement with West Central which expired on January 31, 2015 and automatically renewed for one additional year. The purchase price for soybean oil under these contracts may be indexed to prevailing Chicago Board of Trade, or 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 soybean oil requirements generally for varying periods up to one year.
Our ability to mitigate our risk of falling biomass-based diesel and RIN 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 market for biomass-based diesel futures 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 heating oil. 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 established futures market for RINs, which severely limits the ability to risk manage the price of RINs. We enter into forward contracts to sell RINs and we use risk management position limits to manage RIN exposure.
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. 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 incurred risk management gains of $61.6 million from our derivative financial instrument trading activity for the year ended December 31, 2014, compared to risk management losses of $5.7 million for the year ended December 31, 2013. Changes in the value of these futures or swap instruments are recognized in current income or loss. Over the year 2014, risk management gains were impacted mostly from the significant decline in energy market prices, specifically the fourth quarter decline of crude oil and heating oil. 2014 risk management gains have represented an income of $0.21 per gallon sold. Over the last three years prior to 2014, risk management losses have represented an average expense of $0.02 per gallon sold. The current three-year average, which incorporates 2014 risk management gains, represents an average income of $0.07 per gallon sold.
Seasonality
Our operating results are influenced by seasonal fluctuations in the demand for biodiesel. Our sales tend to decrease during the winter season due to blending concentrations being reduced to adjust for performance during colder weather. Colder seasonal temperatures can cause the higher cloud point biodiesel we make from inedible animal fats to become cloudy and eventually gel at a higher temperature than petroleum-based diesel or lower cloud point biodiesel made from soybean oil, canola oil or inedible corn oil. Such gelling can lead to plugged fuel filters and other fuel handling and performance problems for customers and suppliers. Reduced demand in the winter for our higher cloud point biodiesel can result in excess supply of such higher cloud point biodiesel and lower prices for such 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.
RIN prices may also be subject to seasonal fluctuations. The RIN is dated for the calendar year in which it is generated. Since only 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 increase if it is undersupplied. Similar to prior years, during 2013, biomass-based diesel RIN generation was 1.78 billion gallons when the RVO for biomass-based diesel was 1.28 billion gallons and RIN prices declined during the third and fourth quarters as production rates exceeded the RVO. For 2014, biomass-

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based diesel RIN generation was 1.75 billion gallons even though the RVO for biomass-based diesel was originally proposed at 1.28 billion gallons. As of the date of this filing, the RVOs for 2014 and 2015 are still not finalized.
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. Production in 2011, 2012 and 2013 was in excess of a continued expanding RFS2 volume requirements. 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. As of this filing, the EPA has not finalized the 2014 or 2015 RVO. In November 2013 the EPA proposed the 2014 and 2015 biomass-based diesel RVO at 1.28 billion gallons for each year. The EPA later issued a "notification of delay in issuing standards", effectively withdrawing the proposal. As of the date of this filing, the RVO for 2014 and 2015 had not been proposed nor finalized. Notwithstanding these issues, we expect RFS2 to continue to create demand for biomass-based diesel. Biomass-based diesel production, as reported by EMTS, was flat when comparing 2013 gallons produced to the 1.75 billion gallons produced during 2014.
During 2013 and 2014, the amount of imported gallons qualifying under RFS2 has increased. Imported gallons will likely make up a growing percentage of the RVO, as the EPA has approved a plan to allow Argentinian biodiesel made from soybean oil to qualify for RINs generation. Under RFS2, Obligated Parties are entitled to satisfy up to 20% of their annual requirement for with prior year RINs. We saw a decline in RIN prices in the first three quarters of 2014 as production rates exceeded the then proposed, yet delayed issuance and not yet finalized, RVO target.
Components of Revenues and Expenses
We derive revenues in our Biomass-based diesel segment from the following sources:
sales of biodiesel and renewable hydrocarbon diesel produced at our wholly-owned facilities, including RINs, 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 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 items 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 federal biodiesel mixture excise tax credit, and from the USDA Advanced Biofuel Program.
We derive revenues in our Services segment from the following sources:
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 biomass-based diesel production facilities.
Cost of goods sold for our Biomass-based diesel segment includes:
with respect to our production facilities, expenses incurred for feedstocks, catalysts and other chemicals used in the production process, leases, utilities, depreciation, salaries and other indirect expenses related to the production process, and, when required by our customers, transportation, storage and insurance;
with respect to biomass-based diesel acquired from third parties produced under toll manufacturing arrangements, expenses incurred for feedstocks, transportation, catalysts and other chemicals used in the production process and toll processing fees paid to the facility producing the biomass-based diesel;
with respect to 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;

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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.
Selling, general and administrative expense consists of expenses generally involving corporate overhead functions and operations at our Ames, Iowa and Tulsa, Oklahoma operations, as well as research and development expenses incurred at REG Life Sciences.
Other income (expense), net is primarily comprised of the change in fair value of contingent considerations issued as part of the acquisitions of LS9 and Syntroleum Corporation/Dynamic Fuels, LLC, interest expense including the accretion of convertible debt and amortization of deferred financing costs, and interest income.
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, 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 and raw material feedstocks acquired from others;
fees received under toll manufacturing agreements with third parties;
fees received from federal and state incentive programs for renewable fuels;
fees from construction, operations and project management; and
fees received for the marketing and sales of biomass-based diesel produced by third parties.
Biomass-based diesel sales as well as RINs 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 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 or reductions of tax incentives for biodiesel production or consumption would have a material adverse effect on our revenues and operating margins” and “Factors Influencing Our Results of Operations-Governmental programs favoring biodiesel production and use.” In connection with the biodiesel tax credit, we file a claim with the Internal Revenue Service, or

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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 19, 2014, the Tax Increase Prevention Act of 2014 was signed into law, which reinstated a set of tax extender items including the retroactive reinstatement of the federal biodiesel mixture excise tax credit for 2014 and expired on December 31, 2014.
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.
Impairment of Long-Lived Assets and Certain Identifiable Intangibles.
We have three partially constructed production facilities and one non-operational production facility. In 2007, the Company commenced construction of two 60 mmgy production facilities, one near New Orleans, Louisiana and the other in Emporia, Kansas. In 2008, the Company halted construction of these facilities as a result of conditions in the biomass-based diesel industry and the credit markets. Construction of the New Orleans facility is approximately 45% complete and construction of the Emporia facility is approximately 20% complete. In September 2010, the Company acquired a 15 mmgy production facility in Clovis, New Mexico which is approximately 50% complete. Currently, the Clovis facility is being operated as a terminal. In November 2012, the Company completed our acquisition of Bulldog Biodiesel, LLC, a 15 mmgy production facility near Atlanta, Georgia, that was non-operational at the time the Company purchased it and will remain idled until certain repairs or upgrades are made.
We review long-lived assets, including property, plant and equipment and definite-lived intangible assets for impairment when circumstances dictate. Such evaluations generally are focused on our plants - regardless of whether they are operating, are under construction or are currently on a “construction hold.” The latter assets are those that receive the most attention as their future cash flows are subject to the most uncertainty. Asset are impaired if the undiscounted net cash flows estimated to be generated by those assets are less than their carrying amounts. If estimated future undiscounted cash flows are not sufficient to recover the carrying value of the assets, an impairment charge is recorded for the amount by which the carrying amount of the assets exceeds its fair value. Fair value is determined by management estimates using discounted cash flow calculations. The estimate of cash flows arising from the future use of the asset that are used in the impairment analysis requires judgment regarding what we would expect to recover from the future use of the asset.
Significant assumptions used by management in the undiscounted cash flow analysis include the projected demand for biomass-based diesel based on annual renewable fuel volume obligations under RFS2, our capacity to meet that demand, the estimated market price of biomass-based diesel and the cost of feedstock used in the manufacturing process. For facilities under construction or that are currently on construction hold, management’s estimates also include the capital expenditures necessary to complete construction of the plant. Our facilities under construction or on construction hold are expected to have substantially similar operating capabilities and results as our current operating facilities. Such operating capabilities would include similar feedstock capabilities, similar access to low cost feedstocks, similar proximity to shipping from our vendors and to our customers, and would contemplate our ability to implement best practices among our various currently operating facilities to maximize production volumes and reduce operating costs.
We estimated the future cash flows from the facilities "under construction" or "on construction hold" utilizing the following significant assumptions:
Costs to complete: The remaining costs to complete the plant construction are developed by management, using historical and plant-specific knowledge and external estimates. Management’s estimate of costs included those required to finish the general structure of each facility, as well as furnish it with the appropriate equipment necessary to produce biomass-based diesel. There has not been an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset (asset group). There can be no assurance actual costs to complete or upgrade these facilities will be consistent with these estimates.
Gallons sold: We estimate the aggregate gallons to be produced and sold based upon nameplate capacity of the plants under construction or not in use coupled with historical operating rates for our existing plants.
Gross margin per gallon: We estimate rising sales prices and costs after 2014. This annual increase is a consequence of anticipated increased demand for biomass-based diesel, market trends expected for the energy industry and normal inflationary pressures. biomass-based diesel sales prices are estimated using the expected prices for biomass-based diesel, RINs and co-products. When building the estimate for future prices, we weigh historical evidence, CBOT and NYMEX future prices and industry forecasts. To develop the estimated feedstock prices, we utilized soybean oil as a base coupled with a spread to soybean oil for all other feedstocks based on historical experience and expected future price changes.

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Plant operation costs: We estimate plant operation costs to increase with production, until a steady cost level is reached once the plants are operating in a stabilized manner. Plant operating costs are estimated based upon costs at currently operating plants and take into account the size of the plants under construction and production volumes.
Period of time used in recovery analysis: To estimate the period of time utilized in the recovery analysis, we look to the primary asset group at the plants which the asset group derives its cash-flow-generating capacity. We consider the plant assets and their operational functionality and determined that the inner equipment of the plants, (e.g. tanks, separators, filters, heaters, etc.), is the most significant component of the asset group. We have determined that the useful life of this equipment has a range of 10-30 years depending on its use, with the majority of the equipment having a 20 year life. Therefore, we have selected a 20 year period from the original date the assets are placed into service as the time period over which the cash flows would be projected.
Other Considerations - Means of financing of facilities under construction or construction on hold: In 2008, we halted construction on our New Orleans, Louisiana and Emporia, Kansas facilities as a result of conditions in the biomass-based diesel industry and the credit markets. We continue to pursue financing and intend to complete the facilities when industry conditions improve and financing becomes available on terms satisfactory to us. Since construction halted at these facilities in 2008, we have continued to monitor the construction sites and perform routine maintenance on the partially constructed assets. We also have pursued programs under which we could obtain a government guarantee to enhance our ability to obtain financing for these facilities, but at this point have not been able to obtain any such guarantees. We will continue to pursue such government programs in the future to the extent they arise. If available, we would also consider using funds from operations to fund a portion of the construction at these facilities. As currently configured, the assets can be completed as biomass-based diesel production facilities, or with alternative or additional capabilities for the manufacture of specialty chemicals or other renewable products such as advanced biofuels and renewable chemicals. Some of the existing components could be transported for use at our other production facility locations, or they could be sold to third parties for various uses. The Emporia construction project can benefit from a city incentive package that continues through 2018. In addition, from time to time we have had discussions with potential investors and commercial partners regarding these facilities. We have also invested in third party engineering studies to revise and enhance construction completion plans on a more cost effective and profit-driven basis. We cannot be certain if or when such facilities will be completed or any alternate transaction regarding such facilities that we may pursue will be consummated.
There were no asset impairment charges for the years ended December 31, 2014, 2013 or 2012.
Valuation of certain assets and liabilities related to acquisition of LS9. The significant estimates related to our acquisition of LS9 include the valuation of in-process research and development intangible assets, or IPR&D, and contingent consideration. We engaged an independent external valuation specialist to provide assistance in measuring the fair values of these assets and liabilities related to the acquisition.
The fair value of the IPR&D was determined using an income approach called the excess earnings method. Cash flows for specific products for which the IPR&D relate were forecasted, and include estimates for costs to complete research and development activities, projected revenues based upon market data and discussions with market participants and projected operating expenses based on experience with smaller scale production. Appropriate returns for other identifiable assets were then calculated using generally accepted valuation methodologies and deducted from the forecast. These residual cash flows were then discounted to their present value using a risk adjusted discount rate of 25%. This rate reflects the developmental stage of the business and risks associated with development and commercialization of the products. Several scenarios were considered for each IPR&D project to reflect the possible outcomes dependent on future decisions related to production capacity, feedstock inputs and costs and decisions to discontinue development. Each scenario was assigned a probability based on its likelihood of occurring. The estimated fair value of IPR&D was arrived at by adding the probability weighted values of the scenarios considered.
We will pay contingent consideration of up to $21.5 million to the previous owners of LS9 if, and when, we achieve certain development and commercialization milestones of products from LS9’s technology. Payments for achieving individual product milestones range from $0.5 million to $2.5 million and are payable in either cash or shares of our common stock at our election. The fair value of contingent consideration was determined using an expected probability income approach. We estimated the likelihood of achieving each milestone for each product under development. These probabilities ranged from 0% to 88%. The anticipated time to reaching each milestone was also considered to determine if the payment would be made within the five-year milestone consideration time frame. Both the likelihood of achieving milestones and the related timing were estimated based on the current stage of development and the complexity of completing development and commercialization. If the anticipated time to the milestone fell within the time frame, then the probability-weighted earnout payment was discounted using a risk adjusted discount rate of 8%. The fair value of the contingent consideration is estimated at the end of each reporting period with changes in fair value running through current period earnings.

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Valuation of certain assets and liabilities related to acquisition of Syntroleum/Dynamic Fuels. The significant estimates related to our acquisition of Syntroleum and Dynamic Fuels include the valuation of intangibles and contingent consideration. We engaged an independent external valuation specialist to provide assistance in measuring the fair value of these assets and liabilities related to the acquisition.
The fair value of the renewable hydrocarbon diesel technology was determined using the relief from royalty method, or RFR, which reflects the savings realized by owning the intangible assets. The premise associated with this valuation technique is that if the intangible assets were licensed to an unrelated party, the unrelated party would pay a percentage of revenue for the use of the assets. The cost savings, or relief from royalty, represents the value of the intangible assets. The value under RFR method is dependent upon the following factors for an asset: royalty rate, discount rate, expected life and projected revenue.
We will pay contingent consideration to Tyson Foods, if and when, we achieve certain production volumes. The agreement calls for periodic payments to Tyson Foods based on pre-determined payments per gallon of product sold, with a maximum of $35.0 million over a term of eleven and a half years. The obligation with respect to these future payments is guaranteed by the Company. The initial valuation of the contingent consideration was based on four distinct production forecasts developed to represent the range of possible production levels for Dynamic Fuels. The base case anticipates the plant will be running at full capacity by the end of 2015, and continue to run at full capacity thereafter. We considered there to be an 80% probability of realizing the forecasted base case. We believe that there are also foreseeable situations in which the Dynamic Fuels facility would not run at full capacity. As a result, we estimated a 10% probability the facility would run at two-thirds of capacity on average, and a 5% probability the facility would run at half capacity on average. The fourth scenario, given a 5% probability, is that some operational, regulatory, environmental, or unforeseen event prohibits Dynamic Fuels from producing renewable fuels at any significant level, leading to a shut-down with no significant contingent payments made to Tyson Foods. The probability weighted contingent payments were discounted using a risk adjusted discount rate of 5.8%. The fair value of the contingent consideration is estimated at the end of each reporting period with changes in fair value running through current period earnings.
Convertible Notes. In June 2014, the Company issued $143.8 million in convertible senior notes. Applicable authoritative accounting guidance required that the liability component of the convertible senior notes be recorded at its fair value as of the issuance date and the debt discount being recorded in equity on a net of tax basis. The fair value of the convertible senior notes was calculated as if the convertible senior notes did not contain any conversion or capped call provisions. Therefore, a payment schedule was developed to calculate the anticipated interest payments to be made beginning on December 15, 2014 and continuing on each subsequent June 15 and December 15 until the final interest payment and repayment of principal on June 15, 2019. The payments were discounted at an implied yield on the note based upon a lattice model using a risk free rate adjusted for the volatility in our securities excluding the conversion provisions. The debt discount is being amortized through interest expense until the maturity date of June 15, 2019.
In connection with the issuance of the convertible senior notes, the Company entered into capped call transactions. The capped call transactions are expected to reduce potential dilution of earnings per share upon conversion of the convertible senior notes. The purchased capped call transactions were recorded as a reduction to common stock-additional paid-in-capital.
Goodwill asset valuation. Over the past several years we have made a number of acquisitions. Such acquisitions have had a significant amount of the purchase price allocated to goodwill. While goodwill is not amortized, it is subject to periodic reviews for impairment. We review the carrying value of goodwill for impairment annually on July 31 or when we believe impairment indicators exist. Goodwill is allocated and reviewed for impairment by reporting units. The analysis is based on a comparison of the carrying value of the reporting unit to its fair value, determined utilizing a discounted cash flow, or DCF, methodology and consideration of a market approach. Additionally, we review the carrying value of goodwill whenever events or changes in business circumstances indicate that the carrying value of the assets may not be recoverable. Changes in estimates of future cash flows caused by items such as unforeseen events or sustained unfavorable changes in market conditions could negatively affect the fair value of the reporting unit’s goodwill asset and result in an impairment charge.
We engage an independent external valuation specialist to provide assistance in measuring the fair value of our biomass-based diesel and services reporting units using an income approach. The income approach uses a discounted cash flow, or DCF, analysis based on cash flow estimates prepared by us in addition to comparing other selected public guideline company information. The selected DCF method is an invested capital method. In performing the services reporting unit goodwill impairment analysis, cash flows generated from services provided to third parties and to the biomass-based diesel reporting unit were used to determine the reporting unit’s fair value.
We recognize the narrow difference between the fair value and the carrying value of the biomass-based diesel reporting unit.  Such difference is primarily attributable to the weighting of uncertainties around the continuance of government supports for the industry; absent such discounting, there would be a much greater difference between fair value and carrying value. 

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There were other acquisitions made during the course of 2014; we are carefully monitoring goodwill attributable to these acquisitions but, because of the proximity of the acquisition date to the annual measurement date, such analysis was focused primarily on significant changes since the measurement date.
The annual impairment tests as of July 31, 2014 determined that the fair value at the biomass-based diesel reporting unit exceeded its value by approximately 7% and the services reporting unit exceeded its value by approximately 66%. We also reviewed goodwill from our acquisitions of LS9, Syntroleum and Dynamic Fuels at July 31, 2014 and determined no impairment was needed. No impairment of goodwill was recorded during the years 2014, 2013, and 2012. Because of our recent acquisitions, we are required to continue to reassess our reporting units and determine whether we are required to reallocate the acquired goodwill given changes in reporting units. Such reassessment can lead to differences in forecasted cash flows and in the amount of specific goodwill against which such forecasted cash flows are measured. There can be no assurances that future circumstances and/or conditions will not change, which could result in an impairment of goodwill. Such circumstances and/or conditions could include, but are not limited to, the aforementioned change in reporting units, further decline in the price of our common stock, deterioration in our financial condition or results of operations, and/or adverse changes in the fair value of our assets and liabilities. Management continues to monitor circumstances and conditions for events that could result in an impairment of our goodwill.
Income taxes. We evaluate our deferred tax assets to determine if valuation allowances are required or should be adjusted. A valuation allowance is established against our deferred tax assets based on consideration of all available evidence, both positive and negative, using a “more likely than not” standard. This assessment considers, among other matters, the nature, frequency and severity of recent losses, forecasts of future profitability, the duration of statutory carry-forward periods, our experience with tax attributes expiring unused and tax planning alternatives. In making such judgments, significant weight is given to evidence that can be objectively verified.
As a result of excluding certain government incentives from taxable income in 2013, we were in a cumulative loss position for the preceding three years which is considered significant negative evidence that is difficult to overcome on a “more likely than not” standard through objectively verifiable data. While our long-term financial outlook remained positive, we concluded that our ability to rely on our long-term outlook and forecasts as to future taxable income was limited due to uncertainty created by the weight of the negative evidence. As a result, we recorded a valuation allowance offsetting our deferred tax assets.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon. We believe there is a reasonable basis in the tax law for all of the positions we take on the various federal and state tax returns we file. However, in recognition of the fact that various taxing authorities may not agree with our position on certain issues, we expect to establish and maintain tax reserves. Significant judgment is required in evaluating our tax positions, including evaluating uncertainties around the technical merits and measurement of our tax position to exclude certain government incentives from taxable income.

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Results of Operations
Fiscal years ended December 31, 2014 and December 31, 2013
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,
 
2014
 
2013
Gallons sold
287.3 million
 
258.6 million
Average B100 price per gallon
$
3.62

 
$
4.58

 
 
 
 
Revenues
$
1,273,831

 
$
1,498,138

Costs of goods sold
1,113,219

 
1,258,705

Gross profit
160,612

 
239,433

Selling, general and administrative expenses
62,681

 
45,865

Research and development expense
12,424

 
258

Income from operations
85,507

 
193,310

Other income (expense), net
603

 
(2,009
)
Income tax expense
(3,572
)
 
(4,935
)
Net income
82,538

 
186,366

Less—Net income attributable to noncontrolling interests
(73
)
 

Net income attributable to the Company
82,611

 
186,366

Gain on redemption of preferred stock
378

 

Distributed and undistributed dividends to preferred stockholders
(40
)
 
(2,055
)
Effects of participating preferred stock
(91
)
 
(16,272
)
Effects of participating share-based awards
(1,238
)
 
(2,785
)
Net income attributable to the Company’s common stockholders
$
81,620

 
$
165,254

Revenues. Our total revenues decreased $224.3 million, or 15%, to $1,273.8 million for the year ended December 31, 2014, from $1,498.1 million for the year ended December 31, 2013. This decrease was primarily due to the decreasing biomass-based diesel prices as a result of the drop in crude oil prices in conjunction with reduced demand attributable to regulatory uncertainty as the EPA currently has not finalized the RVO for 2014 or 2015.
Biomass-based diesel revenues including government incentives decreased $224.6 million, or 15%, to $1,273.4 million during the year ended December 31, 2014, from $1,498.0 million for the year ended December 31, 2013. The 2014 revenues reflected a net benefit of $78.8 million government incentive revenue as a result of the December19, 2014 reinstatement application of the federal biodiesel mixture excise tax credit for 2014 and the net effect of an increase in gallons sold, but coupled with a decrease in biomass-based diesel prices. The increase in gallons sold reflects increased throughput across our production facilities due to upgrades to our existing facilities. Due to lower RIN and energy prices in 2014, our average B100 sales price per gallon decreased $0.96, or 21%, to $3.62 during the year ended December 31, 2014, compared to $4.58 during the year ended December 31, 2013. The decrease in average sales price from 2013 to 2014 contributed to a $248.3 million revenue decrease when applied to the number of gallons sold during 2013. Gallons sold increased 28.7 million, or 11%, to 287.3 million during the year ended December 31, 2014, compared to 258.6 million during the year ended December 31, 2013. The increase in gallons for the year ended December 31, 2014 accounted for a revenue increase of $103.9 million using 2014 average sales pricing. The decrease in biomass-based diesel government incentives despite the increase in gallons sold was mainly due to the 2013 biomass-based diesel government incentives including an amount of $57.7 million relating to 2012 activities and that market participants were acting as if the biodiesel tax credit would be reinstated throughout the year and entered into agreements to capture the credit when or if reinstated. Sales of separated RIN inventory were $130.2 million and $143.5 million for the years ending December 31, 2014 and 2013, respectively.
Costs of goods sold. Our costs of goods sold decreased $145.5 million, or 12%, to $1,113.2 million for the year ended December 31, 2014, from $1,258.7 million for the year ended December 31, 2013. Costs of goods sold as a percentage of revenues were 87% and 84% for the years ended December 31, 2014 and 2013, respectively. The increase in costs of goods sold as a percentage of revenues in 2014 was primarily due to the net effect of lower revenues per gallon as a direct impact of the drop in crude oil prices on biomass-based diesel prices and slightly lower feed stock costs in 2014 as compared to 2013.

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Average lower cost feedstocks prices for the year ended December 31, 2014 was $0.34 per pound, compared to $0.39 per pound for the year ended December 31, 2013. Soybean oil costs for the year ended December 31, 2014 was $0.38 per pound in comparison to $0.45 per pound for the year ended December 31, 2013. Due to the significant decline in energy market prices such as crude oil and heating oil during the fourth quarter 2014, we had gains of $61.6 million from risk management trading activity for the year ended December 31, 2014, compared to losses of $5.7 million from risk management trading for the year ended December 31, 2013, respectively. Over the last three years prior to 2014, risk management losses have represented an average expense of $0.02 per gallon sold. The current three-year average, which incorporates 2014 risk management gains, represents an average income of $0.07 per gallon sold. In addition, the decrease in the value of RINs during 2014 resulted in a $4.3 million write-down to lower of cost or market on RIN inventory held throughout the year compared to a write-down of $2.9 million during 2013. Costs of goods sold for separated RIN inventory sales were $119.8 million and $144.0 million for the years ending December 31, 2014 and 2013, respectively.
Selling, general and administrative expenses. Our selling, general and administrative, or SG&A, expenses were $62.7 million for the year ended December 31, 2014, compared to $45.9 million for the year ended December 31, 2013. SG&A expenses increased $16.8 million, or 37%, for the year ended December 31, 2014 as compared to 2013. This increase was driven mainly by a $7.9 million increase in employee related expenses as we increased headcount to support our growth, a $1.7 million increase in legal and professional fees, a $0.6 million increase in depreciation expense, $1.1 million increase in bad debt expense and a $5.5 million increase in meeting and travel expenses, IT, insurance and other expenses, the majority of which was attributable to contracted services and amortization expenses related to acquired intangible assets.
Research and development expense. Our research and development expenses were $12.4 million for the year ended December 31, 2014, compared to $0.3 million for the year ended December 31, 2013. The increase in research and development expenses was primarily due to our acquisition of LS9, which was a research and development stage company primarily focused on microbial fermentation to develop and produce renewable chemicals, fuels and other products.
Other income (expense), net. Other income was $0.6 million for the year ended December 31, 2014 compared to other expense of $2.0 million for the year ended December 31, 2013. Other income 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 $2.6 million was mainly due to the change in the fair value of contingent consideration of $6.6 million, which was offset by an increase in interest expense of $4.3 million, which in turn was driven by higher debt balance in 2014 as compared to 2013.
Income tax expense. There was income tax expense recorded during the year ended December 31, 2014 of $3.6 million, compared to an income tax expense of $4.9 million for the year ended December 31, 2013. At December 31, 2014 and 2013, we had net deferred income tax assets of approximately $114.7 million and $70.5 million, respectively, with a valuation allowance of $136.5 million and $76.9 million, respectively. As a result, our effective tax rate was 4.1% and 2.7% for the years ended December 31, 2014 and 2013, respectively. We have an income tax receivable of $2.8 million and $2.2 million as of December 31, 2014 and 2013, respectively.
Gain on redemption of preferred stock. We recognized a gain of $0.4 million which represents the difference between the carrying amount and the amount we paid to redeem all of the then outstanding Series B Preferred Stock shares in March 2014. There was no redemption gain (loss) on preferred stock in 2013.
Distributed and changes in undistributed dividends. Distributed and undistributed preferred stock dividends were $0.0 million and $2.1 million for the years ended December 31, 2014 and 2013, respectively.
Effects of participating preferred stock. Effects of participating preferred stock was $0.1 million mainly as a result of the redemption of all outstanding Series B Preferred Stock shares in March 2014. The effect was $16.3 million for the year ended December 31, 2013.
Effects of participating share-based awards. Effects of participating restricted stock units was $1.2 million and $2.8 million for the years ended December 31, 2014 and 2013, respectively.
Fiscal years ended December 31, 2013 and December 31, 2012
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:

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Twelve Months Ended
December 31,
 
2013
 
2012
Gallons sold
258.6 million
 
188.4 million
Average B100 price per gallon
$
4.58

 
$
4.60

 
 
 
 
Revenues
 
 
 
Biomass-based diesel
$
1,498,011

 
$
1,014,797

Services
127

 
237

Total
1,498,138

 
1,015,034

Costs of goods sold
 
 
 
Biomass-based diesel
1,258,549

 
956,448

Services
156

 
263

Total
1,258,705

 
956,711

Gross profit
239,433

 
58,323

Selling, general and administrative expenses
45,865

 
42,408

Research and development expense
258

 
14

Income from operations
193,310

 
15,901

Other income (expense), net
(2,009
)
 
7,812

Income tax expense
(4,935
)
 
(1,454
)
Net income attributable to REG
186,366

 
22,259

Effects of recapitalization

 
39,107

Accretion of preferred stock to redemption value

 
(1,808
)
Change in undistributed dividends allocated to preferred stockholders

 
(823
)
Distributed dividends to preferred stockholders
(2,055
)
 
(3,156
)
Effects of participating preferred stock
(16,272
)
 
(8,952
)
Effects of participating share-based awards
(2,785
)
 
(3,145
)
Net income attributable to the Company’s common stockholders
$
165,254

 
$
43,482

Revenues. Our total revenues increased $483.1 million, or 48%, to $1,498.1 million for the year ended December 31, 2013, from $1,015.0 million for the year ended December 31, 2012. This increase was primarily due to an increase in gallons sold and the reinstatement of the biodiesel tax credit that was signed into law on January 2, 2013:
Biomass-based diesel. Biomass-based diesel revenues including government incentives increased $483.2 million, or 48%, to $1,498.0 million during the year ended December 31, 2013, from $1,014.8 million for the year ended December 31, 2012. This increase in biomass-based diesel revenues was due to an increase in gallons sold and $282.1 million increase in biodiesel government incentives from 2012 to 2013. Of these increases, $57.7 million was a net benefit reflecting the retroactive application of the biodiesel tax credit for 2012. The increase in gallons sold reflects increased throughput across our production facilities due to upgrades to our existing facilities and the addition of REG New Boston and REG Mason City. Due to lower RIN and energy prices in 2013, our average B100 sales price per gallon decreased $0.02, or 1%, to $4.58 during the year ended December 31, 2013, compared to $4.60 during the year ended December 31, 2012. The decrease in average sales price from 2012 to 2013 contributed to a $3.8 million revenue decrease when applied to the number of gallons sold during 2012. Gallons sold increased 70.2 million, or 37%, to 258.6 million during the year ended December 31, 2013, compared to 188.4 million during the year ended December 31, 2012. The increase in gallons for the year ended December 31, 2013 accounted for a revenue increase of $322.9 million using 2013 average sales pricing. Sales of separated RIN inventory were $143.5 million and $61.6 million for the years ending December 31, 2013 and 2012, respectively.
Services. Services revenues decreased from the prior year. Service revenues were $0.1 million and $0.2 million for the year ended December 31, 2013 and 2012.
Costs of goods sold. Our costs of goods sold increased $302.0 million, or 32%, to $1,258.7 million for the year ended December 31, 2013, from $956.7 million for the year ended December 31, 2012. Costs of goods sold as a percentage of revenues were 84% and 94% for the years ended December 31, 2013 and 2012, respectively. The decrease in costs of goods

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sold as a percentage of revenues in 2013 was primarily due to higher revenues per gallon from reinstatement of the biodiesel tax credit and lower feed stock costs:
Biodiesel. Biodiesel costs of goods sold increased $302.1 million, or 32%, to $1,258.5 million for the year ended December 31, 2013, compared to $956.4 million for the year ended December 31, 2012. The increase in biodiesel costs of goods sold is primarily the result of the additional gallons sold in the 2013 period partially offset by slightly lower feedstock prices in 2013 as compared to 2012. Average lower cost feedstocks prices for the year ended December 31, 2013 was $0.39 per pound, compared to $0.43 per pound for the year ended December 31, 2012. Soybean oil costs for the year ended December 31, 2013 was $0.45 per pound in comparison to $0.55 per pound for the year ended December 31, 2012. We had losses of $5.7 million from risk management trading activity for the year ended December 31, 2013, compared to losses of $4.6 million from risk management trading for the year ended December 31, 2012, respectively. Biodiesel costs of goods sold as a percentage of revenues were 84% and 94% for the years ended December 31, 2013 and 2012, respectively. The decrease in biodiesel cost of goods sold as a percentage of revenues in 2013 was primarily due to revenues from the reinstated biodiesel tax credit and higher biodiesel prices as well as declining feedstock prices when compared to 2012. In addition, the decrease in the value of RINs during 2013 resulted in a $2.9 million write-down to lower of cost or market on RIN inventory held throughout the year compared to a write-down of $19.6 million during 2012. Costs of goods sold for separated RIN inventory sales were$144.0 million and $83.1 million for the years ending December 31, 2013 and 2012, respectively.
Services. Costs of services decreased $0.1 million to $0.2 million for the year ended December 31, 2013, from $0.3 million for the year ended December 31, 2012.
Selling, general and administrative expenses. Our selling, general and administrative, or SG&A, expenses were $46.1 million for the year ended December 31, 2013, compared to $42.4 million for the year ended December 31, 2012. SG&A expenses increased $3.7 million, or 9%, for the year ended December 31, 2013. We incurred a $1.7 million increase in professional fee expense, a $1.3 million increase in meeting and travel, $0.4 million increase in depreciation expense and an increase of $0.6 million related to computer expenses. This increase was offset by a $0.3 million decrease in the provision for bad debt expense and a decrease of $1.7 million in wages and benefits expense, which is mostly made up of a decrease in non-cash stock compensation expense of $7.7 million and an increase of $4.3 million in expense related to the annual incentive plan based upon achievement of certain operating and financial results for the respective years.
Other income (expense), net. Other expense was $2.0 million for the year ended December 31, 2013 compared to other income of $7.8 million for the year ended December 31, 2012. Other income is primarily comprised of the changes in fair value of the Series A Preferred Stock conversion feature embedded derivative, changes in fair value of Seneca Holdco liability, interest expense, interest income and the other non-operating items. The change in fair value of the Series A Preferred Stock conversion feature embedded derivative resulted in $12.0 million of income for the year ended December 31, 2012. The change in fair value of the Seneca Holdco liability was $0.3 million of revenue for the year ended December 31, 2012. Interest expense decreased $2.3 million to $2.4 million for the year ended December 31, 2013, from $4.7 million for the year ended December 31, 2012. This decrease was primarily attributable to a decrease in in term debt.
Income tax expense. There was income tax expense recorded during the year ended December 31, 2013 of $4.9 million, compared to an income tax expense of $1.5 million for the year ended December 31, 2012. At December 31, 2013 and 2012, we had net deferred income tax assets of approximately $70.5 million and $3.5 million, respectively, with a valuation allowance of $76.9 million and $0 million, respectively, partially offset by an accrued liability of $1.9 million for both periods related to uncertain tax benefits. As a result, our effective tax rate was 2.7% and 6.1% for the years ended December 31, 2013 and 2012, respectively. We have an income tax receivable of $2.2 million and $4.7 million as of December 31, 2013 and 2012, respectively.
Effects of Recapitalization. In January 2012, we completed an initial public offering of our common stock. Due to the IPO, we recorded the effects from recapitalization of $39.1 million. To account for the exchange of Series A Preferred Stock for the newly issued Series B Preferred Stock and common stock, we compared the fair value of the Series B Preferred Stock and common shares issued to the carrying amount of the Series A preferred shares that were redeemed. The excess of the carrying amount of Series A Preferred Stock that were redeemed over the fair value of the Series B Preferred Stock and common stock that was issued was recorded as an increase to additional paid-in capital and was added to net earnings available to common shareholders.
Preferred stock accretion. There was no preferred stock accretion during the year ended December 31, 2013, compared to $1.8 million for the year ended December 31, 2012 associated with the Series A Preferred Stock that was terminated upon completion of the IPO. During January 2012, as part of our IPO and the conversion of the Series A Preferred Stock to Series B Preferred Stock, the accretion of the Series A Preferred Stock was terminated and we determined that no accretion was deemed

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necessary on the newly issued Series B Preferred Stock. See “Note 4 – Redeemable Preferred Stock” in our consolidated financial statements for a description of the transaction.
Change in undistributed dividends. Undistributed preferred stock dividends were $0 million and $0.8 million for the years ended December 31, 2013 and 2012, respectively. During January 2012, the Series A Preferred Stock converted to Series B Preferred Stock as part of our IPO. All previous undistributed dividends were cancelled as part of the conversion. The new Series B Preferred Stock agreement requires us to pay dividends on a semi-annual basis.
Distributed dividends. Distributed preferred stock dividends were $2.1 million and $3.2 million for the years ended December 31, 2013 and 2012, respectively. Based upon the terms of the Series B Preferred Stockholders, we are required to pay dividends to stockholders on a semi-annual basis. The dividends were paid in June and December of 2013 and 2012.
Effects of participating preferred stock. Effects of participating preferred stock was $16.3 and $9.0 million for the years ended December 31, 2013 and 2012, respectively.
Effects of participating share-based awards. Effects of participating restricted stock units was $2.8 and $3.1 million for the years ended December 31, 2013 and 2012, respectively.
Adjusted EBITDA
We use earnings before interest, taxes, depreciation and amortization, adjusted for certain additional items, identified in the table below, or Adjusted EBITDA, as a supplemental performance measure. We present Adjusted EBITDA because we believe it assists 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.
The following table provides our Adjusted EBITDA for the periods presented, as well as a reconciliation to net income:
 
 
 
 
 
 
 
 
 
Year ended
December 31,
 
 
 
 
 
 
 
 
 
Year ended
December 31,
(In thousands)
1Q-2014
 
2Q-2014
 
3Q-2014
 
4Q-2014
 
2014
 
1Q-2013
 
2Q-2013
 
3Q-2013
 
4Q-2013
 
2013
Net income (loss)
$
(2,359
)
 
$
11,007

 
$
4,572

 
$
69,318

 
$
82,538

 
$
46,403

 
$
23,130

 
$
86,703

 
$
30,130

 
$
186,366

Adjustments:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income tax (benefit) expense
(107
)
 
(11,919
)
 
(248
)
 
15,846

 
3,572

 
30,189

 
15,314

 
(42,051
)
 
1,483

 
4,935

Interest expense
551

 
1,204

 
2,867

 
2,068

 
6,690

 
576

 
604

 
577

 
640

 
2,397

Other income (expense), net
(48
)
 
(384
)
 
(124
)
 
(106
)
 
(662
)
 
(117
)
 
(93
)
 
(66
)
 
(112
)
 
(388
)
Change in fair value of contingent consideration

 
(384
)
 
(1,059
)
 
(5,188
)
 
(6,631
)
 

 

 

 

 

Straight-line lease expense
(163
)
 
(150
)
 
(142
)
 
(184
)
 
(639
)
 
(159
)
 
(162
)
 
(163
)
 
(162
)
 
(646
)
Depreciation
3,004

 
3,190

 
3,332

 
5,729

 
15,255

 
2,080

 
2,296

 
2,598

 
2,731

 
9,705

Amortization
(185
)
 
(184
)
 
303

 
(150
)
 
(216
)
 
(199
)
 
(191
)
 
(181
)
 
(181
)
 
(752
)
Other

 

 

 
73

 
73

 
(863
)
 

 

 

 
(863
)
Lease cancellation (1)

 
1,904

 

 

 
1,904

 

 

 

 

 

Biodiesel tax credit (2), (3)
12,778

 
18,550

 
23,887

 
(55,215
)
 

 
(57,372
)
 
(373
)
 

 

 
(57,745
)
Non-cash stock compensation
1,235

 
1,414

 
1,392

 
1,842

 
5,883

 
1,356

 
1,029

 
1,484

 
1,547

 
5,416

Adjusted EBITDA
$
14,706

 
$
24,248

 
$
34,780

 
$
34,033

 
$
107,767

 
$
21,894

 
$
41,554

 
$
48,901

 
$
36,076

 
$
148,425

(1)
In April 2014, we bought out the remaining life of the land lease at our Danville, Illinois facility and subsequently purchased the land. The amount represents the portion related to canceling the lease.
(2)
On January 2, 2013, the American Taxpayer Relief Act of 2012 was signed into law, which reinstated a set of tax extender items including the reinstatement of the federal biodiesel mixture excise tax credit for 2013 and retroactively reinstated the credit for 2012. The retroactive credit for 2012 resulted in a net benefit to us that was recognized in first quarter 2013, but because this credit relates to the operating performance and results of 2012, it is excluded from 2013 adjusted EBITDA and allocated to the 2012 periods based upon gallons sold.

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(3)
On December 19, 2014, the Tax Increase Prevention Act of 2014 was signed into law, which reinstated a set of tax extender items including the retroactive reinstatement of the federal biodiesel mixture excise tax credit for 2014 and expired on December 31, 2014. The retroactive credit for 2014 resulted in a net benefit to us that was recognized in the fourth quarter of 2014, however because this credit relates to the full year operating performance and results, we allocated the first three quarters of 2014, respectively, based upon gallons sold and excluded those amounts from the fourth quarter 2014 adjusted EBITDA.
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 for capital assets 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;
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, 2014 and 2013, the total of our cash and cash equivalents and our marketable securities was $80.3 million and $153.2 million, respectively. At December 31, 2014, we had term debt of $252.9 million, compared to term debt of $34.2 million at December 31, 2013. This term debt is due in various tranches and the maturities are reflected in the contractual obligations table below. We set aside a total of $117.7 million of restricted cash in form of certificates of deposits as collateral for certain term debt and letters of credit. The debt is subject to various financial covenants. We were in compliance with all restrictive financial covenants associated with the borrowings as of December 31, 2014.
Our term debt (in millions) is as follows:
 
December 31,
 
2014
 
2013
Convertible debt
$
121.4

 
$

REG Geismar GOZone bonds
100.0

 

REG Danville term loan
1.5

 
5.6

REG Newton term loan
19.9

 
18.1

REG Mason City term loan
4.6

 
5.1

REG Ames term loans
4.2

 

Other
1.3

 
1.4

Total term debt
$
252.9

 
$
30.2

Bell, LLC promissory note
$

 
$
4.0

In addition, we had revolving debt (in millions) as follows:
 
December 31,
 
2014
 
2013
Total revolving loans (current)
$
16.7

 
$
11.0

Maximum available to be borrowed under revolving line of credit
20.7

 
29.0


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Wells Fargo Revolving Letter of Credit
We currently have a revolving credit agreement with the lenders thereto and Wells Fargo Capital Finance, LLC, as agent, which we refer to as the Wells Fargo Revolver. The Wells Fargo Revolver provides for the extension of revolving loans in an aggregate principal amount not to exceed $40.0 million, based on eligible inventory, accounts receivable, biodiesel credits of the subsidiary borrowers and the inventory of certain affiliates. As of December 31, 2014, our available borrowing capacity under the Wells Fargo Revolver was $37.4 million of which $16.7 million was outstanding, leaving $20.7 million in availability. The Wells Fargo Revolver has a stated maturity date of December 23, 2016.
Amounts borrowed under the Wells Fargo Revolver bear interest, in the case of LIBOR rate loans, at a per annum rate equal to the LIBOR rate plus the LIBOR Rate Margin (as defined), which may range from 2.50 to 4.00 percent, based on the Quantity Average Excess Availability Amount (as defined). The LIBOR Rate Margin is subject to reduction or increase depending on the amount available for borrowing under the new revolving credit agreement.
The Wells Fargo 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, 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 (as defined in the Wells Fargo Revolver) of at least 1.0 to 1.0 and to have Excess Availability (as defined in the Wells Fargo Revolver) of at least $4 million. The Wells Fargo Revolver is secured by the subsidiary borrowers’ membership interests and substantially all of their assets, and the inventory of REG Albert Lea, LLC, REG Houston, LLC, and REG New Boston, LLC, subject to a $25 million limitation.
Convertible debt
In June 2014, the Company issued $143.8 million in convertible senior notes (Convertible Notes) with a maturity date of June 15, 2019, unless earlier converted or repurchased. The 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 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 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 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 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 Convertible Notes, holders may convert their 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 Company’s election. The Company's current intent is to settle the principal amount of the Senior 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 Convertible Notes are not redeemable at the Company’s option prior to maturity.
In connection with the issuance of the Convertible Notes, the Company entered into capped call transactions (Capped Call) in private transactions. Under the Capped Call, the Company purchased capped call options that in aggregate relate to 92.5% of the total number of shares of the Company's Common Stock underlying the Convertible Notes, with a strike price equal to the conversion price of the Convertible Notes and with a cap price equal to $16.02 per share. The capped calls were purchased for $11.9 million and recorded as a reduction to common stock-additional paid-in-capital.
The purchased Capped Call allows the Company to receive shares of its Common Stock and/or cash from counterparties equal to the amounts of Common Stock and/or cash related to the excess of the market price per share of the Common Stock, as measured under the terms of the Capped Call over the strike price of the Capped Call during the relevant valuation period. The purchased Capped Call is intended to reduce the potential dilution to Common Stock upon future conversion of the Convertible Notes by effectively increasing the initial conversion price to $16.02 as well as to offset potential cash payments the Company is required to make in excess of the principal amount of the Convertible Notes in applicable events.

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GOZone bonds
In June 2014, we acquired Dynamic Fuels, subsequently renamed REG Geismar, LLC. REG Geismar is obligated with respect to $100.0 million aggregate principal amount of Gulf Opportunity Zone tax-exempt bonds, or GOZone Bonds, due in October 2033, through a loan agreement with the Louisiana Public Facilities Authority.
At the time that the GOZone Bonds were originally issued, Tyson Foods, one of the former equityholders of Dynamic Fuels, obtained an irrevocable direct-pay letter of credit, or the Old Letter of Credit, from a financial institution which was provided to the trustee for the GOZone Bonds and drawn upon to pay the principal of and interest on the GOZone Bonds and the portion of the purchase price attributable to principal of and interest on the GOZone Bonds in connection with any GOZone Bond repurchase obligations. At the closing of the acquisition of Dynamic Fuels in June 2014, we entered into a reimbursement agreement with Tyson Foods whereby we agreed to reimburse Tyson Foods for any amounts payable by Tyson Foods in the event of a draw on the Old Letter of Credit. We deposited $101.3 million into an escrow account for the benefit of Tyson Foods in connection with this reimbursement agreement, which represented the full amount of Tyson Foods’ obligation under the Old Letter of Credit and is held as non-current restricted cash on the Consolidated Balance Sheets.
On July 8, 2014, REG Geismar and Bank of America, N.A. entered into a Reimbursement Agreement, dated as of the same date, or Reimbursement Agreement, and Bank of America issued a letter of credit, or Substitute Letter of Credit, to the trustee for the GOZone Bonds in substitution for the Old Letter of Credit and our reimbursement arrangement with Tyson Foods was terminated. The Substitute Letter of Credit is in the stated amount of $101.3 million, which represents the sum of the outstanding $100.0 million principal amount of the GOZone Bonds plus $1.3 million of interest. The Substitute Letter of Credit expires on July 8, 2015. In the event that the expiration date of the Substitute Letter of Credit is not extended or a new letter of credit is not issued in substitution for the Substitute Letter of Credit, holders of the GOZone Bonds are required to tender their GOZone Bonds for repurchase and the trustee for the GOZone Bonds is required pursuant to the terms of the indenture governing the GOZone Bonds to draw down the Substitute Letter of Credit to fund the repurchase of the GOZone Bonds. The Substitute Letter of Credit requires that the GOZone Bonds remain in the daily or weekly interest rate mode.
Pursuant to the Reimbursement Agreement, REG Geismar must reimburse Bank of America for any and all draws on the Substitute Letter of Credit. It is an event of default under the Reimbursement Agreement if REG Geismar fails to make any payment required under the Reimbursement Agreement when due, fails to comply with its obligations under the financing agreements related to the GOZone Bonds, including the Loan Agreement, or breaches certain representations, warranties or covenants in the Reimbursement Agreement (including the failure to cause the cash collateral described above to be maintained) and in the case of certain bankruptcy events involving REG Geismar. An event of default under the Reimbursement Agreement would also result in an event of default under the indenture governing the Bonds, which would cause the trustee for the GOZone Bonds to accelerate payment of the GOZone Bonds and draw down on the Substitute Letter of Credit. REG Geismar would be liable for all reimbursement obligations in connection with such a draw under the Reimbursement Agreement.
REG Geismar’s repayment obligations under the Reimbursement Agreement are secured by a $101.3 million certificate of deposit established by REG Capital, another wholly-owned subsidiary of ours, which was pledged by REG Capital to Bank of America. REG Geismar’s obligations under the Reimbursement Agreement are not guaranteed by us or any of our affiliates.
To fund the $101.3 million security deposit related to the GOZone Bonds, in June 2014, we issued $143.8 million aggregate principal amount of 2.75% convertible senior notes as discussed above. The estimated net proceeds to us from the issuance of the Convertible Notes, after deductible underwriting fees and related expenses, were approximately $138.6 million.
REG Danville, LLC
On November 3, 2011, REG Danville, LLC entered into an Amended and Restated Loan Agreement with Fifth Third Bank, or the Fifth Third Loan. The renewed Fifth Third Loan had a three year term with an automatic one year extension upon certain cumulative principal payment thresholds being met. The maturity of the loan was extended to November 2015 based on REG Danville meeting certain principal payment requirements. The loan requires monthly principal payments of $150,000 and interest to be charged using LIBOR plus 5% per annum. The Fifth Third Loan is secured by our Danville facility. The loan agreement contains various loan covenants that restrict REG Danville’s ability to take certain actions, including prohibiting it in certain circumstances from making payments to us. The covenants were subsequently amended to include changes upon us executing a tax sharing agreement with REG Danville. Beginning on December 31, 2011, we are required to make semi-annual principal payments in an amount equal to 50% of REG Danville's Excess Cash Flow. The Fifth Third Loan agreement defines Excess Cash Flow as REG Danville’s EBITDA plus certain affiliate payments less principal payments, interest expense, taxes and unfunded maintenance capital expenditures. The Excess Cash Flow payment for December 31, 2014 and 2013 was $2.3

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million and $1.4 million, respectively. As of December 31, 2014, there was $1.5 million outstanding under the Fifth Third Loan.
REG Newton, LLC
On March 8, 2010, in connection with the CIE Asset Acquisition, one of our subsidiaries, REG Newton, refinanced a $23.6 million term loan, or the AgStar Loan, and obtained a $2.4 million line of credit, or the AgStar Line, with AgStar Financial Service, PCA, or AgStar. This amount is secured by our Newton facility. The AgStar Loan bears interest at 3% plus the greater of (i) LIBOR or (ii) 2%. Beginning on October 1, 2011, monthly principal payments of approximately $0.12 million and accrued interest was due based on a 12-year amortization period.
On December 4, 2013, REG Newton, LLC entered into an Amended and Restated Master Loan Agreement, effective December 1, 2013, with AgStar Financial Services, PCA (AgStar) which replaced the existing Master Loan Agreement, dated March 8, 2010. The Amended and Restated Agreement extends the maturity of the existing term loan by five years until December 1, 2018 and increases the term loan by $5.0 million. The REG Newton term debt is secured by all plant assets owned by REG Newton. Interest is to be accrued based on 30-day LIBOR plus 400 basis points. REG Newton is required to make principal and interest payments of approximately $0.3 million. The loan agreement requires REG Newton to make an annual payment equal to 50% of its Excess Cash Flow calculated based upon the prior year’s audited financial statements within 120 days of the fiscal year end. The AgStar Loan agreement defines Excess Cash Flow as EBITDA, less the sum of required debt payments, interest expense, up to $0.5 million in maintenance capital expenditure and allowed distributions. The required excess cash flow payments for 2014 and 2013 were $0.5 million and $0, respectively. As of December 31, 2014, there was $19.9 million of principal outstanding under the term loan.
REG Mason City, LLC
On July 30, 2013, REG Mason City entered into an agreement with Soy Energy, or Soy Energy Loan. The Soy Energy Loan has a six-year term and is secured by our Mason City facility. The loan requires interest only payments for the first eight months and monthly principal and interest payments of approximately $0.1 million starting in April 2014. Interest is based on a fixed rate of 5%. The loan agreement contains a covenant that restricts REG Mason City's ability to take certain actions, including prohibiting it in certain circumstances from making payments to us. The Soy Energy Loan requires annual excess cash flow payments beginning on December 31, 2013. REG Mason City must pay Soy Energy a principal payment in the amount equal to 50% of its excess cash flow. There was no required excess cash flow payments for 2014. As of December 31, 2014, the balance on the loan was $4.6 million.
Cash flow. The following table presents information regarding our cash flows and cash and cash equivalents for the years ended December 31, 2014, 2013 and 2012:
 
Year Ended
December 31,
 
2014
 
2013
 
2012
 
 
 
(in thousands)
 
 
Net cash flows provided from operating activities
$
32,528

 
$
139,645

 
$
44,619

Net cash flows used in investing activities
(217,033
)
 
(54,389
)
 
(14,546
)
Net cash flows provided from financing activities
94,794

 
1,186

 
3,137

Net change in cash and cash equivalents
(89,711
)
 
86,442

 
33,210

Cash and cash equivalents, end of period
$
63,516

 
$
153,227

 
$
66,785

The historical cash flows shown above highlight that we have been able to consistently generate positive cash flows from operations. The large operating cash inflow for 2013 was primarily attributable to the refresh of the biodiesel tax credit that not only touched on 2013 operations but also allowed us to recoup certain amounts from 2012. The absence of the credit until late 2014 has led to the decrease in operating cash flows. Our investing activity has been focused in two different directions in the previous years; first, expenditures were made to purchase new businesses and capacity; second, expenditures were made to further develop existing plant assets. Financing activities have moved hand in hand with our investing activities as it is our general intention to use separate debt and equity raise transactions to finance the purchase of assets and businesses. 2013 financing activities also included our initial public offering whose proceeds were used for working capital, capital expenditures related to improvements of production processes and logistics, and acquisitions of the Seneca facility.
Capital expenditures. We have three partially constructed plants, one near New Orleans, Louisiana, one in Emporia, Kansas, one in Clovis, New Mexico and a non-operational plant near Atlanta, Georgia. We expect additional investments of

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approximately $165 to $180 million in the aggregate, excluding working capital requirements, would be required before these plants would be able to commence production. These facilities would add an expected 150 mmgy to our nameplate production capacity. Our Clovis plant is currently being operated as a terminal facility. We plan to make significant capital expenditures when debt or equity financing becomes available to complete construction of these four facilities.
During 2014, we completed a $20 million upgrade at our Mason City facility and a $13 million upgrade to our Newton facility. In 2013, we completed upgrades to our Albert Lea facility, our New Boston facility, our Mason City facility and our Seneca facility. Capital expenditures related to these facility upgrades were approximately $22 million, $4 million and $1 million and $5 million, respectively, in 2013. We plan to undertake various upgrades at our existing facilities to further expand processing capabilities, which may include an estimated $15 million at our Geismar facility. We may enter into additional tolling arrangements with third parties from time to time where third parties will produce biomass-based diesel on our behalf using our feedstocks. Such arrangements may require investments of additional working capital during the tolling periods.
We continue to be in discussions with lenders in an effort to enter into equity and debt financing arrangements to meet our projected financial needs for facilities under construction and capital improvement projects for our operating facilities. Since these discussions are ongoing, we are uncertain when or if financing will be available. The financing may consist of common or preferred stock, debt, project financing or a combination of these financing techniques. Additional debt would increase our leverage and interest costs and would likely be secured by certain of our assets. Additional equity or equity-linked financings would likely have a dilutive effect on our existing and future stockholders. It is likely that the terms of any project financing would include customary financial and other covenants on our project subsidiaries, including restrictions on the ability to make distributions, to guarantee indebtedness and to incur liens on the plants of such subsidiaries.
Contractual Obligations:
The following table describes our commitments to settle contractual obligations in cash as of December 31, 2014:
 
Payments Due by Period
 
Total
 
Less Than
1 Year
 
Years 1-3
 
Years
4-5
 
More Than
5 Years
 
(In thousands)
Long Term Debt (1)
$
252,929

 
$
5,746

 
$
8,947

 
$
138,236

 
$
100,000

Contingent Considerations (2)
39,319

 
9,228

 
24,914

 
5,177

 

Operating Lease Obligations (3)
120,239

 
16,845

 
37,437

 
19,624

 
46,333

Purchase Obligations (4)
34,947

 
3,857

 
7,714

 
7,532

 
15,844

Other Obligations (5)
11,781

 

 

 

 

 
$
459,215

 
$
35,676

 
$
79,012

 
$
170,569

 
$
162,177

(1)
See Note 12 of Item 8 for additional detail. Includes fixed interest associated with these obligations.
(2)
Represents contingent considerations relating to our acquisitions of LS9 and Syntroleum/Dynamic Fuels. See Note 5 of Item 8 for additional detail.
(3)
Operating lease obligations consist of terminals, rail cars, vehicles and ground leases.
(4)
Purchase obligations for our production facilities and partially completed facilities.
(5)
Includes commitments, incentive compliance and other facility obligations. Represents $1.9 million of liability for unrecognized tax benefits as the timing and amounts of cash payments are uncertain (the amounts have not been classified by period) and a maximum $9.9 million open commitments for the tender offer to acquire the remaining interest at Petrotec.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Recent Accounting Pronouncements
For a discussion of new accounting pronouncements affecting us, refer to “Note 2 – Summary of Significant Accounting Policies” to our consolidated financial statements.
ITEM 7A.
Quantitative and Qualitative Disclosures about Market Risk
The primary objectives of our investment activity are to preserve principal, provide liquidity and maximize income without significantly increasing risk. Some of the securities we invest in are subject to market risk. This means that a change in

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prevailing interest rates may cause the principal amount of the investment to fluctuate. To minimize this risk, we maintain a portfolio of cash equivalents in short-term investments in money market funds.
Commodity Price Risk
Over the period from January 2010 through December 2014, average diesel prices based on Platts reported pricing for Group 3 (Midwest) have ranged from a high of approximately $5.40 per gallon reported in June 2011 to a low of approximately $2.82 per gallon in December 2014, with prices averaging $4.21 per gallon during this period. Over the period January 2010 to December 2014, soybean oil prices (based on daily closing nearby futures prices on the CBOT for crude soybean oil) have ranged from a high of $0.5977 per pound, or $4.60 per gallon of biodiesel in April 2011 to a low of $0.3117 per pound, or $2.40 per gallon in December 2014 assuming 7.7 pounds of soybean oil yields one gallon of biodiesel with closing sales prices averaging $0.4644 per pound or $3.58 per gallon. Over the period from January 2010 through December 2014, animal fat prices (based on prices from The Jacobsen Missouri River, for choice white grease) have ranged from a high of $0.5450 per pound in June 2011 to a low of $0.2250 per pound in January 2014, with sales prices averaging $0.3730 per pound during this period. Over the period from July 2010 through December 2014, RIN prices (based on prices from OPIS) have ranged from a high of $1.99 in September 2011 to a low of $0.24 in November 2013, with sales prices averaging $0.88 during this period.
Lower biomass-based diesel prices and lower feedstock prices but at a disproportionate decreasing rate as compared to biomass-based diesel prices result in lower profit margins and, therefore, represent unfavorable market conditions. The availability and price of feedstocks are subject to wide fluctuations due to unpredictable factors such as weather conditions during the growing season, rendering volumes, carry-over from the previous crop year and current crop year yield, governmental policies with respect to agriculture and supply and demand.
We have prepared a sensitivity analysis to estimate our exposure to market risk with respect to our sales contracts, lower cost feedstock requirements, soybean oil requirements and the related exchange-traded contracts for 2014. Market risk is estimated as the potential loss in fair value, resulting from a hypothetical 10% adverse change in the fair value of our lower cost feedstock and soybean oil requirements and biomass-based diesel sales. The results of this analysis, which may differ from actual results, are as follows:
 
2014
Volume
(in millions)
 
Units
 
Hypothetical
Adverse
Change in
Price
 
Impact on Annual
Gross
Profit (in
millions)
 
Percentage
Change in
Gross
Profit
Biomass-based diesel
287.3

 
gallons
 
10
%
 
$
98.3

 
(60.8
)%
Lower Cost Feedstocks
1,679.7

 
pounds
 
10
%
 
$
56.1

 
(34.7
)%
Soybean Oil
303.0

 
pounds
 
10
%
 
$
11.6

 
(7.2
)%
We attempt to protect operating margins by entering into risk management contracts that mitigate price volatility of our feedstocks, such as inedible animal fat and inedible corn oil and energy prices. We create offsetting positions by using a combination of forward physical purchases and sales contracts on feedstock and biomass-based diesel, including risk management futures contracts, swaps and options primarily on heating oil and 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. A 10% adverse change in the prices of heating oil would have a negative effect on the fair value of these instruments of $6.7 million. A 10% adverse change in the price of soybean oil would have a negative effect on the fair value of these instruments of $0.5 million.
Interest Rate Risk
We are subject to interest rate risk in connection with our $0.7 million loan from the proceeds of Variable Rate Demand Industrial Development Revenue Bonds, or IFA Bonds, issued by the Iowa Finance Authority to finance our Ralston facility. The IFA Bonds bear interest at a variable rate determined by the remarketing agent from time to time as the rate necessary to produce a bid for the purchase of all of the Bonds at a price equal to the principal amount thereof plus any accrued interest at the time of determination, but not in excess of 10% per annum. The interest rate on the bonds was 0.08% for the last week of December 2014.
REG Newton is subject to interest rate risk relating to its $19.9 million term debt financing from AgStar. Interest will accrue on the outstanding balance of the term loan at 30-day LIBOR plus 400 basis points (effective rate at December 31, 2014 of 4.16%).

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We are subject to interest risk relating to the $100.0 million GOZone bonds, which bears interest at variable rates. The interest rate on the bonds was 0.02% for the last week of December 2014.
We are subject to interest rate risk under our Wells Fargo Revolver entered into on December 23, 2011 under which we had $16.7 million borrowed and outstanding at December 31, 2014. Amounts borrowed under the Wells Fargo Revolver bear interest, in the case of LIBOR rate loans, at a per annum rate equal to the LIBOR rate plus the LIBOR Rate Margin (as defined in the Wells Fargo Revolver), which may range from 2.50 to 4.00 percent, based on the Quantity Average Excess Availability Amount (as defined in the Wells Fargo Revolver). All other amounts borrowed that are not LIBOR rate loans bear interest at a rate equal to the greatest of (i) (A) 1.75% per annum, (B) the Federal Funds Rate plus 0.5%, (C) the LIBOR Rate (which rate shall be calculated based upon an interest period of three months and will be determined on a daily basis), plus 1.5% points, and (D) the rate of interest announced, from time to time, within Wells Fargo Bank, National Association at its principal office in San Francisco as its “prime rate,” plus (ii) the Base Rate Margin (as defined in the Wells Fargo Revolver), which may range from 1.00 to 1.75 percent, based on the Quantity Average Excess Availability Amount. The Base Rate Margin is subject to reduction or increase depending on the amount available for borrowing under the Wells Fargo Revolver. The loan was a base rate loan as of December 31, 2014 (effective rate at December 31, 2014 of 4.00%).
Our weighted average interest rate on variable rate debt balances during 2014 was 1.15% and a hypothetical increase in interest rate of 10% would not have a material effect on our annual interest expenses and consolidated financial statements.
Inflation
To date, inflation has not significantly affected our operating results, though costs for petroleum-based diesel fuel, feedstocks, construction, labor, taxes, repairs, maintenance and insurance are all subject to inflationary pressures. Inflationary pressure in the future could affect our ability to sell the biomass-based diesel we produce, maintain our production facilities adequately, build new biomass-based diesel production facilities and expand our existing facilities as well as the demand for our facility construction management and operations management services.

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ITEM 8.
Financial Statements and Supplementary Data
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Renewable Energy Group, Inc.
Ames, Iowa

We have audited the accompanying consolidated balance sheets of Renewable Energy Group, Inc. and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), redeemable preferred stock and equity, and cash flows for each of the three years in the period ended December 31, 2014. We also have audited the Company's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment the internal control over financial reporting at Petrotec, which was acquired on December 24, 2014, and whose financial statements constitute 4% of total assets and less than 1% of total revenues of the consolidated financial statement amounts as of and for the year ended December 31, 2014. Accordingly, our audit did not include the internal control over financial reporting at Petrotec. The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company's internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Renewable Energy Group, Inc. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ Deloitte & Touche LLP

Des Moines, Iowa
March 6, 2015


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RENEWABLE ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2014 AND 2013
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
 
2014
 
2013
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
63,516

 
$
153,227

Marketable securities
16,770

 

Accounts receivable, net (includes amounts owed by related parties of $36 and $426, respectively)
294,669

 
82,911

Inventories
97,508

 
85,814

Prepaid expenses and other assets
43,135

 
25,568

Restricted cash
12,845

 

Total current assets
528,443

 
347,520

Property, plant and equipment, net
493,196

 
286,044

Property, plant and equipment, net—variable interest entity

 
5,180

Goodwill
188,275

 
84,864

Intangible assets, net
28,837

 
4,867

Investments
9,736

 
7,351

Other assets (includes amounts owed by related party of $0 and $35, respectively)
19,586

 
5,029

Restricted cash
104,815

 

TOTAL ASSETS
$
1,372,888

 
$
740,855

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Revolving line of credit
$
16,679

 
$
10,986

Current maturities of long-term debt
5,746

 
6,729

Current maturities of long-term debt—variable interest entity

 
300

Accounts payable (includes amounts owed to related parties of $1,101 and $552, respectively)
202,821

 
48,727

Accrued expenses and other liabilities
28,486

 
12,305

Deferred income taxes
14,899

 
3,687

Deferred revenue
16,680

 
15,503

Total current liabilities
285,311

 
98,237

Unfavorable lease obligation
19,170

 
7,905

Deferred income taxes
6,905

 
2,691

Contingent consideration for acquisitions
30,091

 

Long-term debt
247,183

 
23,422

Long-term debt—variable interest entity

 
3,729

Other liabilities
5,566

 
6,838

Total liabilities
594,226

 
142,822

COMMITMENTS AND CONTINGENCIES (NOTE 21)

 

Series B Preferred Stock ($.0001 par value; 3,000,000 shares authorized; 0 and 143,313 shares outstanding, redemption amount $0 and $3,583, respectively)

 
3,963

EQUITY:
 
 
 
Common stock ($.0001 par value; 300,000,000 shares authorized; 44,422,881 and 36,506,221 shares outstanding, respectively)
4

 
4

Common stock—additional paid-in-capital
453,109

 
359,818

Retained earnings
321,083

 
238,134

Accumulated other comprehensive loss
(11
)
 

Treasury stock (585,150 and 530,898 shares, respectively)
(4,412
)
 
(3,886
)
Total equity attributable to the Company's shareholders
769,773

 
594,070

Noncontrolling interest
8,889

 

Total equity
778,662

 
594,070

TOTAL LIABILITIES AND EQUITY
$
1,372,888

 
$
740,855

See notes to consolidated financial statements.

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Table of Contents

RENEWABLE ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 2014, 2013 AND 2012
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
 
2014
 
2013
 
2012
REVENUES:
 
 
 
 
 
Biomass-based diesel sales
$
1,052,772

 
$
1,207,618

 
$
1,006,465

Biomass-based diesel sales—related parties

 

 
6

Biomass-based diesel government incentives
220,634

 
290,393

 
8,326

 
1,273,406

 
1,498,011

 
1,014,797

Services
425

 
127

 
237

 
1,273,831

 
1,498,138

 
1,015,034

COSTS OF GOODS SOLD:
 
 
 
 
 
Biomass-based diesel
1,070,430

 
1,209,191

 
902,084

Biomass-based diesel—related parties
42,622

 
49,358

 
54,364

Services
167

 
156

 
263

 
1,113,219

 
1,258,705

 
956,711

GROSS PROFIT
160,612

 
239,433

 
58,323

SELLING, GENERAL, AND ADMINISTRATIVE EXPENSES (includes related party amounts of $45, $37, and $158, respectively)
62,681

 
45,865

 
42,408

RESEARCH AND DEVELOPMENT EXPENSE
12,424

 
258

 
14

INCOME FROM OPERATIONS
85,507

 
193,310

 
15,901

OTHER INCOME (EXPENSE), NET:
 
 
 
 
 
Change in fair value of contingent consideration
6,631

 

 

Change in fair value of preferred stock conversion feature embedded derivatives

 

 
11,975

Other income
662

 
388

 
516

Interest expense (includes related party amounts of $7, $30, and $32, respectively)
(6,690
)
 
(2,397
)
 
(4,679
)
 
603

 
(2,009
)
 
7,812

INCOME BEFORE INCOME TAXES
86,110

 
191,301

 
23,713

INCOME TAX EXPENSE
(3,572
)
 
(4,935
)
 
(1,454
)
NET INCOME
82,538

 
186,366

 
22,259

LESS—NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST
(73
)
 

 

NET INCOME ATTRIBUTABLE TO THE COMPANY
82,611

 
186,366

 
22,259

EFFECTS OF RECAPITALIZATION
R