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EX-32 - EX-32 - Advanced BioEnergy, LLCck0001325740-ex32_11.htm
EX-31.2 - EX-31.2 - Advanced BioEnergy, LLCck0001325740-ex312_8.htm
EX-31.1 - EX-31.1 - Advanced BioEnergy, LLCck0001325740-ex311_6.htm
EX-24 - EX-24 - Advanced BioEnergy, LLCck0001325740-ex24_10.htm
EX-21 - EX-21 - Advanced BioEnergy, LLCck0001325740-ex21_7.htm
EX-10.11 - EX-10.11 FOURTH AMENDMENT - Advanced BioEnergy, LLCck0001325740-ex1011_42.htm
EX-10.10 - EX-10.10 THIRD AMENDMENT - Advanced BioEnergy, LLCck0001325740-ex1010_43.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

Form 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2018

Commission file number: 000-52421

 

ADVANCED BIOENERGY, LLC

(Exact name of Registrant as Specified in its Charter)

 

 

Delaware

20-2281511

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification No.)

 

8000 Norman Center Drive, Suite 610

Bloomington, MN 55437

(763) 226-2701

(Address, including zip code, and telephone number,

Including area code, of Registrant’s Principal Executive Offices)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Membership Units

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes      No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.    Yes      No  

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.)    Yes      No  

Indicate by check mark 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

Accelerated filer

 

 

 

 

Non-accelerated filer

  

Smaller reporting company

 

 

 

 

Emerging growth company

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

Our membership units are not publicly traded; therefore, our public float is not measurable.

As of December 1, 2018, the number of outstanding membership units was 25,410,851.

Portions of the registrant’s definitive Proxy Statement for the registrant’s 2019 Annual Meeting of Members are incorporated by reference into Part III.

 

 


ADVANCED BIOENERGY, LLC

FORM 10-K FOR THE FISCAL YEAR ENDED SEPTEMBER 30, 2018

INDEX

 

 

 

 

Page

PART I

 

 

 

Item 1.

Business

 

5

Item 1A.

Risk Factors

 

10

Item 2.

Properties

 

21

Item 3.

Legal Proceedings

 

21

Item 4.

Mine Safety Disclosures

 

22

 

 

 

 

PART II

 

 

 

Item 5.

Market for Registrant’s Common Equity, Related Unit holder Matters and Issuer Purchases of Equity Securities

 

23

Item 6.

Selected Financial Data

 

25

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

26

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

 

36

Item 8.

Financial Statements and Supplementary Data

 

37

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

58

Item 9A.

Controls and Procedures

 

58

Item 9B.

Other Information

 

58

 

 

 

 

PART III

 

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

 

59

Item 11.

Executive Compensation

 

59

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Unit holder Matters

 

59

Item 13.

Certain Relationships and Related Transactions, and Director Independence

 

59

Item 14.

Principal Accountant Fees and Services

 

59

 

 

 

 

PART IV

 

 

 

Item 15.

Exhibits and Financial Statement Schedules

 

60

Item 16

Form 10-K Summary

 

63

SIGNATURES

 

64

 

 

 

2


SPECIAL NOTE REGARDING FORWARD-LOOKING INFORMATION

This Annual Report on Form 10-K contains forward-looking statements regarding our business, financial condition, results of operations, performance and prospects. All statements that are not historical or current facts are forward-looking statements and are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve known and unknown risks, uncertainties and other factors, many of which may be beyond our control and may cause our actual results, performance or achievements to be materially different from any future results, performances or achievements expressed or implied by the forward-looking statements. Certain of these risks and uncertainties are described in the “Risk Factors” section of this Annual Report on Form 10-K. These risks and uncertainties include, but are not limited to, the following:

 

our operational results are subject to fluctuations in the prices of grain, utilities and ethanol, which are affected by various factors including weather, production levels, supply, demand, changes in technology and government support and regulations;

 

our margins have fluctuated in the past and could again become negative, which may affect our ability to meet current obligations, service our debt and satisfy financial covenants of our credit agreement with AgCountry;

 

our dependence on third parties for the marketing and sale of our ethanol and co-products;

 

our current dependence on Agtegra Cooperative for the corn we need to produce ethanol;

 

our ability to successfully construct and operate a new grain receiving and storage facility at our Aberdeen, South Dakota plant;

 

our risk mitigation strategies could be unsuccessful and could materially harm our results;

 

our cash distributions to unit holders depend upon our future financial and operational performance and will be affected by debt covenants, reserves and operating expenditures;

 

ethanol may trade at a premium to gasoline at times, causing a disincentive for discretionary blending of ethanol beyond the rates required to comply with the RFS (as defined below). This may have a negative impact on ethanol pricing and demand;

 

current government mandated standards such as the RFS may be reduced or eliminated, and legislative acts taken by state governments such as California related to low-carbon fuels that include the effects of indirect land use, may have an adverse effect on our business;

 

alternative fuel additives may be developed that are superior to, or cheaper than ethanol;

 

transportation, storage and blending infrastructure may become impaired, preventing ethanol from reaching markets;

 

our operating facilities may experience technical difficulties and not produce the gallons of ethanol expected;

 

our units are subject to a number of transfer restrictions, and although our units are now listed on an internet-based matching platform, we cannot ensure that a market will ever develop for our units;

 

the ability of our ABE South Dakota subsidiary to make distributions to ABE in light of restrictions in this subsidiary’s credit facility;

 

anti-dumping and countervailing duties investigations by the Chinese government into U.S. distillers grains exported to China could result in reduced export demand for distillers grains and have a negative impact on domestic distillers grain prices;

 

the ethanol tariff imposed by the Chinese government rose from 5 to 45 percent in 2018, and as of December 2018 remained at 45 percent; this higher tariff could result in reduced export demand for ethanol and have a negative impact on domestic ethanol prices;

 

in late August 2017, the Brazilian government imposed a tariff of 20 percent on U.S. ethanol imports. The tariff applies to imports after an initial tax-free quota of 600 million liters, or 158.5 million gallons, per year. This tariff remains in effect as of December 2018.  The tariff could result in reduced export demand for United States ethanol and have a negative impact on domestic ethanol prices;

 

the supply of ethanol rail cars in the market has fluctuated in recent years and may affect our ability to obtain new tanker cars or negotiate new leases at a reasonable fee when our current leases expire; and

 

an increase in rail traffic congestion throughout the United States primarily due to the increase in cargo trains carrying shale oil, which, from time to time, has and may continue to affect our ability to return our tanker rail cars to the Aberdeen

3


 

and Huron plants on a timely basis. Delays in returning rail cars to our plants may affect our ability to operate our plants at full capacity due to our ethanol storage capacity constraints.

You can identify forward-looking statements by terms such as “anticipates,” “believes,” “could,” “estimates,” “expects,” “intends,” “may,” “plans,” “potential,” “predicts,” “projects,” “should,” “will,” “would,” and similar expressions intended to identify forward-looking statements. Forward-looking statements reflect our current views with respect to future events, are based on assumptions, and are subject to risks and uncertainties. Given these uncertainties, you should not place undue reliance on these forward-looking statements. Also, forward-looking statements represent our estimates and assumptions only as of the date of this report. Except as required by law, we assume no obligation to update any forward-looking statements publicly, or to update the reasons actual results could differ materially from those anticipated in any forward-looking statements, even if new information becomes available in the future. Readers are urged to carefully review and consider the various disclosures made by us in this report and in our other reports filed from time to time with the U.S. Securities and Exchange Commission, which we refer to as the SEC, that advise interested parties of the risks and factors that may affect our business.

INTELLECTUAL PROPERTY

Advanced BioEnergyTM, our logos and the other trademarks, trade names and service marks of Advanced BioEnergy mentioned in this report are our property. This report also contains trademarks and service marks belonging to other entities.

INDUSTRY AND MARKET DATA

We obtained the industry, market and competitive position data used throughout this report from our own research, studies conducted by third parties, independent industry associations, governmental associations or general publications and other publicly available information. In particular, we have based much of our discussion of the ethanol industry, including government regulation relevant to the industry and forecasted growth in demand, on information published by the Renewable Fuels Association (“RFA”) and Growth Energy, the national trade associations for the U.S. ethanol industry. Because the RFA and Growth Energy are trade organizations for the ethanol industry, they may present information in a manner that is more favorable to that industry than would be presented by an independent source. Although we believe these sources are reliable, we have not independently verified the information. Forecasts are particularly likely to be inaccurate, especially over long periods of time.

ETHANOL UNITS

All references in this report to gallons of ethanol are to gallons of denatured ethanol. Denatured ethanol is ethanol blended with 2.0% to 2.5% denaturant, such as gasoline, to render it undrinkable and thus not subject to alcoholic beverage taxes.

 

 

4


PART I

ITEM 1.

BUSINESS

COMPANY OVERVIEW

Advanced BioEnergy, LLC (“Company,” “we,” “our,” “Advanced BioEnergy” or “ABE”) was formed in 2005 as a Delaware limited liability company. Our business consists of producing ethanol and co-products, including wet, modified and dried distillers’ grains, and corn oil. Ethanol is a renewable, environmentally clean fuel source that is produced at numerous facilities in the United States, mostly in the Midwest. In the U.S., ethanol is produced primarily from corn and then blended with unleaded gasoline in varying percentages. The ethanol industry in the U.S. has grown significantly as the use of ethanol reduces harmful auto emissions, enhances octane ratings of the gasoline with which it is blended, offers consumers a cost-effective choice, and decreases the amount of crude oil the U.S. needs to import from foreign sources.

To execute our business plan, in November 2006, we acquired ABE South Dakota, LLC (f/k/a Heartland Grain Fuels, LP), which owned existing ethanol production facilities in Aberdeen and Huron, South Dakota. We commenced construction of our expansion facility in Aberdeen, South Dakota in April 2007, and commenced operations in January 2008. Our production operations are carried out primarily through our operating subsidiary: ABE South Dakota, LLC (“ABE South Dakota”) which owns and operates ethanol facilities in Aberdeen and Huron, South Dakota.

Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. Based on the related business nature and expected financial results, the Company’s plants are aggregated into one reportable segment.

FACILITIES

The table below provides a summary of our dry mill ethanol plants in operation as of September 30, 2018:

 

Location

 

Opened

 

Estimated

Annual

Ethanol

Production(1)

 

 

Estimated

Annual

Distillers’

Grains

Production(2)

 

 

Estimated

Annual

Corn Oil

Production

 

 

Estimated

Annual Corn

Processed

 

 

Primary

Energy Source

 

 

 

 

(Million gallons)

 

 

(000s Tons)

 

 

(000s lbs)

 

 

(Million bushels)

 

 

 

Aberdeen, SD(3)

 

January 2008

 

 

48

 

 

 

134

 

 

 

11,561

 

 

 

15.7

 

 

Natural Gas

Huron, SD

 

September 1999

 

 

32

 

 

 

97

 

 

 

5,717

 

 

 

11.4

 

 

Natural Gas

Consolidated

 

 

 

 

80

 

 

 

231

 

 

 

17,278

 

 

 

27.1

 

 

 

 

(1)

Actual permitted gallons are 65.7 million for Aberdeen and 42.0 million for Huron totaling 107.7 million gallons.

(2)

Our plants produce and sell wet, modified and dried distillers’ grains. The stated quantities are on a fully dried basis operating at full production capacity.

(3)

Our plant at Aberdeen formerly consisted of two production facilities that operated on a separate basis.  The larger plant is represented in table above. In April 2016, the Company ceased operations at its smaller, nine million gallon Aberdeen facility due to inefficiencies at this older plant and capital expenditures required to keep the plant in operating condition, coupled with a weak margin environment. In the fourth quarter of fiscal 2016, the Company decided not to resume operations at this facility in the future and, accordingly, impaired the value of this asset on its financial statements to an estimated salvage value of $200,000, which resulted in a loss of $1,584,000 in the fourth quarter of fiscal 2016. During fiscal 2017, the Company received proceeds of $155,000 from the salvage of the smaller plant. At September 30, 2017, the remaining value of the asset on the Company’s financial statements was $45,000. During fiscal 2018, the Company received proceeds of $98,000 from the salvage of the smaller plant. At September 30, 2018, the remaining value of the asset on the Company’s financial statements was $0.

We believe that the plants are in adequate condition to meet our current and future production goals. We believe that the plants are adequately insured for replacement cost plus related disruption expenditures.

Under the ABE South Dakota security agreement with AgCountry (defined below), AgCountry holds a first priority security interest and mortgage in all inventory, accounts receivable, intangibles, equipment, fixtures, buildings, and a first mortgage in land owned or leased by ABE South Dakota.

5


ETHANOL

Ethanol sales have represented 77%, 82%, and 80% of our revenues in the years ended September 30, 2018, 2017, and 2016, respectively. In 2017, the United States consumed 14.49 billion gallons of ethanol representing 10.1% of the 142.98 billion gallons of finished motor gasoline consumed, according to the U.S Energy Information Administration (“EIA”). Ethanol is currently blended with gasoline to meet regulatory standards as a clean air additive, an octane enhancer, a fuel extender and as a gasoline alternative.

Ethanol is most commonly sold as E10, the 10 percent blend of ethanol that can be used in all American automobiles. Increasingly, ethanol is also available as E15, which is a higher octane fuel with a 15 percent blend of ethanol. In June 2012, the EPA approved E15 for use in vehicles with model years 2001 and later. According to the Renewable Fuels Association, this group of approved vehicles makes up 90 percent of all vehicles on the road today.  Although regulatory issues remain in many states, E15 is now available in limited locations in 29 states.  Ethanol is also available as E85, a higher percentage ethanol blend for use in flexible fuel vehicles.

The Renewable Fuels Standard

The Renewable Fuels Standard (“RFS”) is a national program that imposes requirements with respect to the amount of renewable fuel produced and used in the United States. The RFS was revised by the EPA in July 2010 (“RFS2”) and applies to refineries, blenders, distributors and importers. We believe the RFS2 program has and will continue to increase the market for renewable fuels, such as ethanol, as a substitute for petroleum-based fuels. The RFS2 required that 16.55 billion gallons be sold or dispensed in 2013, increasing to 36.0 billion gallons by 2022, representing 7% of the anticipated gasoline and diesel consumption in 2022. In 2013, RFS2 required refiners and importers to blend renewable fuels totaling at least 9.74% of total fuel volume, of which 8.12% of total fuel volume, or 13.8 billion gallons, could be derived from corn-based ethanol. The remainder of the requirement is to be met by non-corn related advanced renewable fuels such as cellulosic ethanol and biomass-based biodiesel. The RFS requirement for corn-based ethanol was capped at 15.0 billion gallons starting in 2015.

As of October 2018, current annualized ethanol production is approximately 16.2 billion gallons per the RFA. On November 30 2017, the EPA announced the final rule for 2018 RVOs, which is set at 15.0 billion gallons for corn-based ethanol.  This rule is also set at 100% of the original conventional biofuel requirement of 15.0 billion gallons, but has a reduction in the amount of advanced biofuels required. On June 26, 2018 the EPA announced proposed RVOs for 2019, which include 15.0 billion gallons for corn-based ethanol, consistent with both the 2018 RVOs and the original statutory volumes. On November 30, 2018 the EPA announced the final RVOs for 2019.  The final RVOs for 2019 were consistent with the volumes proposed in June, with an increase only in advanced biofuel volumes to 4.92 billion gallons from the proposed 4.88 billion gallons.  The 15.0 billion gallons that can be met with corn-based ethanol remains the same as the June 2018 proposal and the original statutory volumes.

The following chart illustrates the potential United States ethanol demand based on the schedule of minimum usage established by the RFS2 program through the year 2022 (in billions of gallons):

 

Year

 

Total

Renewable

Fuel

Requirement

 

 

Cellulosic

Ethanol

Minimum

Requirement

 

 

Biodiesel

Minimum

Requirement

 

 

Advanced

Biofuel

 

 

RFS

Requirement

That Can Be

Met With

Corn-Based

Ethanol

 

2017(1)

 

 

24.00

 

 

 

5.50

 

 

 

 

 

 

9.00

 

 

 

15.00

 

2017(2)

 

 

19.28

 

 

 

0.31

 

 

 

2.00

 

 

 

4.28

 

 

 

15.00

 

2018(1)

 

 

26.00

 

 

 

7.00

 

 

 

 

 

 

 

11.00

 

 

 

15.00

 

2018(3)

 

 

19.29

 

 

 

0.29

 

 

 

2.10

 

 

 

4.29

 

 

 

15.00

 

2019(1)

 

 

28.00

 

 

 

8.50

 

 

 

 

 

 

13.00

 

 

 

15.00

 

2019(4)

 

 

19.88

 

 

 

0.38

 

 

 

2.10

 

 

 

4.88

 

 

 

15.00

 

2019(5)

 

 

19.92

 

 

 

0.42

 

 

 

2.10

 

 

 

4.92

 

 

 

15.00

 

2020

 

 

30.00

 

 

 

10.50

 

 

 

 

 

 

15.00

 

 

 

15.00

 

2021

 

 

33.00

 

 

 

13.50

 

 

 

 

 

 

18.00

 

 

 

15.00

 

2022

 

 

36.00

 

 

 

16.00

 

 

 

 

 

 

21.00

 

 

 

15.00

 

 

(1)

Original statutory volumes.

(2)

Final EPA Renewable Fuel Standards for 2017 issued November 2016.

(3)

Final EPA Renewable Fuel Standards for 2018 issued November 2017.

(4)

Proposed EPA Renewable Fuel Standards for 2019 issued June 2018.

(5)

Final EPA Renewable Fuel Standards for 2019 issued November 2018.

 

6


The RFS2 went into effect on July 1, 2010 and requires certain gas emission reductions for the entire lifecycle, including production of fuels. The greenhouse gas reduction requirement generally does not apply to facilities that commenced construction prior to December 2007. If this changes and our plants must meet the standard for emissions reduction, it may impact the way we procure feed stock and modify the way we market and transport our products.

Clean Air Additive

A clean air additive is a substance that, when added to gasoline, reduces tailpipe emissions, resulting in improved air quality characteristics. Ethanol contains 35% oxygen, approximately twice that of MTBE, a historically used oxygenate. The additional oxygen found in ethanol, when blended with gasoline at a 10% level, results in more complete combustion of the fuel in the engine cylinder and reduces tailpipe emissions, including volatile organic compound emissions, by as much as 30%. Pure ethanol, which is non-toxic, water soluble and biodegradable, replaces some of the harmful gasoline components, including benzene.

Octane Enhancer

Pure ethanol possesses an average octane rating of 113, enabling refiners to conform lower octane blend stock to gasoline standards, while also expanding the volume of fuel produced. In addition, ethanol is commonly added to finished regular grade gasoline at the wholesale terminal to produce higher octane mid-grade and premium gasoline. At present, ethanol represents one of the few commercially viable sources of octane enhancer available to refiners.

Fuel Extender

Ethanol extends the volume of gasoline by the amount of ethanol blended with conventional gasoline, thereby reducing dependence on foreign crude oil and refined products. Furthermore, ethanol is easily added to gasoline after the refining process, reducing the need for large, capital intensive capacity expansion projects at refineries.

E85, a Gasoline Alternative

Ethanol is the primary blend component in E85. According to the U.S. Department of Energy, today there are over 3,310 retail stations offering E85 in the United States. The RFA estimates that there are now more than 22.0 million ethanol-flexible fuel vehicles (“FFVs”), on the road in the U.S. today, which is approximately eight percent of all vehicles.

E15

As noted above, to increase ethanol usage, Growth Energy requested a waiver from the EPA to increase the allowable amount of ethanol blended to a 15% level. In June 2012, the EPA approved E15 to be used in vehicles with model years 2001 and later. Although regulatory issues remain in many states, E15 is available in limited locations in 29 states as of November 2018.

Ethanol Competition

The ethanol we produce is similar to ethanol produced by other plants. The RFA reports that as of November 2018, current annual U.S. ethanol production capacity was approximately 16.2 billion gallons per year, with actual annualized production around 16.0 billion gallons per year. On a national level, there are numerous other production facilities with which we are in direct competition, many of which have greater resources than we do. As of November 2018, South Dakota had 15 ethanol plants producing an aggregate of 1.1 billion gallons of ethanol per year.

The largest ethanol producers include:  Archer Daniels Midland Company; Cargill, Inc.; Flint Hills Resources, LP; Green Plains Renewable Energy, Inc.; POET, LLC and Valero Renewable Fuels. Producers of this size may have an advantage over us from economies of scale and stronger negotiating positions with purchasers. We market our ethanol primarily on a regional and national basis. We believe that we are able to reach the best available markets through the use of experienced ethanol marketers and by the rail delivery methods we use. Our plants compete with other ethanol producers on the basis of price, and, to a lesser extent, delivery service. We believe that we can compete favorably with other ethanol producers due to our proximity to ample grain, natural gas, electricity and water supplies at favorable prices.

7


Competition from Alternative Fuels

Alternative fuels and alternative ethanol production methods are continually under development. The major oil companies have significantly greater resources than we have to develop alternative products and to influence legislation and public perception of ethanol. New ethanol products or methods of ethanol production developed by larger and better-financed competitors could provide them competitive advantages and harm our business.

Ethanol Marketing

ABE South Dakota has ethanol marketing agreements with NGL Energy Partners, LP (“NGL”), a diversified energy business. These ethanol marketing agreements require that we sell to NGL all of the denatured fuel-grade ethanol produced at the South Dakota plants. These ethanol marketing agreements expire on June 30, 2019 and will automatically renew unless cancelled by either party three months prior to the end of the term.

CO-PRODUCTS

Sales of distillers’ grains have represented 20%, 14%, and 18% of our revenues for the years ended September 30, 2018, 2017, and 2016, respectively. When the plants are operating at capacity, they produce approximately 231,000 tons of dried distillers’ grains equivalents per year, approximately 15-16 pounds per bushel of corn used. Distillers’ grains are a high-protein, high-energy animal feed supplement primarily marketed to the dairy and beef industry, but also to the poultry and swine markets. Dry mill ethanol processing creates three forms of distillers’ grains: (i) wet distillers’ grains with solubles, known as wet distillers’ grains; (ii) modified wet distillers’ grains with solubles, known as modified distillers’ grains; and (iii) dry distillers’ grains with solubles. Wet and modified distillers’ grains have been dried to approximately 65% and 50% moisture levels, respectively, and are predominately sold to nearby markets. Dried distillers’ grains have been dried to 11% moisture, have an almost indefinite shelf life and may be sold and shipped to more distant markets. In this Form 10-K, we sometimes refer to these products as “distillers’ grains” or “distillers’.”

We installed corn oil extraction technology at our Aberdeen plant in 2012. We installed corn oil extraction technology at our Huron plant that became fully operational in October 2016. Corn oil systems are designed to extract non-edible corn oil during the thin stillage evaporation process immediately prior to production of distillers’ grains. Corn oil is produced by processing evaporated thin stillage through a disk stack style centrifuge. Corn oil has a lower density than the water or solids that make up the syrup. The centrifuges separate the relatively light oil from the heavier components of the syrup, eliminating the need for significant retention time. De-oiled syrup is returned to the process for blending into wet, modified, or dry distillers’ grains.

Industrial uses for corn oil include feedstock for biodiesel, livestock feed additives, rubber substitutes, rust preventatives, inks, textiles, soaps and insecticides. Our corn oil is primarily sold by truck to biodiesel manufacturers.

Competition

In the sales of distillers’ grains, we compete with other ethanol producers, as well as a number of large and smaller suppliers of competing animal feed. We believe the principal competitive factors are price, proximity to purchasers and product quality. Currently we derive 68% of our distillers’ grain revenues from the sale of dried distillers’ grains, which have an indefinite shelf life and can be transported by truck or rail, and 32% from the sale of modified or wet distillers’ grains, which have a shorter shelf life and are typically sold in local markets and delivered via truck.

We compete with other ethanol producers in the sale of corn oil. We ship all of the corn oil from our facilities via truck.  Many ethanol producers have added corn oil technology to their facilities.

Co-Product Marketing

ABE South Dakota has an agreement with Dakotaland Feeds, LLC (“Dakotaland Feeds”) to market and sell wet distillers grains produced at the Huron plant and modified distillers grains produced at the Aberdeen plant. ABE South Dakota has a marketing agreement with Gavilon Ingredients, LLC (“Gavilon”) for the dried distillers’ grains produced at the Huron and Aberdeen plants that became effective July 1, 2013. The marketing agreement requires Gavilon to use commercially reasonable efforts to purchase substantially all of the dried distillers’ grains produced at the Huron and Aberdeen plants through July 31, 2019. The Aberdeen plant self-markets its wet and a small portion of modified distillers’ grains.

ABE South Dakota is party to an agreement with Gavilon to market all the corn oil produced by the Huron and Aberdeen plants through November 30, 2019 and September 30, 2019, respectively.

8


DRY MILL PROCESS

Dry mill ethanol plants produce ethanol primarily by processing corn. Other possible feeds are grain sorghum, or other cellulosic materials. The corn is conveyed directly from Agtegra Cooperative to the plant where it is weighed and transferred to a scalper to remove rocks, cobs, and other debris. The corn is then fed to a hammermill where it is ground into flour and conveyed into a slurry tank. Water, heat and enzymes are added to the flour in the slurry tank to start the process of converting starch from the corn into sugar. The slurry is pumped to a liquefaction tank where additional enzymes are added. These enzymes continue the starch-to-sugar conversion. The grain slurry is then pumped into fermenters, where yeast is added, to begin the batch-fermentation process. Fermentation is the process of the yeast converting the sugar into alcohol and carbon dioxide. After the fermentation is complete, a vacuum distillation system removes the alcohol from the corn mash. The 95% (190-proof) alcohol from the distillation process is then transported to a molecular sieve system, where it is dehydrated to 100% alcohol (200 proof). The 200-proof alcohol is then pumped to storage tanks and blended with a denaturant, usually natural gasoline. The 200-proof alcohol and 2.0-2.5% denaturant blend constitute denatured fuel ethanol.

Corn mash left over from distillation is pumped into a centrifuge for dewatering. The liquid from the centrifuge, known as thin stillage, is then pumped from the centrifuges to an evaporator, where it is concentrated into a syrup. The solids that exit the centrifuge, known as the wet cake, are conveyed to the dryer system. Syrup is added to the wet cake as it enters the dryer, where moisture is removed. The process produces distillers’ grains with solubles, which is used as a high-protein/fat animal-feed supplement. Dry-mill ethanol processing creates three forms of distillers’ grains: (i) wet distillers’ grains with solubles, known as wet distillers’ grains; (ii) modified wet distillers’ grains with solubles, known as modified distillers’ grains; and (iii) dry distillers’ grains with solubles, known as dry distillers’ grains. Wet and modified distillers’ grains have been dried to approximately 65% and 50% moisture levels, respectively, and are predominately sold to nearby markets. Dried distillers’ grains have been dried to 11% moisture, have an almost indefinite shelf life and may be sold and shipped to more distant markets.

Corn oil is produced by processing evaporated thin stillage through a disk stack style centrifuge. Corn oil has a lower density than water or solids that make up the syrup. The centrifuges separate the relatively light oil from the heavier components of the syrup, eliminating the need for significant retention time. De-oiled syrup is returned to the process for blending into wet, modified, or dry distillers’ grains. The corn oil is then pumped into storage tanks before being loaded onto trucks for sale.

RAW MATERIALS

Corn

In 2017, the ethanol industry consumed approximately 5.5 billion bushels of corn, which approximated 38% of the 14.6 billion bushels of domestic corn production, according to the U.S. Department of Agriculture.

Our production facilities produce ethanol by using a dry-mill process, with an annual production capacity of approximately 80 million gallons, which yields approximately 2.8 gallons of denatured ethanol per bushel of corn. When our South Dakota facilities are operating at capacity, they process approximately 27 million bushels of corn per year. We have a grain origination agreement with Agtegra Cooperative (“Agtegra”) under which Agtegra originates, stores and delivers corn to the Aberdeen and Huron plants. Although our agreement with Agtegra allows us to purchase corn from other sources, we have historically not done this. Our agreement with Agtegra was automatically renewed in November 2016 and was set to expire in November 2019.  On May 4, 2018, we issued a partial notice of termination of this agreement with respect to the Aberdeen plant due to our plans to construct a grain storage and receiving facility.  The remaining agreement for the Huron plant expires in November 2019 and will automatically renew unless cancelled at least 180 days prior to the end of the renewal term.

We purchase corn from Agtegra through forward fixed-priced contracts, forward basis contracts and daily spot pricing. Our forward contracts specify the amount of corn, the price and the time period over which the corn is to be delivered. These forward contracts are at fixed-prices or prices based on the Chicago Board of Trade (“CBOT”) prices.

Natural Gas

When our South Dakota facilities operate at capacity, they require approximately 2.1 million British Thermal Units (“mmbtu”) of natural gas per year. Natural gas prices and availability are affected by weather conditions and overall economic conditions. We have constructed our own natural gas pipeline for the Aberdeen plant. This pipeline originates at a mainline and allows our Aberdeen plant to source gas from various national marketers without paying transportation cost to the local utility. Our Huron plant does not have an owned pipeline and is subject to additional transportation charges. The Huron plant generally purchases its natural gas from national suppliers. Natural gas prices can be volatile; therefore from time to time we use hedging strategies to reduce our exposure to natural gas price fluctuations.

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Shipment of Ethanol by Rail Car

We transport ethanol to our customers primarily via tanker rail cars. As of September 30, 2018, we are leasing ethanol tank cars under leases that expire at varying times over the next six years. Over the past several years, there have periodically been periods of increased rail traffic congestion throughout the United States, primarily due to the increase significant in cargo trains carrying shale oil. From time to time, this congestion has affected our ability to have our tanker rail cars return to the Aberdeen and Huron plants on a timely basis. Delays in returning rail cars to our plants may affect our ability to operate our plants at full capacity due to ethanol storage capacity constraints. To mitigate this risk, the Company added one million gallons of denatured ethanol storage at the Aberdeen plant, which became operational in January 2015. The Company may also consider additional storage capacity at the Huron plant in the future.

ENVIRONMENTAL MATTERS

We 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; and the health and safety of our employees. Any violation of these laws and regulations or permit conditions could result in substantial fines, natural resource damage, criminal sanctions, and damage claims from third parties, and permit revocations or facility shutdowns. We believe we are currently in substantial compliance with environmental laws and regulations and do not anticipate a material adverse effect on our business or financial condition as a result of our efforts to comply with these requirements. However, our business is still subject to risks associated with environmental and other regulations and associated costs. Protection of the environment requires us to incur expenditures for equipment, processes and permitting. We use various pollution control equipment in our production facilities. In fiscal 2015, we installed a Continuous Emissions Monitoring System (“CEMS”) at our Aberdeen plant to enable us to burn increased levels of natural gas while ensuring compliance with emissions regulations. The total capital expenditure related to the bag house and CEMS unit was approximately $420,000.

EMPLOYEES

As of December 1, 2018, we had 62 full-time employees. None of our employees are covered by a collective bargaining agreement.

SEASONALITY

Our operating results are influenced by seasonal fluctuations in the price of our primary operating inputs, corn and natural gas, and the price of our primary products, ethanol and distillers’ grains. Historically, the spot price of corn tends to rise during the spring planting season in May and June and tends to decrease during the fall harvest in October and November. The price for natural gas however, tends to move opposite of corn and tends to be lower in the spring and summer and higher in the fall and winter. The price of distillers’ grains tends to rise during the fall and winter cattle feeding seasons and be lower in the spring and summer when pasture grazing is readily available, although this effect can be mitigated if export markets are strong.

REPORTS

The Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports are available on the Company’s website www.advancedbioenergy.com as soon as reasonably practicable after it electronically files these materials with the SEC.

 

 

ITEM 1A.

RISK FACTORS

RISKS RELATED TO OUR BUSINESS

Current ABE South Dakota debt financing agreements contain restrictive covenants. Our failure to comply with applicable debt financing covenants and agreements could have a material adverse effect on our business, results of operations and financial condition.

The terms of our existing debt financing agreements contain, and any future debt financing agreements we enter into may contain, financial, maintenance, organizational, operational or other restrictive covenants. If ABE South Dakota is unable to comply with these covenants or service its debt, we may be forced to reduce or delay planned capital expenditures, sell assets, restructure our indebtedness or submit to foreclosure proceedings, any of which could result in a material adverse effect upon our business, results of operations and financial condition.

As a result of a depressed margin environment in fiscal 2018, ABE South Dakota was required to request waivers for certain Events of Default at September 30, 2018, and covenant amendments for certain future covenants for which ABE South Dakota

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projected non-compliance.  Although ABE South Dakota’s lender, AgCountry Farm Credit Services, PCA, granted the waivers and covenant amendments via the Third and Fourth Amendments to the 2015 Credit Agreement, we cannot project with certainty that we will meet all covenant obligations, as amended, if depressed margins continue for an extended period of time.  If ABE South Dakota is unable to comply with the amended covenants, we cannot be certain that our lender will grant us future waivers, which could result in any or all of the impacts noted above and could result in a material adverse effect upon our business, results of operations and financial condition.

Our financial performance is highly dependent on commodity prices, which are subject to significant volatility, uncertainty, and supply disruptions, so our results may be materially adversely affected.

Our results of operations and financial condition are significantly affected by the cost and supply of corn and natural gas, and by the selling price for ethanol, distillers’ grains, corn oil and gasoline, which are commodities. Changes in the price and supply of these commodities are subject to and determined by market forces over which we have no control.

Our revenues exclusively depend on the market prices for ethanol, distillers’ grains and corn oil. These prices can be volatile due to a number of factors, including overall supply and demand, the price of corn, the price of and demand for gasoline, the level of government support and the availability and price of competing products.

One of our members beneficially owns a large percentage of our units, which may enable it to control substantially all matters requiring member approval.  This member, THL and affiliated entities (f/k/a Hawkeye Energy Holdings), has been granted other special voting rights.

In August 2009, we and each of our then-current directors, Agtegra Cooperative (formerly South Dakota Wheat Growers Association), entities associated with Clean Energy Capital (“CEC”) (and predecessor entities) and entities associated with Thomas H. Lee Partners, L.P. (“THL”) executed a Voting Agreement (the “Voting Agreement”). The Voting Agreement, as amended January 25, 2015, among other things, currently requires the parties to (a) nominate for election to the board two designees of THL and the Chief Executive Officer of the Company, (b) recommend to the members the election of each of these designees, (c) vote (or act by written consent) all units (or other voting equity securities) of the Company they beneficially own, hold of record or otherwise control at any time, in person or by proxy, to elect each of the designees to the board, (d) not take any action that would result in (and take any action necessary to prevent) the removal of any of the designees from the board or the increase in the size of the board to more than nine members without the consent of the THL and the Chief Executive Officer, and (e) not grant a proxy with respect to any units that is inconsistent with the parties’ obligations under the Voting Agreement. As of January 1, 2017, entities associated with CEC no longer have a five percent ownership interest in the Company and accordingly, CEC is not entitled to designees for whom the other parties to the Voting Agreement must vote. The Company has also granted THL board observation rights under the Voting Agreement. At December 1, 2018, the parties to the Voting Agreement held in the aggregate approximately 40% of the outstanding units of the Company.

As a result of the Voting Agreement and its ownership, THL has the ability to significantly influence the outcome of any actions taken by our board of directors. In addition, given the large ownership of this entity, THL can significantly influence other actions, such as amendments to our operating agreement, mergers, going private transactions, and other extraordinary transactions, and any decisions concerning the terms of any of these transactions. The ownership and voting positions of this member may have the effect of delaying, deterring, or preventing a change in control or a change in the composition of our board of directors. This member may also use its contractual rights, including access to management, and its large ownership position to address its own interests, which may be different from those of our other members.

We are required to sell substantially all of our ethanol to NGL Energy Partners LP, which may place us at a competitive disadvantage and reduce profitability.

The Company’s operating subsidiary, ABE South Dakota, has ethanol marketing agreements with NGL Energy Partners, LP (“NGL”), a diversified energy business. These ethanol marketing agreements require that we sell to NGL all of the denatured fuel-grade ethanol produced at the South Dakota plants. These ethanol marketing agreements expire on June 30, 2019 and will automatically renew unless cancelled by either party three months prior to the end of the current term.

ABE South Dakota depends on NGL to market ABE’s ethanol and manage the logistics of ABE South Dakota’s rail cars to ensure ABE South Dakota is able to continue producing ethanol without exceeding its storage capacity, which would result in unplanned slowdowns or shut downs. Any failure or default by NGL in its obligations to ABE South Dakota may negatively affect our profitability.

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We depend upon NGL to market the ethanol we produce, and we sublease from NGL a majority of the ethanol rail cars we use to transport our ethanol to customers. If we are unable to renew these agreements with NGL, our liquidity and profitability could be adversely affected, if we are unable to find similar pricing and payment terms from other marketers.

We depend on others for sales of our products and purchases of our inputs, which may place us at a competitive disadvantage and reduce profitability.

As noted above, we currently have agreements with a third-party marketing firm, NGL, to market all of the ethanol we produce at our facilities. We also contract with third parties to market the sale of most of the distillers’ grains and corn oil produced at our South Dakota plants. If the ethanol or co-product marketers breach their contracts or do not have the ability, for financial or other reasons, to market all of the ethanol we produce or to market the co-products produced at the South Dakota plants, we may not have any readily available alternative means to sell our products. Our lack of a sales force and reliance on these third parties to sell and market most of our products may place us at a competitive disadvantage. Our failure to sell all of our ethanol and co-products may result in lower revenues and reduced profitability.

We have a grain origination agreement with Agtegra under which Agtegra originates, stores and delivers corn to the Aberdeen and Huron plants. Although our agreement with Agtegra allows us to purchase corn from other sources, we have historically not done this. Our agreement with Agtegra was automatically renewed in November 2016 and was set to expire in November 2019.  On May 4, 2018, we issued a partial notice of termination of this agreement with respect to the Aberdeen plant due to our plans to construct a grain storage and receiving facility.  The remaining agreement for the Huron plant expires in November 2019 and will automatically renew unless cancelled at least 180 days prior to the end of the renewal term. We have also begun to explore constructing grain storage at our Huron plant.  The process of constructing and operating our own grain storage facilities requires a substantial commitment of time and capital and there is no assurance that we will be successful.  If we are unable to negotiate a more favorable grain origination agreement with Agtegra for our Huron plant, or successfully construct and operate our own grain storage facility at either plant, it could have a material adverse effect on our business, results of operations and financial condition.

We are exposed to credit risk resulting from non-payment by significant customers.

We have a concentration of credit risk because our ABE South Dakota subsidiary generally sells all of its ethanol to a single customer. Although we typically receive payments within twenty days from the date of sale for our ethanol, distillers’ grains and corn oil, we continually monitor this credit risk exposure. In addition, we may prepay for or make deposits on undelivered inventories. Our credit risk concentrations for inventory advances are primarily with a few major suppliers of petroleum products and agricultural inputs. The inability of a third party to pay our accounts receivable or to deliver us inventory for advance payments we made may cause us to experience losses and may adversely affect our liquidity and our ability to make our payments when due. As of September 30, 2018, the total receivable balance at ABE South Dakota was $4.2 million, of which 99% was due from three customers.

Our profitability depends on the spread between ethanol and corn prices, which can vary significantly.

Gross profit on gallons produced at our facilities, which accounts for the substantial majority of our operating income, principally depends on the spread between ethanol and corn prices.

The price of corn is influenced by weather conditions (including droughts or excess rainfall) and other factors affecting crop yields, farmer planting decisions and general economic, market and regulatory factors, including government policies and subsidies with respect to agriculture and international trade, and global and local supply and demand. Conversely, ethanol prices are primarily influenced by market demand and can fluctuate widely depending on industry-wide ethanol inventory levels.

Volatility in oil and gas prices may materially affect ethanol pricing and demand and make it difficult to manage profit margins.

Ethanol has historically traded at a discount to gasoline; however with the recent volatility in oil and gas prices, ethanol prices have also fluctuated. When ethanol trades at a discount to gasoline it encourages discretionary blending, thereby potentially increasing the demand for ethanol beyond required blending rates. Conversely, when ethanol trades at a premium to gasoline, there is a disincentive for discretionary blending and ethanol demand is negatively affected. Consequently, ethanol pricing and demand may also be volatile, which makes it difficult to manage profit margins and which could result in a material adverse effect on our business, results of operations and financial condition.

The market for natural gas is subject to market conditions that create uncertainty in the price and availability of the natural gas that we use in our manufacturing process.

Natural gas costs represented approximately 6.2% of our cost of goods sold in the year ended September 30, 2018. We rely upon third parties for our supply of natural gas that we consume to produce ethanol. The prices for and availability of natural gas are subject

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to volatile market conditions. These market conditions often are affected by factors beyond our control such as higher prices resulting from colder than average weather conditions, hurricanes in the Gulf of Mexico, and the expansion of hydraulic fracturing in the U.S. over the past several years, which has expanded domestic supplies, and overall economic conditions. Significant disruptions in the supply of natural gas could impair our ability to produce ethanol. Furthermore, increases in natural gas prices or changes in our natural gas costs relative to natural gas costs paid by competitors may adversely affect our results of operations and financial position. Natural gas prices over the period from October 1, 2012 through September 30, 2018, based on the New York Mercantile Exchange or NYMEX, daily futures data, have ranged from a low of $2.44 per million British Thermal Units, or mmbtu, on April 27, 2015 to a high of $6.49 per mmbtu on February 24, 2014. At September 30, 2018, the NYMEX price of natural gas was $3.01 per mmbtu.

We may engage in hedging transactions and other risk mitigation strategies that could harm our results.

We are exposed to a variety of market risks, including the effects of changes in commodity prices. Hedging activities can result in losses when a position is purchased in a declining market or a position is sold in a rising market. We cannot ensure that we will not experience hedging losses in the future. Hedging arrangements also expose us to the risk of financial loss in situations where the other party to the hedging contract defaults on its contract or, in the case of exchange-traded contracts, where there is a change in the expected differential between the underlying price in the hedging agreement and the actual prices paid or received by us. In addition, failure to have adequate capital to use various hedging strategies, may expose us to substantial risk of loss, or result in a loss for our company. As of September 30, 2017 and 2018, we did not have any material derivative contracts outstanding.

Our lack of business diversification could result in adverse operating results if our revenues from our primary products decrease.

Our business consists of the production and sale of ethanol, distillers’ grains, and corn oil. We do not have any other lines of business or other potential sources of revenue. Our lack of business diversification could cause us to shut down operations and be unable to meet financial obligations if we are unable to generate positive cash flows from the production and sale of ethanol and co-products because we do not currently expect to have any other lines of business or alternative revenue sources.

Our operating results may fluctuate significantly, which makes our future results difficult to predict and could cause our operating results to fall below expectations.

Our operating results have fluctuated in the past and may fluctuate significantly in the future due to a variety of factors, many of which are outside of our control. As a result, comparing our operating results on a period-to-period basis may not be meaningful, and our past results do not necessarily indicate our future performance.

We depend on certain key personnel, and the loss of any of these persons may prevent us from implementing our business plan in an effective and timely manner.

Our success depends largely upon the continued services of our chief executive officer and other key personnel. Any loss or interruption of the services of one of these key personnel could result in our inability to manage our operations effectively or pursue our business strategy.

RISKS RELATED TO OUR UNITS

We have placed significant restrictions on transferability of the units, no public trading market exists for our units and there is no assurance that unit holders will receive future cash distributions.

Our units are subject to substantial transfer restrictions pursuant to our operating agreement. As a result, investors may not be able to easily liquidate their investments in the units and, therefore, may be required to assume the risks of investments in us for an indefinite period of time, which may be the life of our Company.

Further, although our units are now listed on an internet-based matching platform, there is currently no established public trading market for our units, and we do not anticipate an active trading market will develop. In order for the Company to maintain its partnership tax status, unit holders may not trade the units on an established securities market or readily trade the units on a secondary market (or the substantial equivalent thereof).

To help ensure that a secondary market does not develop, our operating agreement prohibits transfers without the approval of our board of directors. The board of directors will not approve transfers unless they fall within “safe harbors” contained in the publicly traded partnership rules under the tax code, which include, without limitation, the following:

 

Transfers by gift to the member’s descendants,

 

Transfer upon the death of a member,

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Transfers between family members, and

 

Transfers that comply with the “qualifying matching services” requirements.

Distributions are payable at the sole discretion of our board of directors, subject to the provisions of the Delaware Limited Liability Company Act, our operating agreement and the requirements of our creditors. We cannot ensure that we will make cash distributions in the future. Our board may elect to retain future profits to provide operational financing for the plants, debt retirement and possible plant expansion, the construction or acquisition of additional plants or other company opportunities. This means that members may receive little or no return on their investment and be unable to liquidate their investment due to transfer restrictions and lack of a public trading market.

Our members have limited voting rights.

Members cannot exercise control over our daily business affairs. Subject to the provisions in our operating agreement, our board of directors may modify our business plans without the members’ consent.

In addition to the election of directors, the disposition of substantially all of our assets through merger, exchange or otherwise, except for dissolution of our Company or a transfer of our assets to a wholly owned subsidiary, requires the affirmative vote of a majority of our membership voting interests.

Our members may only propose amendments to the Operating Agreement if they hold more than 1% of the units outstanding. Members may demand a member meeting only if they represent a majority of the membership voting interests.

Amendments to our operating agreement (other than amendments that would modify the limited liability of a member or alter a member’s economic interest, which requires a two-thirds vote of the membership interests adversely affected) require the affirmative vote of a majority of the membership voting interests represented at a meeting.

RISKS RELATED TO THE ETHANOL INDUSTRY

If demand does not sufficiently increase and production capacity and imported ethanol increase, industry overcapacity could develop.

According to the RFA, domestic ethanol production capacity has increased dramatically from 1.7 billion gallons per year in January 1999 to 16.2 billion gallons per year as of November 2018. In addition to this increase in production capacity, excess ethanol production capacity also may result from decreases in the demand for ethanol or increased imported supply, which could result from a number of factors, including but not limited to, regulatory developments, reduced exports and reduced gasoline consumption in the U.S. Reduced gasoline consumption could occur as a result of increased prices for gasoline or crude oil, which could cause businesses and consumers to reduce driving or acquire vehicles with more favorable gasoline mileage, or as a result of technological advances, such as the commercialization of engines utilizing hydrogen fuel-cells, which could supplant gasoline-powered engines. There are a number of governmental initiatives designed to reduce gasoline consumption, including tax credits for hybrid vehicles and consumer education programs. In August 2012, the Federal government issued regulations to increase fuel efficiency and reduce greenhouse gas pollution for all new cars and trucks sold in the United States. These new standards will cover cars and light trucks for Model Years 2017-2025, requiring performance equivalent to 54.5 mpg in 2025. These standards are likely to reduce the overall demand for gasoline, and therefore ethanol.

Any increase in the supply of distillers’ grains, without corresponding increases in demand, could lead to lower prices or an inability to sell our distillers’ grains. A decline in the price of distillers’ grains, or the distillers’ grains market generally, could have a material adverse effect on our business, results of operations and financial condition.

Volatility in gasoline selling price and production cost may reduce our gross margins.

Ethanol is used both as a fuel additive to reduce vehicle emissions and as an octane enhancer to improve the octane rating of the gasoline with which it is blended. Therefore, the supply and demand for gasoline affects the price of ethanol, and our business and future results of operations may be materially adversely affected if gasoline demand or price decreases.

The price of distillers’ grains is affected by the price of other commodity products; decreases in the price of these commodities could decrease the price of distillers’ grains.

Distillers’ grains compete with other protein-based animal feed products. The price of distillers’ grains may decrease when the price of competing feed products decrease. The prices of competing animal feed products are based in part on the prices of the

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commodities from which they are derived. Downward pressure on commodity prices, such as corn and soybean meal, will generally cause the price of competing animal feed products to decline, resulting in downward pressure on the price of distillers’ grains. Because the price of distillers’ grains is not tied to production costs, decreases in the price of distillers’ grains will result in us generating less revenue and lower profit margins.

Growth in the sale and distribution of ethanol depends on the changes in and expansion of related infrastructure, which may not occur on a timely basis, if at all, and our operations could be adversely affected by infrastructure disruptions.

Ethanol is currently blended with gasoline to meet regulatory standards as a clean air additive, an octane enhancer, a fuel extender and a gasoline alternative. In 2017, the United States consumed 14.49 billion gallons of ethanol representing 10.1% of the 142.98 billion gallons of finished motor gasoline consumed, according to the U.S Energy Information Administration (“EIA”). Ethanol plants in the United States produced 15.8 billion gallons in 2017, approximately 0.5 billion gallons more than were produced in 2016. The demand for ethanol is affected by what is commonly referred to as the “blending wall”, which is a regulatory cap on the amount of ethanol that can be blended into gasoline. The blend wall affects the demand for ethanol, and as industry production capacity reaches the blend wall, the supply of ethanol in the market may surpass the demand. Assuming current gasoline usage in the U.S. at 142.98 billion gallons per year and a blend rate of 10% ethanol and 90% gasoline, the current blend wall is approximately 14.3 billion gallons of ethanol per year. In order to expand demand for ethanol, higher percentage blends must be used in standard vehicles.

To drive growth in ethanol usage, Growth Energy requested a waiver from the EPA to increase the allowable amount of ethanol blended into gasoline from the current 10% level to a 15% level. A final decision, announced on October 13, 2010, allows E15 usage in 2007 and newer vehicles, and was updated on January 21, 2011 to include 2001 to 2006 vehicles. Although regulatory issues remain in many states, E15 is now available in limited locations in 29 states.

Additional infrastructure will be required to handle the additional 5% of blending including:

 

Expansion of refining and blending facilities to handle ethanol;

 

Growth in the number of service stations equipped to handle ethanol fuels, which often requires investment in new pumps and storage capacity at stations;

 

Additional storage facilities for ethanol;

 

Additional rail capacity; and

 

Increase in truck fleets capable of transporting ethanol within localized markets

Without infrastructure investments by unrelated parties, the demand for ethanol may not increase, which could have an adverse effect on our business.

Corn-based ethanol may compete with cellulose-based ethanol in the future, which could make it more difficult for us to produce ethanol on a cost-effective basis.

A current focus in ethanol production research is the development of an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, and municipal solid waste and energy crops. This focus is driven by governmental mandates including the Renewable Fuels Standard, as most recently amended (“RFS2”), and the fact that cellulose-based biomass would create opportunities to produce ethanol in areas that are unable to grow corn. Furthermore, ethanol produced from cellulose based biomass is generally considered to emit less carbon emission than ethanol produced from corn. If an efficient method of producing ethanol from cellulose-based biomass is developed and commercialized on a large scale, we may not be able to compete effectively. There is currently one commercial scale plant dedicated to cellulosic ethanol production operating, and several others producing a combination of corn-based and cellulosic ethanol via pathways approved by the EPA. We currently believe it would not be cost-effective for us to convert our existing plants into cellulose-based biomass facilities. If we are unable to produce ethanol as cost effectively as cellulose-based producers, our ability to generate revenue and operate profitably will be negatively affected.

Competition from new or advanced technology may lessen the demand for ethanol and negatively affect our profitability.

Alternative fuels, gasoline oxygenates and ethanol production methods are continually under development. A number of automotive, industrial and power generation manufacturers are developing more efficient engines, hybrid engines and alternative clean power systems using fuel cells or clean burning gaseous fuels. Vehicle manufacturers are working to develop vehicles that are more fuel efficient and have reduced emissions using conventional gasoline. Vehicle manufacturers have developed and continue to work to improve hybrid technology, which powers vehicles by engines that use both electric and conventional gasoline fuel sources. In the future, the emerging fuel cell industry will offer a technological option to address increasing worldwide energy costs, the long-term

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availability of petroleum reserves and environmental concerns. Fuel cells have emerged as a potential alternative to certain existing power sources because of their higher efficiency, reduced noise and lower emissions. Fuel cell industry participants are currently targeting the transportation, stationary power and portable power markets to decrease fuel costs, lessen dependence on crude oil and reduce harmful emissions. If the fuel cell and hydrogen industries continue to expand and gain broad acceptance, and hydrogen becomes readily available to consumers for motor vehicle use, we may not be able to compete effectively. This additional competition could reduce the demand for ethanol, which would adversely affect our profitability and reduce the value of our units.

Competition in the ethanol industry could limit our growth and harm our operating results.

The market for ethanol and other biofuels is highly competitive. Our current and prospective competitors include many large companies that have substantially greater market presence, geographic diversity, name recognition and financial, marketing and other resources than we do. We compete directly or indirectly with large companies, such as  Archer Daniels Midland Company; Cargill, Inc.; Flint Hills Resources, LLC; Green Plains Renewable Energy, Inc.; POET, LLC and Valero Energy Corporation and with other companies that are seeking to develop large-scale ethanol plants and alliances. Pressure from our competitors could require us to reduce our prices or increase our spending for marketing, which would erode our margins and could have a material adverse effect on our business, financial condition and results of operations.

Imported ethanol may be a less expensive alternative to domestic ethanol, which would cause us to lose market share and reduce the value of your investment.

Brazil is currently the world’s second largest producer and exporter of ethanol. In Brazil, ethanol is produced primarily from sugarcane, which can be less costly to produce than U.S. corn-based ethanol. When former import tariffs from Brazil were removed, a significant barrier to entry into the U.S. ethanol market was eliminated. Competition from ethanol imported from Brazil or Caribbean or Central American countries may affect our ability to sell our ethanol profitably.

RISKS RELATED TO ETHANOL PRODUCTION

Operational difficulties at our plants could negatively affect our sales volumes and could cause us to incur substantial losses.

Our operations are subject to unscheduled downtime and operational hazards inherent to our industry, such as equipment failures, utility outages, fires, explosions, abnormal pressures, blowouts, pipeline ruptures, transportation disruptions and accidents and natural disasters. We may have difficulty managing the process maintenance required to maintain our nameplate production capacities. If our ethanol plants do not produce ethanol and distillers’ grains at the levels we expect, our business, results of operations, and financial condition may be materially adversely affected.

Improperly trained employees may not follow procedures, resulting in damage to certain parts of the ethanol production facility, which could negatively affect operating results if our plants do not produce ethanol and its by-products as anticipated.

The production of ethanol and distillers’ grains demands continuous supervision and judgments regarding mixture rates, temperature and pressure adjustments. Errors of judgment due to lack of training or improper manufacturer instructions could send chemicals into sensitive areas of production, which may reduce or halt ethanol or distillers’ grains production at our facilities.

Rail traffic congestion may affect our ability to return our tanker rail cars to our plants on a timely basis, and could require us to reduce or cease production in the event we exceed our ethanol storage capacity.

There have been periodic significant increases in rail traffic congestion throughout the United States primarily due to the increase in cargo trains carrying shale oil. From time to time, this congestion has and may continue to affect our ability to have our tanker rail cars return to the Aberdeen and Huron plants on a timely basis. Delays in returning rail cars to our plants may affect our ability to operate our plants at full capacity due to ethanol storage capacity constraints. In response to the rail congestion issues we constructed an additional one million gallons of denatured ethanol storage at our Aberdeen, South Dakota plant. The additional storage became operational in January 2015 and increased the total denatured ethanol storage at the Aberdeen plant to approximately two million gallons. We are evaluating whether to add ethanol storage at our Huron, South Dakota plant.

We may have difficulty obtaining enough corn to operate the plants profitably.

There may not be an adequate supply of corn produced in the areas surrounding our plants to satisfy our requirements. Even if there is an adequate supply of corn and we make arrangements to purchase it, we could encounter difficulties finalizing the sales transaction and managing the delivery of the corn, including difficulties caused by inclement weather. If we do not obtain corn in the quantities we plan to use, we may not be able to operate our plants at full capacity. If the price of corn in our local markets is higher

16


due to lack of supply, drought, or other reasons, our profitability may suffer and we may incur significant losses from operations. As a result, our ability to make a profit may decline.

RISKS RELATED TO REGULATION AND GOVERNMENTAL ACTION

We are exposed to additional regulatory risk that may prevent the sale of our products to customers located in certain states or require us to change the way we operate.

Legislative acts by the State of California and the Environmental Protection Agency (i.e. RFS2) require cleaner emissions and reduced carbon footprints including effects caused by indirect land use. These acts, when implemented, may prohibit the sale of our products to certain customers, which may materially adversely impact our results from operations, or may require us to procure feedstock and market our products in a fashion that negatively impacts our financial performance.

The use and demand for ethanol and its supply are affected by federal and state legislation and regulation, most significantly the Renewable Fuels Standard. Any changes in applicable legislation or regulation could cause the demand for ethanol to decline or its supply to increase, which could have a material adverse effect on our business, results of operations and financial condition, and the ability to operate at a profit.

Various federal and state laws, regulations and programs affect the demand for ethanol as a fuel or fuel additive. Tariffs generally apply to the import of ethanol from other countries. These laws, regulations and programs are constantly changing. Federal and state legislators and environmental regulators could adopt or modify laws, regulations or programs that could adversely affect the use of ethanol.

On November 30, 2017, the EPA announced final RVO requirements for the RFS for calendar year 2018. The conventional biofuel requirement of 15 billion gallons remained the same as the rule proposed in July 2017. On June 26, 2018 the EPA announced proposed RVOs for 2019, which include 15.0 billion gallons for corn-based ethanol, consistent with both the 2018 RVOs. The 15.0 billion gallon level for corn-based ethanol achieves the statutory requirement level as originally set by Congress when the RFS was enacted. However, opponents of ethanol such as large oil companies will likely continue their efforts to repeal or reduce the RFS through lawsuits or lobbying of Congress. Successful reduction or repeal of the blending requirements of the RFS could result in a significant decrease in ethanol demand.

Current ethanol production capacity is approximately 16.2 billion gallons according to the RFA. Reduction of blending requirements could reduce the demand for and price of ethanol. If demand for ethanol decreases, it could materially adversely affect our business, results of operations and financial condition.

The U.S. Department of Transportation is requiring the tanker cars that are used to transport ethanol be replaced or retrofitted to meet new rail safety standards.

We use tanker rail cars to transport the majority of the ethanol produced at our facilities. We currently have 411 tanker cars under lease of which a portion will not be taken possession of until fiscal 2019. The majority of the tanker cars used by our company and the rest of the ethanol industry are DOT-111 tanker cars; these are the same type of tanker cars used by the oil industry to transport crude oil.

In response to various incidents on the rail system involving the transportation of crude oil products, the Department of Transportation (“DOT”) has issued new safety regulations surrounding the transportation of highly flammable liquids, which includes not only crude oil products, but also ethanol. The DOT originally proposed a three-year timetable for replacing or modifying current DOT-111 railcars used in ethanol service. However, the ethanol industry argued that it should be afforded more time because corn-based fuel shipped by rail poses less of a risk to public safety than crude oil. The DOT’s final rule gave the ethanol industry until May 1, 2023 to replace or retrofit current DOT-111 cars. Although the extended timetable was a positive outcome for the ethanol industry, the new requirements could result in a shortage of compliant tanker cars. This could have an adverse impact on our operations, because we may be faced with drastically increased lease costs or be forced to retrofit the tanker cars we have under lease, which could have an adverse impact on our business both in the cost of the retrofits as well as potential disruption to our production as a result of cars being out of service while they are retrofitted.

Imported ethanol could undermine the ethanol industry in the U.S.

Imported ethanol is no longer subject to any tariffs since December 31, 2011. Since production costs for ethanol in many countries may be less from time to time than what they are in the U.S., the duty-free import of ethanol may negatively affect the demand for domestic ethanol and the price at which we sell our ethanol.

17


Tariffs imposed on ethanol exports to China have recently been increased by the Chinese government and could negatively affect the demand and pricing for ethanol.

The 2017 ethanol tariff for imports into China was increased to 30% as of January 1, 2017; the 2016 ethanol tariff was 5%.  U.S. exports of ethanol to China were at a historical high in 2016, as China was one of the top buyers of U.S. ethanol.  On April 2, 2018, the Chinese government increased the tariff on U.S. ethanol imports into China from 30 to 45 percent.  

We cannot estimate the exact effect this tariff increase will have on the overall domestic ethanol market.  However, the increased tariff is expected to reduce overall U.S. ethanol export demand, which could have a negative effect on U.S. domestic ethanol prices.

The Brazilian government has imposed tariffs on ethanol exports to Brazil, which could negatively affect the demand and pricing for ethanol.

In late August 2017, the Brazilian government imposed a tariff of 20 percent on U.S. ethanol imports which became effective in September 2017. The tariff applies to imports after an initial tax-free quota of 600 million liters, or 158.5 million gallons, per year.  The U.S. exported more than 445 million gallons of ethanol to Brazil in 2017, which was a sixty percent increase in the amount exported to Brazil during 2016.  In the first six months of 2018, ethanol exports to Brazil were up 28 percent over the same period in 2017.  However, as Brazil’s domestic ethanol prices have decreased in recent months due to a large Brazilian sugar harvest, imported ethanol has become more expensive than Brazil’s domestic supply and Brazilian ethanol imports from the U.S. have declined.  We cannot estimate the exact effect this tariff is having on the overall domestic ethanol market.  However, it is possible a tariff at this level could reduce ethanol prices in the domestic market by decreasing export demand for U.S. ethanol.

Regulations governing the production and sale of animal feeds, including distillers’ grains, may change our operating procedures and increase our operating costs, and could affect the export markets for distillers’ grains.

In November 2015, in response to Food Safety and Modernization Act (“FSMA”) implemented in 2011, the Food and Drug Administration (“FDA”) issued final rules for Current Good Manufacturing Practices (“CGMP”): Hazard Analysis, Risk-Based Preventative Controls and Oversight and Management of Preventative Controls for human and animal food facilities. The final rules require FDA-registered food facilities to address safety concerns for sourcing, manufacturing and shipping food products through food safety programs and plans, which includes conducting hazard analyses, developing risk-based preventative controls and monitoring, and addressing intentional adulteration, recalls, sanitary transportation and supplier verification.  The implementation of the final rule varies depending on the size of the organization and other criteria.  We became subject to CGMP compliance beginning September 2017, and preventive controls became effective in September 2018.  We prepared a detailed compliance plan using third party resources and trained our employees on the requirements of FSMA. Implementation of the final regulations has changed certain operating procedures for the production, handling and sale of distillers’ grains.  As we continue to operate within the requirements of FSMA, it may increase our operating and compliance costs.

Actions by the Chinese government may limit the sale of distillers’ grains to China.

China has historically been one of the world’s largest importers of U.S. dry distillers’ grains. In late 2013, the Chinese government signaled its intent to regulate the quality of food imports into China. To achieve this goal, the China AQSIQ (General Administration of Quality Supervision, Inspection and Quarantine) agency indicated that it would require U.S. food producers to register and comply with Chinese food preparation guidelines, and the U.S. government to monitor the production of food products in the U.S. that are exported to China, in a manner similar to the system proposed under the FSMA.

In November 2013, Chinese authorities rejected corn shipments to China because the cargoes included MIR162, a variety of genetically engineered, insect-resistant corn that had been approved in the United States and a number of other countries but not in China. In June 2014, quarantine authorities in China stopped issuing permits for the import of dried distillers’ grains from the United States due to the presence of MIR162 in shipments.

In late December 2014, Chinese officials lifted the ban on MIR162, thereby re-opening the market for distiller’s grains exports to China. Once the ban had been lifted, China resumed imports of distiller’s grains. If China were to reinstate the ban on MIR162 or take similar action, it could decrease demand for distillers’ grains and decrease distillers’ grain prices in the United States’ domestic market by decreasing worldwide demand.

Chinese investigations into United States distillers grains exports into China could negatively affect the demand and pricing for distillers grains.

In January 2016, China’s Ministry of Commerce (“MOC”) launched anti-dumping and countervailing duties investigations into U.S. distillers grains being imported into China. The anti-dumping investigation is in response to claims made by Chinese producers

18


that U.S. distillers grains were being sold at prices below normal value, thereby damaging the domestic industry.  The countervailing duties investigation is in response to claims that U.S. distillers grain exports are subsidized by the U.S. government. On September 23, 2016, China's MOC issued a preliminary duty of 33.8 percent for all producers related to the antidumping investigation on U.S. distillers grain, due at the time of product arrival.  On September 28, 2016, MOC issued preliminary duties of between 10 and 10.7 percent, depending on the producer of the product, related to the countervailing duty investigation on U.S. distillers grain; this is also due at time of product arrival.  These duties were larger than expected and market prices for U.S. distillers began to drop following the imposition of these duties.  In January 2017, China further increased these duties in a final ruling following the investigation.  Distillers grains anti-dumping duties were increased to 42.2 to 53.7 percent and the distillers grains countervailing duties were increased to 11.2 to 12 percent.

China has historically been one of the world’s largest importers of distillers grain. In 2015, it accounted for 50 percent of the U.S. distillers grain exports.  In 2016, distillers grain imports by China were down 50 percent versus 2015 to 3.3 million metric tons, and in 2017, China imported only 416,000 tons of distillers grains.  We cannot estimate the exact effect these duties will have on the overall domestic distillers grains market.  However, the U.S. is the world's largest exporter of distillers grains, and if the duties remain in place, it will likely continue to reduce distillers grains prices in the domestic market by decreasing worldwide demand for distillers grains.

Various studies have criticized ethanol, and could lead to the reduction or repeal of government regulations such as the RFS that promote the use and domestic production of ethanol.

Although many trade groups, academics and governmental agencies have supported ethanol as a fuel additive that promotes a cleaner environment, others have criticized ethanol production as consuming considerably more energy and emitting more greenhouse gases than other biofuels. Other studies have suggested that corn-based ethanol is less efficient than ethanol produced from switch grass or wheat grain and that ethanol’s demand on corn has resulted in higher food prices and shortages. If these views gain widespread acceptance, support for existing measures promoting use and domestic production of corn-based ethanol could decline, leading to reduction or repeal of these measures.

We may be adversely affected by environmental, health and safety laws, regulations and liabilities.

We are subject to extensive air, water and other environmental 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; and the health and safety of our employees. In addition, the plants we operate or manage need to maintain a number of environmental permits. Each ethanol plant we operate and manage is subject to environmental regulation by the State of South Dakota and by the EPA. These laws, regulations and permits can often require expensive pollution control equipment or operational changes to limit actual or potential impacts on the environment. A violation of these laws and regulations or permit conditions can result in substantial fines, natural resource damages, criminal sanctions, permit revocations or facility shutdowns, liability for the costs of investigation or remediation and for damages to natural resources. Our operating subsidiary may also be subject to related claims by private parties alleging property damage and personal injury due to exposure to hazardous or other materials from those plants.

Environmental issues, such as contamination and compliance with applicable environmental standards, could arise at any time during operation of an ethanol plant. If this occurs, our operating subsidiary could be required to spend significant resources to remedy the issues and may limit operation of the ethanol plant. Our operating subsidiary may be liable for the investigation and cleanup of environmental contamination that might exist or could occur at each of the properties that it owns or operates where it handles hazardous substances. If these substances have been or are disposed of or released at sites that undergo investigation or remediation by regulatory agencies, our operating subsidiary may be responsible under the CERCLA (otherwise known as the “Superfund Act”) or other environmental laws for all or part of the costs of investigation and remediation, and for damages to natural resources. Our operating subsidiary may also be subject to related claims by private parties, including our employees and property owners or residents near the plants, alleging property damage and personal injury due to exposure to hazardous or other materials at or from those plants. Additionally, employees, property owners or residents near our ethanol plants could object to the air emissions or water discharges from our ethanol plants. Ethanol production has been known to produce an unpleasant odor. Environmental and public nuisance claims or toxic tort claims could be brought against us as a result of this odor or their other releases to the air or water. Some of these matters may require us to expend significant resources for investigation, cleanup, installation of control technologies or other compliance-related items, or other costs.

Additionally, the hazards and risks associated with producing and transporting our products (such as fires, natural disasters, explosions, abnormal pressures and blowouts) may also result in personal injury claims by third parties or damage to property owned by us or by third parties. We could sustain losses for uninsurable or uninsured events, or in amounts in excess of existing insurance coverage. Events that result in significant personal injury to third parties or damage to property owned by us or third parties or other losses that are not fully covered by insurance could have a material adverse effect on our business, results of operations and financial condition.

19


We also cannot ensure that our operating subsidiary will be able to comply with all necessary permits to continue to operate its ethanol plants. Failure to comply with all applicable permits and licenses could subject our operating subsidiary to future claims or increase costs and materially adversely affect our business, results of operations and financial condition. Additionally, environmental laws and regulations, both at the federal and state level, are subject to change and these changes can be made retroactively. Consequently, even if our operating subsidiary obtains the required permits, it may be required to invest or spend considerable resources to comply with future environmental regulations, such as regulation of greenhouse gasses, or new or modified interpretations of those regulations, which could materially adversely affect our business, results of operations and financial condition. Present and future environmental laws and regulations (and interpretations thereof) applicable to the operations of our operating subsidiary, more vigorous enforcement policies and discovery of currently unknown conditions may require substantial expenditures that could have a material adverse effect on our business, results of operations and financial condition.

Our employees are exposed to the physical hazards of heights, rotating, motorized mechanical and mobile machinery, and equipment and chemicals. Despite procedures, training, physical and engineered barriers and preventative measures, we may still be exposed to liabilities of Occupational Safety and Health Administration fines and incur potential punitive damages as a result of employee injuries that fall outside the workman’s compensation program and insurable losses.

RISKS RELATED TO TAX ISSUES

Income allocations assigned to unit holder units may result in taxable income in excess of cash distributions, which means unit holders may have to pay income tax on their investment with personal funds.

Unit holders will be required to pay tax on their allocated shares of our taxable income. It is likely that a unit holder will receive allocations of taxable income in some years that result in a tax liability that is in excess of any cash distributions we may make to the unit holder in that year. Among other things, this result might occur due to accounting methodology, lending covenants that restrict our ability to pay cash distributions, or our decision to retain the cash generated by the business to fund our operating activities and obligations. In the event unit holders have used prior tax losses to offset non-ABE taxable income, the use of these losses may result in future tax liability.

IRS classification of the company as a corporation rather than as a partnership would result in higher taxation and reduced profits.

We are a Delaware limited liability company that has elected to be taxed as a partnership for federal and state income tax purposes, with income, gain, loss, deduction and credit passed through to the holders of the units. However, if for any reason the IRS successfully determines that we should be taxed as a corporation rather than as a partnership, we would be taxed on our net income at rates of up to 21%, or such lower rate as may be established by Congress, for federal income tax purposes, and all items of our income, gain, loss, deduction and credit would be reflected only on our tax returns and would not be passed through to the holders of the units. If we were to be taxed as a corporation for any reason, distributions we make to investors will be treated as ordinary dividend income to the extent of our earnings and profits, and the payment of dividends would not be deductible by us, thus resulting in double taxation of our earnings and profits. If we pay taxes as a corporation, we will have less cash to distribute to our unit holders. Treatment of our company as a corporation for tax purposes could materially adversely affect our business and financial condition.

We might elect to convert our entity status from a limited liability company to a corporation, which would increase our tax burden.

Although we have no current plans to convert to a corporation, our company might elect in the future to convert to a corporation. If we convert to a corporation, no profits will be allocable to unit holders, there will be no tax liability to our unit holders unless we pay a dividend and our company, as a result, would not make tax distributions to our unit holders with respect to these allocable profits. Conversion to a corporation would require an approval by member vote pursuant to our operating agreement. If we elect to be organized as a corporation, we will be subject to Subchapter C of the Internal Revenue Code. We would be taxed on our net income at rates of up to 21%, or such lower rate as may be established by Congress, for federal income tax purposes, and all items of our income, gain, loss, deduction and credit would be reflected only on our tax returns and would not be passed through to the unit holders. Distributions, if made to investors, would be treated as ordinary dividend income to the extent of our earnings and profits, and the payment of dividends would not be deductible by us, resulting in double taxation of our earnings and profits. If we pay taxes as a corporation, we will also have less cash to distribute to our unit holders. Treatment of our company as a corporation for tax purposes could materially adversely affect our business and financial condition.

The IRS may classify your investment as a passive activity, resulting in the inability of unit holders to deduct losses associated with their investment.

It is likely that an investor’s interest in us will be treated as a “passive activity” for tax purposes. If an investor is an individual, estate, trust or a closely held corporation, and if the investor’s interest is deemed to be a “passive activity,” then the investor’s

20


allocated share of any loss we incur will be deductible only against income or gains the investor has earned from other passive activities. Passive activity losses that are disallowed in any taxable year are suspended and may be carried forward and used as an offset against passive activity income in future years. These rules could restrict a unit holder’s ability to currently deduct any of our losses that are passed through to such unit holder.

An IRS audit could result in adjustments to our allocations of income, gain, loss and deduction, causing additional tax liability to unit holders.

The IRS may audit our income tax returns and may challenge positions taken for tax purposes and allocations of income, gain, loss and deduction to investors. If the IRS were successful in challenging our allocations in a manner that reduces loss or increases income allocable to unit holders, our unit holders may have additional tax liabilities. In addition, such an audit could lead to separate audits of a unit holder’s tax returns, especially if adjustments are required, which could result in adjustments on unit holders’ tax returns. Any of these events could result in additional tax liabilities, penalties and interest to unit holders, and the cost of filing amended tax returns.

 

 

ITEM 2.

PROPERTIES

The table below provides a summary of our ethanol plants in operation as of September 30, 2018. We currently own each of these facilities.

 

Location

 

Opened

 

Estimated

Annual

Ethanol

Production(1)

 

 

Estimated

Annual

Distillers’

Grains

Production(2)

 

 

Estimated

Annual

Corn Oil

Production

 

 

Estimated

Annual Corn

Processed

 

 

Primary

Energy Source

 

 

 

 

(Million gallons)

 

 

(000s Tons)

 

 

(000s lbs)

 

 

(Million bushels)

 

 

 

Aberdeen, SD(3)

 

January 2008

 

 

48

 

 

 

134

 

 

 

11,561

 

 

 

15.7

 

 

Natural Gas

Huron, SD

 

September 1999

 

 

32

 

 

 

97

 

 

 

5,717

 

 

 

11.4

 

 

Natural Gas

Consolidated

 

 

 

 

80

 

 

 

231

 

 

 

17,278

 

 

 

27.1

 

 

 

 

(1)

Actual permitted gallons are 65.7 million for Aberdeen and 42.0 million for Huron totaling 107.7 million gallons.

(2)

Our plants produce and sell wet, modified, and dried distillers’ grains. The stated quantities are on a fully dried basis operating at nameplate capacity.

(3)

Our plant at Aberdeen formerly consisted of two production facilities that operated on a separate basis. The larger plant is represented in table above. In April 2016, the Company ceased operations at its smaller, nine-million gallon facility in Aberdeen due to inefficiencies at this older plant and capital expenditures required to keep the plant in operating condition, coupled with the weak margin environment. In the fourth quarter of fiscal 2016, the Company decided not to resume operations at this facility in the future and, accordingly, impaired the value of this asset on its financial statements to an estimated salvage value of $200,000, which resulted in a loss of $1,584,000 in the fourth quarter of fiscal 2016. During fiscal 2017, the Company received proceeds of $155,000 from the salvage of the smaller plant. At September 30, 2017 the remaining value of the asset on the Company’s financial statement was $45,000. During fiscal 2018, the Company received proceeds of $98,000 from the salvage of the smaller plant.  At September 30, 2018, the remaining value of the asset on the Company’s financial statements was $0.

We currently lease approximately 4,400 square feet for our corporate and administrative staff at our corporate headquarters in Bloomington, Minnesota, through September 2021. The current base rent is $20.00 per square foot, or approximately $7,300 per month for the twelve month that began July 1, 2018, with annual increases of $.50 per square foot. We believe this space will be sufficient for our needs until the end of the lease period.

We believe that each of the operating facilities is in adequate condition to meet our current and future production goals. We believe that these plants are adequately insured for replacement cost plus related disruption expenditures.

Under the ABE South Dakota, LLC security agreement with AgCountry (defined below), AgCountry holds a first priority security interest and mortgage in all inventory, accounts receivable, intangibles, equipment, fixtures, buildings, and a first mortgage in land owned or leased by ABE South Dakota.

 

 

ITEM 3.

LEGAL PROCEEDINGS

None.

 

 

21


ITEM 4.

MINE SAFETY DISCLOSURES

None.

 

 

22


PART II

ITEM  5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

There is no established trading market for our membership units, but since June 2015, our units have been listed on AgStockTrade.com, an internet-based matching platform. Our membership units are subject to substantial transfer restrictions pursuant to our operating agreement, which prohibits transfers without the approval of our board of directors. The board of directors will not approve transfers unless they fall within “safe harbors” contained in the publicly traded partnership rules under the tax code, which include, without limitation, the following:

 

transfers by gift to the member’s descendants;

 

transfers upon the death of a member;

 

transfers between family members; and

 

transfers that comply with the “qualifying matching services” requirements.

Holders

There were 1,603 holders of record of our units as of December 1, 2018.

Issuer Purchases of Equity Securities

We did not purchase any of our equity securities during fiscal 2018.

Distributions

In December 2012, after the sale of our Fairmont, Nebraska facility, we paid a distribution of $4.15 per unit to our unit holders. Our board of directors declared a cash distribution of $0.31 per unit on September 18, 2013, which was paid out in October 2013. In June 2014, our board of directors declared a cash distribution of $0.48 per unit, which was paid out in June 2014. In February 2017, our board of directors declared a cash distribution of $0.15 per unit, which was paid out in February 2017.   Subject to any loan covenants or restrictions with any lenders, we may elect to make future distributions to our members in proportion to the units that each member holds relative to the total number of units outstanding. There can be no assurance that we will ever be able to pay any subsequent distributions to our unit holders.

Our board may elect to retain future profits to provide operational financing for the plants, debt retirement, implementation of new technology and various expansion plans, including development of new product lines. Additionally, our lenders may further restrict our ability to make distributions. Unit holders will be required to report on their income tax return their allocable share of the income, gains, losses and deductions we have recognized without regard to whether we make any cash distributions to our members.

Performance Graph

As disclosed above under “Market Information” and elsewhere in this Form 10-K, there is no established trading market for our membership units, which are subject to substantial transfer restrictions pursuant to our operating agreement. Given that our units are not publicly traded on an exchange or any over-the-counter market and we have very limited valuation data on our membership units, we have omitted the performance graph showing the change in our unit holder return.

Unregistered Sales of Equity Securities

The Company had no unregistered sales of securities in fiscal 2018.

23


Securities Authorized for Issuance under Equity Compensation Plans

The equity securities outstanding as of September 30, 2018 under equity compensation plans are (i) the 200,000 January 18, 2013 Unit Appreciation Right (which was approved by the Company’s unit holders at the 2013 Regular Meeting of Members), (ii) the 12,500 January 28, 2015 Unit Appreciation Right, and (iii) the 100,000 January 27, 2016 Unit Appreciation Right. Each of these equity awards are to the Company’s Chief Executive Officer Richard Peterson. The following table provides information as of September 30, 2018 with respect to Company’s Units under 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 (excluding

securities reflected

in first column)

Equity compensation plans approved by security holders

 

 

200,000

 

 

$

0.21

 

 

None

Equity compensation plans not approved by security holders

 

 

12,500

 

 

$

0.85

 

 

None

Equity compensation plans not approved by security holders

 

 

100,000

 

 

$

1.09

 

 

None

Total

 

 

312,500

 

 

 

 

 

 

None

 

 

24


ITEM 6.

SELECTED FINANCIAL DATA

The following table presents selected consolidated financial and operating data as of the dates and for the periods indicated. The selected consolidated income statement data and other financial data for the years ended September 30, 2015 and 2014 and as of September 30, 2016, 2015 and 2014 have been derived from our audited consolidated financial statements that are not included in this Form 10-K. The selected consolidated balance sheet financial data as of September 30, 2018 and 2017 and the selected consolidated income statement data and other financial data for each of the three years in the period ended September 30, 2018 have been derived from the audited Consolidated Financial Statements included elsewhere in this Form 10-K. You should read the following table in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the accompanying notes included elsewhere in this Form 10-K. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following consolidated financial data.

 

 

 

Years Ended September 30,

 

 

 

2018

 

 

2017

 

 

2016

 

 

2015

 

 

2014

 

 

 

(in thousands, except per unit data)

 

Income statement data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ethanol and related product sales

 

$

133,772

 

 

$

143,532

 

 

$

144,695

 

 

$

151,706

 

 

$

198,347

 

Other revenues

 

 

-

 

 

 

-

 

 

 

183

 

 

 

411

 

 

 

430

 

Total net sales

 

 

133,772

 

 

 

143,532

 

 

 

144,878

 

 

 

152,117

 

 

 

198,777

 

Cost of goods sold

 

 

133,628

 

 

 

130,228

 

 

 

145,367

 

 

 

151,511

 

 

 

165,171

 

Gross profit (loss)

 

 

144

 

 

 

13,304

 

 

 

(489

)

 

 

606

 

 

 

33,606

 

Selling, general and administrative expenses

 

 

2,729

 

 

 

3,798

 

 

 

3,267

 

 

 

2,999

 

 

 

4,833

 

Asset impairment

 

 

-

 

 

 

-

 

 

 

1,584

 

 

 

-

 

 

 

-

 

Operating income (loss)

 

 

(2,585

)

 

 

9,506

 

 

 

(5,340

)

 

 

(2,393

)

 

 

28,773

 

Other income

 

 

259

 

 

 

132

 

 

 

383

 

 

 

434

 

 

 

1,383

 

Other expense

 

 

-

 

 

 

-

 

 

 

(73

)

 

 

(7

)

 

 

-

 

Interest income

 

 

5

 

 

 

11

 

 

 

51

 

 

 

22

 

 

 

35

 

Interest expense

 

 

(736

)

 

 

(880

)

 

 

(914

)

 

 

(147

)

 

 

(710

)

Net Income (loss)

 

 

(3,057

)

 

 

8,769

 

 

 

(5,893

)

 

 

(2,091

)

 

 

29,481

 

Basic weighted units outstanding

 

 

25,411

 

 

 

25,411

 

 

 

25,411

 

 

 

25,411

 

 

 

25,411

 

Diluted weighted units outstanding

 

 

25,411

 

 

 

25,411

 

 

 

25,411

 

 

 

25,411

 

 

 

25,411

 

Income (loss) per unit basic

 

$

(0.12

)

 

$

0.35

 

 

$

(0.23

)

 

$

(0.08

)

 

$

1.16

 

Income (loss) per unit diluted

 

$

(0.12

)

 

$

0.35

 

 

$

(0.23

)

 

$

(0.08

)

 

$

1.16

 

 

 

 

As of September 30,

 

 

 

2018

 

 

2017

 

 

2016

 

 

2015

 

 

2014

 

 

 

(In thousands)

 

Balance sheet data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

12,727

 

 

$

18,804

 

 

$

15,416

 

 

$

16,566

 

 

$

21,982

 

Property and equipment, net

 

 

32,211

 

 

 

31,226

 

 

 

32,231

 

 

 

41,155

 

 

 

49,644

 

Total assets

 

 

55,434

 

 

 

61,629

 

 

 

60,033

 

 

 

72,788

 

 

 

87,617

 

Total debt

 

 

19,738

 

 

 

24,366

 

 

 

27,593

 

 

 

32,654

 

 

 

45,563

 

Total equity

 

 

28,423

 

 

 

31,480

 

 

 

26,523

 

 

 

32,416

 

 

 

34,507

 

 

 

 

25


ITEM  7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

The following discussion and analysis provides information that management believes is relevant to an assessment and understanding of our consolidated financial condition and results of operations. This discussion should be read in conjunction with the consolidated financial statements included herewith and the notes to the consolidated financial statements thereto and the risk factors contained herein.

This Management’s Discussion and Analysis section discusses the Company’s results of operations for the years ending September 30, 2018, 2017 and 2016, together with its balance sheets as of September 30, 2018, and 2017.

OVERVIEW

Advanced BioEnergy, LLC (“Company,” “we,” “our,” “Advanced BioEnergy” or “ABE”) was formed in 2005 as a Delaware limited liability company. Our business consists of producing ethanol and co-products, including wet, modified and dried distillers’ grains, and corn oil. Ethanol is a renewable, environmentally clean fuel source that is produced at numerous facilities in the United States, mostly in the Midwest. In the U.S., ethanol is produced primarily from corn and then blended with unleaded gasoline in varying percentages. The ethanol industry in the U.S. has grown significantly as the use of ethanol reduces harmful auto emissions, enhances octane ratings of the gasoline with which it is blended, offers consumers a cost-effective choice, and decreases the amount of crude oil the U.S. needs to import from foreign sources.

To execute our business plan, in November 2006 we acquired ABE South Dakota, LLC (“ABE South Dakota”)(f/k/a Heartland Grain Fuels, LP), which owned existing ethanol production facilities in Aberdeen and Huron, South Dakota. We began construction of our new facility in Aberdeen, South Dakota in April 2007, and began operations in January 2008. Our production operations are carried out primarily through our operating subsidiary ABE South Dakota which owns and operates ethanol facilities in Aberdeen and Huron, South Dakota.

Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources in assessing performance. Based on the related business nature and expected financial results, the Company’s plants are aggregated into one reporting segment.

 

Location

 

Opened

 

Estimated

Annual Ethanol

Production(1)

 

 

Estimated

Annual

Distillers’

Grains

Production(2)

 

 

Estimated

Annual

Corn Oil

Production

 

 

Estimated

Annual Corn

Processed

 

 

Primary

Energy Source

 

 

 

 

(Million gallons)

 

 

(000s Tons)

 

 

(000s lbs)

 

 

(Million bushels)

 

 

 

Aberdeen, SD(3)

 

January 2008

 

 

48

 

 

 

134

 

 

 

11,561

 

 

 

15.7

 

 

Natural Gas

Huron, SD

 

September 1999

 

 

32

 

 

 

97

 

 

 

5,717

 

 

 

11.4

 

 

Natural Gas

Consolidated

 

 

 

 

80

 

 

 

231

 

 

 

17,278

 

 

 

27.1

 

 

 

 

(1)

Actual permitted gallons are 65.7 million for Aberdeen and 42.0 million for Huron totaling 107.7 million gallons.

(2)

Our plants produce and sell wet, modified, and dried distillers’ grains. The stated quantities are on a fully dried basis operating at full production capacity.

(3)

Our plant at Aberdeen formerly consisted of a single production facility that is represented in the table above. Prior to April 2016, we also operated a smaller, nine-million gallon Aberdeen facility. We closed this smaller plant in April 2016 due to inefficiencies and the ongoing capital expenditures required to keep it in operating condition, coupled with the weak margin environment. We decided during our fiscal 2016 fourth quarter not to resume operations at this facility in the future and, accordingly, impaired the value of this asset on our financial statements to an estimated salvage value of $200,000, which resulted in a loss of $1,584,000 in the fourth quarter of fiscal 2016. During fiscal 2017, the Company received proceeds of $155,000 from the salvage of the smaller plant. At September 30, 2017 the remaining value of the asset on the Company’s financial statement was $45,000. During fiscal 2018, the Company received proceeds of $98,000 from the salvage of the smaller plant.  At September 30, 2018, the remaining value of the asset on the Company’s financial statements was $0.

We believe that each of the operating facilities is in adequate condition to meet our current and future production goals. We believe that these plants are adequately insured for replacement cost plus related disruption expenditures.

26


PLAN OF OPERATIONS THROUGH SEPTEMBER 30, 2019

Over the next year we will continue our focus on operational improvements at our South Dakota operating facilities, including completion of the grain storage and receiving facility we are constructing at our Aberdeen plant. These operational improvements include exploring methods to improve ethanol yield per bushel and increasing production output at each of our plants, continued emphasis on safety and environmental regulation, reducing our operating costs, and optimizing our margin opportunities through prudent risk-management policies.

RESULTS OF OPERATIONS

Year Ended September 30, 2018 Compared to Year Ended September 30, 2017

The following table reflects quantities of our products sold at average net prices as well as bushels of corn ground and therms of natural gas burned at average costs for fiscal 2018 and fiscal 2017 for our South Dakota plants:

 

 

 

Year Ended

September 30, 2018

 

 

Year Ended

September 30, 2017

 

Product Sales Information

 

Quantity

 

 

Average Price

 

 

Quantity

 

 

Average Price

 

 

 

(In thousands)

 

 

 

 

 

 

(In thousands)

 

 

 

 

 

Ethanol (gallons)

 

 

83,869

 

 

$

1.23

 

 

 

84,742

 

 

$

1.39

 

Distillers grains (tons)

 

 

209

 

 

$

128.06

 

 

 

210

 

 

$

96.91

 

Corn Oil (pounds)

 

 

20,273

 

 

$

0.20

 

 

 

19,551

 

 

$

0.25

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product Cost Information

 

Quantity

 

 

Average Cost

 

 

Quantity

 

 

Average Cost

 

Corn (bushels)

 

 

29,357

 

 

$

3.25

 

 

 

29,517

 

 

$

3.15

 

Natural Gas (therms)

 

 

2,106

 

 

$

3.92

 

 

 

2,123

 

 

$

3.36

 

 

Net Sales

Net sales for fiscal 2018 were $133.8 million, compared to $143.5 million for fiscal 2017, a decrease of $9.7 million or 7%. The decrease was a result of lower ethanol and corn oil prices combined with a decrease in ethanol gallons and distillers’ tons sold, partially offset by an increase in distillers’ price and corn oil pounds sold. The decrease in ethanol and increase in distillers prices is the result of various factors, including but not limited to, market demand for our products, the spread between ethanol/distillers, corn prices and overall gasoline demand. Ethanol gallons sold decreased 0.9 million gallons or 1% in fiscal 2018, compared to fiscal 2017. Corn oil pounds sold increased 0.7 million pounds or 4% in fiscal 2018, compared to fiscal 2017. The increase in corn oil pounds sold is the result of increased production efficiency at both plants.

Cost of Goods Sold

Cost of goods sold for fiscal 2018 was $133.6 million, compared to $130.2 million for fiscal 2017, an increase of $3.4 million. An increase in corn and natural gas costs represented a portion of the increase in cost of goods sold in fiscal 2018. Corn costs represented 72.0% and 71.6% of cost of sales for the fiscal years 2018 and 2017, respectively. Corn prices increased approximately 3% in fiscal 2018 from fiscal 2017; however, we used 1% fewer corn bushels in fiscal 2018 than in fiscal 2017, due to lower ethanol production in fiscal 2018.

Natural gas costs represented 6.2% and 5.5% of cost of sales for fiscal years 2018 and 2017, respectively. The cost of natural gas per mmbtu increased 17% in fiscal 2018, compared to fiscal 2017. The increased cost of natural gas in fiscal 2018 was due to lower stocks coming out of the withdrawal season, which is the colder season from November through March, in 2017.  These lower stock levels drove prices higher in fiscal 2018.  

Selling, General, and Administrative Expenses

Selling, general and administrative expenses consist primarily of recurring administrative personnel compensation, legal, technology, consulting, insurance and accounting fees.

Overall selling, general and administrative costs decreased by approximately $1.1 million to $2.7 million in fiscal 2018, compared to fiscal 2017. The decrease was primarily a result of higher costs in fiscal 2017 related to the tear down of the smaller Aberdeen plant, certain taxes paid in connection with transporting our ethanol in the state of Washington, and employee incentive compensation.  As a percentage of net sales, fiscal 2018 selling, general and administrative expenses decreased to 2.0%, compared to 2.6% for fiscal 2017.

27


Interest Expense

Interest expense for fiscal 2018 was $0.7 million compared to $0.9 million in fiscal 2017. Fiscal 2018 interest expense included $0.6 million of variable rate interest related to our outstanding debt and $0.1 million of amortization of deferred financing costs. Fiscal 2017 interest expense included $0.8 million of variable rate interest related to our outstanding debt and $0.1 million of amortization of deferred financing costs.

Year Ended September 30, 2017 Compared to Year Ended September 30, 2016

The following table reflects quantities of our products sold at average net prices as well as bushels of corn ground and therms of natural gas burned at average costs for fiscal 2017 and fiscal 2016 for our South Dakota plants:

 

 

 

Year Ended

September 30, 2017

 

 

Year Ended

September 30, 2016

 

Product Sales Information

 

Quantity

 

 

Average Cost

 

 

Quantity

 

 

Average Cost

 

 

 

(In thousands)

 

 

 

 

 

 

(In thousands)

 

 

 

 

 

Ethanol (gallons)

 

 

84,742

 

 

$

1.39

 

 

 

87,790

 

 

$

1.32

 

Distillers grains (tons)

 

 

210

 

 

$

96.91

 

 

 

231

 

 

$

112.79

 

Corn Oil (pounds)

 

 

19,551

 

 

$

0.25

 

 

 

10,566

 

 

$

0.23

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Product Cost Information

 

Quantity

 

 

Average Price

 

 

Quantity

 

 

Average Price

 

Corn (bushels)

 

 

29,517

 

 

$

3.15

 

 

 

30,649

 

 

$

3.34

 

Natural Gas (therms)

 

 

2,123

 

 

$

3.36

 

 

 

2,311

 

 

$

2.62

 

 

Net Sales

Net sales for fiscal 2017 were $143.5 million, compared to $144.9 million for fiscal 2016, a decrease of $1.4 million or 1%. The decrease was a result of lower distillers’ prices combined with a decrease in ethanol gallons and distillers’ tons sold, partially offset by an increase in corn oil prices and pounds sold. The increase in ethanol and decrease in distillers prices is the result of various factors including but not limited to market demand for our products, the spread between ethanol/distillers, corn prices and overall gasoline demand. Ethanol gallons sold decreased 3.0 million gallons or 5% in fiscal 2017, compared to fiscal 2016. Corn oil pounds sold were higher in fiscal 2017 due to the Huron corn oil system starting production in October 2016, as well as increased production efficiency in our Aberdeen corn oil system.

Cost of Goods Sold

Cost of goods sold for fiscal 2017 was $130.2 million, compared to $145.4 million for fiscal 2016, a decrease of $15.2 million. A decrease in corn costs represented a portion of the decrease in cost of goods sold in fiscal 2017. Corn costs represented 71.6% and 70.4% of cost of sales for the fiscal years 2017 and 2016, respectively. Corn prices decreased approximately 6% in fiscal 2017 from fiscal 2016, and we used 5% fewer corn bushels in fiscal 2017 than in fiscal 2016, due to lower ethanol production in fiscal 2017.

Natural gas costs represented 5.5% and 4.2% of cost of sales for fiscal years 2017 and 2016, respectively. The cost of natural gas per mmbtu increased 30% in fiscal 2017, compared to fiscal 2016. The increased cost of natural gas in fiscal 2017 was due to elevated stocks coming out of the withdrawal season in 2016, which drove prices lower in fiscal 2016.  

The estimated useful life of process equipment was re-evaluated and adjusted from 10 years to 15 years in the prior year.  As a result of this change in estimate, depreciation expense was reduced approximately $5.3 million in fiscal 2017 compared to fiscal 2016.

Selling, General, and Administrative Expenses

Selling, general and administrative expenses consist primarily of recurring administrative personnel compensation, legal, technology, consulting, insurance and accounting fees.

Overall selling, general and administrative costs increased by approximately $0.5 million to $3.8 million in fiscal 2017, compared to fiscal 2016. As a percentage of net sales, fiscal 2017 selling, general and administrative expenses increased to 2.6%, compared to 2.2% for fiscal 2016.

28


Asset Impairment

Expense related to asset impairment for fiscal 2017 was zero, compared to $1.6 million for fiscal 2016. The expense in fiscal 2016 was the result of the Company’s decision not to resume operations at its smaller Aberdeen plant in the fourth quarter of fiscal 2016.

Interest Expense

Interest expense for fiscal 2017 and fiscal 2016 was $0.9 million. Fiscal 2017 interest expense included $0.8 million of variable rate interest related to our outstanding debt and $0.1 million of amortization of deferred financing costs. Fiscal 2016 interest expense included $1.1 million of variable rate interest related to our outstanding debt and $0.1 million of amortization of deferred financing costs.  These fiscal 2016 interest expense items were offset by $0.3 million of deferred gain resulting from the troubled debt restructuring that occurred in 2010.

As a result of debt sweep payments made to the 2010 Credit Agreement during fiscal 2016, the carrying value of the debt exceeded the scheduled principal and interest payments remaining over the term of the loan. Therefore, as a result of the final payment on the 2010 Credit Agreement in fiscal 2016, a gain of approximately $325,000 was recognized as other income during the fiscal year ended September 30, 2016.  

Changes in Financial Position for the Year ended September 30, 2018

Current Assets

The decrease in current assets at September 30, 2018 compared to September 30, 2017 of $6.9 million was primarily due to principal payments of $4.7 million and capital expenditures of $4.2 million, offset by cash from operations of $1.5 million.

Property, Plant and Equipment

The $1.0 million increase in property, plant and equipment at September 30, 2018 compared to September 30, 2017 was primarily due to $4.2 million of cash and $0.7 million of capital expenditures in accounts payable, offset by $3.9 million of depreciation expense.

Current Liabilities

Accounts payable and accrued expenses increased by $1.5 million at September 30, 2018 compared to September 30, 2017. The primary reason for the increase is a difference of timing of payments to vendors, which includes $0.7 million related to the Aberdeen grain storage project.

Current Portion of Long-Term Debt and Long-term Debt

The current portion of long-term debt decreased by $3.7 million at September 30, 2018 compared to September 30, 2017. The decrease was due to making the final payment of the 2016 Term Loan in July 2018 and $3.0 million debt payments being deferred as part of the Fourth Amendment to the credit agreement, defined below.

Long-term debt decreased by $1.0 million at September 30, 2018 compared to September 30, 2017. This decrease was due to $4.0 million in debt payments, offset by $3.0 million of deferred debt payments as described above.

CAPITAL RESOURCES

During fiscal 2018, we conducted our business activities and plant operations through the parent company, Advanced BioEnergy, and its primary operating subsidiary, ABE South Dakota. ABE Fairmont has had minimal activity since the December 2012 sale of the Fairmont facility. The liquidity and capital resources for each entity are based on that entity’s existing financing arrangements and capital structure. Advanced BioEnergy is highly restricted in its ability to use the cash and other financial resources of ABE South Dakota for the benefit of Advanced BioEnergy, with the exception of allowable distributions as defined under the 2015 Credit Agreement with AgCountry.

Advanced BioEnergy, LLC (“ABE”)

ABE had cash and cash equivalents of $1.2 million on hand at September 30, 2018. ABE did not have any debt outstanding as of September 30, 2018.

29


From time to time, ABE may receive certain allowable distributions from ABE South Dakota, subject to compliance with the terms and conditions of the 2015 Credit Agreement. ABE will not receive any distribution from ABE South Dakota for its fiscal 2018 financial results.

In connection with the execution of a rail car sublease, the Company, as parent of ABE South Dakota, agreed to post a $2.5 million irrevocable and non-transferable standby letter of credit in May 2012 for the benefit of NGL Crude Logistics, LLC (“NGL” f/k/a Gavilon) as security for the payment obligations of ABE South Dakota under certain agreements with NGL. The Company deposited $2.5 million in a restricted account as collateral for this letter of credit and classified it as restricted cash. Effective May 15, 2014, the letter of credit and corresponding deposit of collateral were decreased by $1.0 million in conjunction with an amendment to the rail car sublease. Effective June 27, 2016, the letter of credit and corresponding deposit of collateral was decreased by $0.5 million in conjunction with an amendment to the rail car sublease. Effective July 31, 2018, the letter of credit was terminated and the corresponding collateral requirement was eliminated.

We believe ABE has sufficient financial resources available to fund current operations and capital expenditure requirements for at least the next 12 months.

ABE Fairmont

ABE Fairmont had no cash and cash equivalents on hand at September 30, 2018. ABE Fairmont has agreed to cooperate with Flint Hills Resources, LLC with respect to post-closing matters, including completing the transfer of certain railway lines. The Company anticipates that ABE Fairmont will remain in existence as a separate entity until it completes all its obligations under the asset purchase agreement and other ongoing agreements, except to the extent that the Company determines that it can perform these obligations itself after the liquidation of ABE Fairmont.

ABE South Dakota

ABE South Dakota had cash and cash equivalents of $11.5 million on hand at September 30, 2018. As of September 30, 2018, ABE South Dakota had interest-bearing term debt outstanding of $20.0 million.

2015 Senior Credit Agreement

On December 29, 2015, ABE South Dakota entered into a Master Credit Agreement (“2015 Credit Agreement”) with AgCountry Farm Credit Services, PCA as lender, (“AgCountry”) to refinance its existing 2010 Senior Credit Agreement. On December 29, 2015, the Company also entered into (i) a First Supplement to the 2015 Credit Agreement covering a $10.0 million Revolving Term Facility and (ii) a Second Supplemental covering a $20.0 million Term Loan. The transaction funded on December 30, 2015.

The $20.0 million Term Loan had a variable interest rate (“Variable Rate”) equal to the one-month LIBOR rate plus a “Margin” of 350 basis points at September 30, 2018. Subsequent to the end of the fiscal year, on October 26, 2018, the Company elected to lock in a fixed interest rate of 6.4%, rather than the Variable Rate, on the remaining balance of the Term Loan.  The Company may elect one or more fixed or adjustable interest rates, rather than the Variable Rate, based on AgCountry’s cost of funds at the time of the election, plus the Margin. Any election must apply to $1.0 million or more owing on the Term Loan. Beginning April 1, 2016, the Company began making quarterly principal payments of $1.0 million, plus accrued interest, on the Term Loan. The Term Loan will be fully amortized over five years with the final payment on January 1, 2021.  At September 30, 2018, the balance of the Term Loan was $10.0 million.

The $10.0 Revolving Term Facility has a Variable Rate equal to the one month LIBOR rate plus an initial Margin of 350 basis points. The applicable LIBOR interest rate at November 30, 2018 was 2.29%. Borrowings under the Revolving Term Facility may be advanced, repaid and re-borrowed during the term. The Company is required to make quarterly interest payments on the Revolving Term Facility, with the full principal amount outstanding due on January 1, 2021. Under the Revolving Term Facility, the Company is required to pay unused commitment fees of 50 basis points. At September 30, 2018, the balance of the Revolving Term Facility was $10.0 million.

The Margin will (i) decrease to 3.25% when the aggregate principal balance of all outstanding loans and the unfunded commitment level is $20.0 million or less, and (ii) decrease to 3.00% when this amount is $15.0 million or less.

ABE South Dakota, LLC also entered into a Security Agreement with AgCountry under which borrowings under the 2015 Credit Agreement are secured by substantially all of ABE South Dakota’s assets. AgCountry holds a first priority security interest and mortgage in all inventory, accounts receivable, intangibles, equipment, fixtures, buildings, and a first mortgage in land owned or leased by ABE South Dakota.

30


The 2015 Credit Agreement also included customary financial and non-financial covenants that limit capital expenditures, distributions and debt and require minimum working capital, owner’s equity, current ratio, debt to EBITDA ratio, and fixed charge coverage ratios as follows:

 

ABE South Dakota has a minimum working capital requirement of $10.0 million beginning at loan closing, increasing to $12.75 million at September 30, 2016 and thereafter. Working capital is calculated as (i) (a) current assets plus (b) the amount available under the Revolving Term Facility, less (ii) current liabilities, measured quarterly.

 

ABE South Dakota’s owner’s equity ratio was the ratio of (i) net worth divided by (ii) total assets. This ratio was to be measured annually at fiscal year-end and would have increased by 2% each fiscal year, from 40% at September 30, 2015, until a 50% ratio was achieved and maintained. This covenant was eliminated by the First Amendment (as defined below).

 

ABE South Dakota must maintain a ratio of current assets to current liabilities of not less than 1.2 to 1.0.

 

ABE South Dakota’s debt to EBITDA ratio must be less than 4.00:1.00. Debt is defined as total interest bearing debt, while EBITDA is defined as earnings before interest, taxes, depreciation, and amortization. The debt to EBITDA ratio will be measured quarterly, but tested annually at each fiscal year end.

 

ABE South Dakota’s minimum fixed charge coverage ratio is 1.15:1.00 and is measured quarterly, but tested annually at each fiscal year end. The fixed charge coverage ratio is calculated by dividing EBITDA by the sum of scheduled payments of principal and interest, capital expenditures, any cash taxes, and distributions. When ABE South Dakota has achieved and maintained an owners’ equity ratio of 60.0% and working capital of $15.0 million, then the minimum fixed charge coverage ratio requirement will be reduced to 1.00:1.00. If the owners’ equity ratio subsequently declines below 60.0%, or working capital declines below $15.0 million, then the 1.15:1.00 minimum fixed charge ratio covenant will be reinstated.

 

ABE South Dakota is limited to annual capital expenditures of $2.0 million without prior consent of AgCountry, and is limited from incurring additional debt over certain amounts without prior approval, and making additional investments without prior approval of AgCountry.

 

ABE South Dakota is also prohibited from making member distributions in excess of 40% of pre-tax net income in a given year without the prior consent of Ag Country. When ABE South Dakota achieves and maintains owners’ equity ratio of 60.0% and working capital of $15.0 million, then it may pay member dividends of 100.0% of pre-tax net income. If the owner’s equity ratio declines below 60.0%, or working capital declines below $15.0 million, then dividends will be restricted until ABE South Dakota regains compliance. ABE South Dakota must meet all loan covenants before and after any distribution.

A number of these covenants have been amended in connection with subsequent term loans, a construction loan, and amendments and waivers as described below.

2016 Term Loan

On September 28, 2016, ABE South Dakota entered into the Third Supplement to the 2015 Credit Agreement (“2016 Term Loan”) with AgCountry to finance the corn oil extraction system at the Huron plant.  The total loan commitment for the 2016 Term Loan was $1.7 million, and the loan has a variable interest rate equal to the one-month LIBOR rate plus a “Margin” of 350 basis points.  Beginning January 1, 2017, the Company began making quarterly payments of accrued interest on the 2016 Term Loan. A total of $1.1 million of the $1.7 million commitment was drawn from this loan. On April 1, 2017, the Company began making quarterly principal payments of $212,500 on the 2016 Term Loan. As of September 30, 2018 the 2016 Term Loan was paid in full.

2018 Construction and Term Loan

On March 13, 2018, ABE South Dakota entered into the Fourth Supplement to the 2015 Credit Agreement (“2018 Term Loan”) with AgCountry to finance a grain storage and receiving facility at the Aberdeen plant. The agreement provides for a $5.0 million multiple advance credit facility. The loan has a variable interest rate equal to the one-month LIBOR rate plus a “Margin” of 350 basis points.  During the construction period, the Company will make quarterly interest payments in arrears on the first day of each quarter.  Upon completion of construction, the Company will begin making quarterly principal payments in the amount of $250,000 per quarter, plus accrued interest. The 2018 Term Loan will be fully amortized over five years, with the final payment on July 1, 2024.  At September 30, 2018, no funds had been drawn on the 2018 Term Loan, and $47,000 in loan fees and closing costs had been incurred, which have been classified as deferred financing costs and will be amortized as interest expense over the term of the loan.

Amendment and Waivers to 2015 Credit Agreement

On September 28, 2016, ABE South Dakota entered into a Limited Waiver and First Amendment to the 2015 Credit Agreement (“First Amendment”) to (i) eliminate the Owner’s Equity Ratio Covenant, (ii) temporarily increase the Capital Expenditures Covenant

31


to $3.0 million for fiscal 2016 to finance the corn oil extraction system at the Huron plant, and (iii) waive other post-closing obligations.  

On November 19, 2016, ABE South Dakota received a waiver to the 2015 Credit Agreement from AgCountry that waived certain Events of Default related to the Working Capital requirement and the Total Outstanding Debt to EBITDA Ratio at September 30, 2016.

On October 16, 2017, ABE South Dakota received a waiver to the 2015 Credit Agreement from AgCountry that waived an Event of Default related to the Capital Expenditure Covenant for fiscal 2017. The Capital Expenditure Covenant for fiscal 2016 was increased to $3.0 million due to the addition of the corn oil extraction system at Huron. However, a portion of the capital expenditure cost was incurred in fiscal 2017, so an additional waiver was granted for this period.

On March 13, 2018, in conjunction with the 2018 Term Loan, ABE South Dakota entered into a Second Amendment to the 2015 Credit Agreement (“Second Amendment”) to temporarily increase the Capital Expenditures Covenant to $6.0 million per year for the years ending September 30, 2018 and 2019.  The covenant will revert back to $2.0 million per year for all years ending after September 30, 2019.  

On October 19, 2018, ABE South Dakota entered into a Limited Waiver and Third Amendment to the 2015 Credit Agreement (“Third Amendment”) to waive certain Events of Default related to covenant compliance as of September 30, 2018 and temporarily amend certain future covenants.  The Third Amendment included the following covenant waiver and amendments: (i) the Fixed Charge Coverage Ratio was waived as of September 30, 2018 and reduced to a ratio of 1.00:1.00 as of September 30, 2019, and reverts back to 1.15:1.00 at September 30, 2020, (ii) the Working Capital Covenant was reduced to $10 million at September 30, 2018 and December 31, 2018, $9 million at March 31, 2019 and June 30, 2019, then increased to $10 million at September 30, 2019 and $12 million at September 30, 2020 and all times thereafter, (iii) the Capital Expenditures covenant was increased to $8.0 million for the year ending September 30, 2019, and reverts back to $2.0 million for all subsequent years, and (iv) the outstanding Debt to EBITDA Ratio was waived at September 30, 2018 and will revert back to the requirement that it be less than 4:00:1:00 on the last day of each fiscal year end beginning September 30, 2019.

On December 28, 2018, ABE South Dakota entered into a Limited Waiver and Deferral Agreement and Fourth Amendment to the 2015 Credit Agreement (“Fourth Amendment”) to defer three future principal payments and waive and temporarily amend certain future covenants.  The Fourth Amendment included the following covenant waivers and amendments:  

 

(i)

defer the next three principal payments due January 1, April 1, and July 1, 2019 until the Term Loan maturity date on January 1, 2021;

 

(ii)

waive the Fixed Charge Coverage Ratio at September 30, 2019,

 

(iii)

amend the Working Capital Covenant to $4 million at December 31, 2018 and subsequent months until increasing to $5 million at September 30, 2020, and increasing to $12 million at September 30, 2021,

 

(iv)

waive the September 30, 2019 Debt to EBITDA Ratio, and

 

(v)

add a Cash Sweep Covenant whereby ABE South Dakota would be required to pay additional principal at the end of each fiscal year in the amount of 30 percent of Free Cash Flow.  In order for a Cash Sweep payment to be made, ABE South Dakota must remain in compliance with all covenants before and after the payment.  Free Cash Flow is defined as: fiscal year EBITDA less interest expense, scheduled principal payments, and non-financed maintenance capital expenditures.  The Fourth Amendment would also restrict future dividend payments until all covenants revert back to originally set levels.

2010 Senior Credit Agreement

ABE South Dakota entered into an Amended and Restated Senior Credit Agreement effective as of June 18, 2010, and amended on December 9, 2011 (the “2010 Senior Credit Agreement”) among ABE South Dakota, the lenders from time to time party thereto, and an Administrative Agent and Collateral Agent. The principal amount of the term loan facility was payable in quarterly payments of $750,000, with the remaining principal amount fully due and payable on March 31, 2016. Loans outstanding under the 2010 Senior Credit Agreement were subject to mandatory prepayment in certain circumstances, including, but not limited to, mandatory prepayments based upon receipt of certain proceeds of asset sales, casualty proceeds, termination payments, and cash flows.

ABE South Dakota agreed to pay a $3.0 million restructuring fee to the lender due at the earlier of March 31, 2016 and the date on which the loans were repaid in full. ABE South Dakota recorded the restructuring fee as long-term, non-interest bearing debt. ABE South Dakota was also obligated to pay the final installment of a waiver fee to the senior lenders in March 2016. The original waiver fee was $275,000 of which $68,750 was payable in March 2016. The Company recorded this fee as non-interest bearing debt on its consolidated balance sheet, and amortized the fee to interest expense over the remaining life of the debt.

32


In connection with closing the 2015 Credit Agreement, ABE South Dakota paid in full all amounts outstanding under the 2010 Senior Credit Agreement, including $29.0 million of principal, accrued interest, the $3.0 restructuring fee, and the waiver fee of $68,750, and all security interests of the prior lenders were extinguished.

CASH FLOWS

The following table shows our cash flows for the years ended September 30:

 

 

 

Years Ended September 30

 

 

 

2018

 

 

2017

 

 

2016

 

 

 

(In thousands)

 

 

(In thousands)

 

 

(In thousands)

 

Net cash provided by operating activities

 

$

1,508

 

 

$

13,186

 

 

$

1,723

 

Net cash used in investing activities

 

 

(3,861

)

 

 

(2,663

)

 

 

(2,416

)

Net cash used in financing activities

 

 

(4,724

)

 

 

(7,135

)

 

 

(4,069

)

 

 

Cash Flow from Operations

Our cash flows from operations in fiscal 2018 were lower compared to fiscal 2017, primarily due to decreased margins in fiscal 2018.

Our cash flows from operations in fiscal 2017 were higher compared to fiscal 2016, primarily due to increased margins in fiscal 2017.

Cash Flow from Investing Activities

We used more cash for investing activities in fiscal 2018 compared to fiscal 2017, primarily as a result of $4.2 million spent on capital expenditures in fiscal 2018 compared to $3.0 million in fiscal 2017.

We used more cash from investing activities in fiscal 2017 compared to fiscal 2016, primarily as a result of $3.0 million spent on capital expenditures in fiscal 2017 compared to $2.6 million in fiscal 2016.

Cash Flow from Financing Activities

We used less cash for financing activities in fiscal 2018 versus 2017 primarily due to a $3.8 million distribution to unit holders in fiscal 2017. This was offset by $1.1 million drawn from the 2016 Term Loan for the Huron corn oil project in fiscal 2017. It was also offset by debt payments of $4.7 million in fiscal 2018 versus $4.4 million in fiscal 2017.

We used more cash for financing activities in fiscal 2017 versus 2016 primarily due to a $3.8 million distribution to unit holders. This was offset by $1.1 million drawn from the 2016 Term Loan for the Huron corn oil project.  In fiscal 2016, we received $30.0 million in proceeds from the 2015 Credit Agreement and used $34.1 million for payments on debt, including $2.0 million toward normal principal payments and $32.1 million to satisfy all remaining obligations of the 2010 Senior Credit Agreement.  This resulted in a net use of cash from financing activities of $4.1 million in fiscal 2016.    

CREDIT ARRANGEMENTS

A summary of debt in effect at September 30, 2018 is as follows (in thousands, except percentages):

 

 

 

September 30,

2018

Interest Rate

 

 

September 30,

2018

 

 

September 30,

2017

 

ABE South Dakota:

 

 

 

 

 

 

 

 

 

 

 

 

Senior debt principal—variable

 

 

5.57

%

 

 

20,000

 

 

 

24,677

 

Deferred financing costs

 

N/A

 

 

 

(262

)

 

 

(311

)

Total outstanding

 

 

 

 

 

$

19,738

 

 

$

24,366

 

33


CONTRACTUAL OBLIGATIONS

The following table summarizes our contractual obligations as of September 30, 2018.

 

 

 

Years Ending September 30,

 

 

 

2019

 

 

2020

 

 

2021

 

 

2022

 

 

2023

 

 

Thereafter

 

 

Total

 

Long-term debt obligations(1)

 

$

905

 

 

$

3,895

 

 

$

14,967

 

 

$

(10

)

 

$

(9

)

 

$

(10

)

 

$

19,738

 

Operating lease obligations(2)

 

 

3,413

 

 

 

2,777

 

 

 

2,529

 

 

 

1,839

 

 

 

1,134