UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
DC 20549




FORM
10-K


þ
            
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
      1934.FOR
      THE FISCAL YEAR ENDED DECEMBER 31, 2009o
            
            TRANSITION
      REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
      1934FOR THE TRANSITION PERIOD
      FROM            TO




COMMISSION
FILE NUMBER: 000-1359687




RED
TRAIL ENERGY, LLC


(Exact
name of registrant as specified in its charter)


NORTH
      DAKOTA
            
            76-0742311(State
      or other jurisdiction
            
            (IRS
      Employerof
      incorporation or organization)
            
            Identification
      No.)




P.O. Box
11


3682
Highway 8 South


Richardton,
ND 58652


(Address
and Zip Code of Principal Executive Offices)




(Registrant’s
telephone number, including area code): (701) 974-3308




Securities
register pursuant to Section 12(b) of the Exchange Act: None




Securities
registered under Section 12(g) of the Exchange Act: Class A 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 o No þ




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




Indicated
by checkmark 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 þ No o




Indicate
by check mark if disclosures of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. o




Indicate
by checkmark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated filer and
large accelerated filer in Rule 12b-2 of the Exchange Act. (Check
one):




Large
accelerated filer o
     Accelerated Filer o
     Non-accelerated filer þ    Smaller
Reporting Company o




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




The
aggregate market value of the membership units held by non-affiliates of the
registrant as of June 30, 2009 was $34,080,812.  There is no
established public trading market for our membership units.  The
aggregate market value was computed by reference to the most recent offering
price of our Class A units which was $1 per unit.




As
of March 31, 2010 the Company has 40,193,973 Class A Membership Units
outstanding.










TABLE
OF CONTENTS




PART
      I
              
              
              2ITEM
      1. BUSINESS
              
              
              2ITEM
      1A. RISK FACTORS
              
              
              10ITEM
      2. PROPERTIES
              
              
              16ITEM
      3. LEGAL PROCEEDINGS
              
              
              16ITEM
      4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
              
              
              16PART
      II
              
              
              16ITEM
      5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNIT HOLDER MATTERS AND
      ISSUER PURCHASE OF EQUITY SECURITIES
              
              
              16ITEM
      6. SELECTED FINANCIAL DATA
              
              
              17ITEM
      7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
      OF OPERATION
              
              
              18ITEM
      7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
    RISK
              
              
              29ITEM
      8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
              
              
              31ITEM
      9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
      FINANCIAL DISCLOSURES
              
              
              31ITEM
      9A(T). CONTROLS AND PROCEDURES
              
              
              31ITEM
      9B. OTHER INFORMATION
              
              
              32PART
      III
              
              
              32ITEM
      10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
              
              
              32ITEM
      11. EXECUTIVE COMPENSATION
              
              
              36ITEM
      12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
      RELATED STOCKHOLDER MATTERS
              
              
              38ITEM
      13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND GOVERNOR
      INDEPENDENCE
              
              
              39ITEM
      14. PRINCIPAL ACCOUNTING FEES AND SERVICES
              
              
              39PART
      IV
              
              
              40ITEM
      15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
              
              
              40SIGNATURES
              
              
              45









CAUTIONARY
STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS





This Form
10-K contains forward-looking statements within the meaning of Section 21E of
the Exchange Act. Forward-looking statements are all statements other than
statements of historical fact, including without limitation those statements
that are identified by the words “anticipates,” “believes,” “continue,”
“could,” “estimates,” “expects,” “future,” “hope,” “intends,” “may,”
“plans,” “potential,” “predicts,” “should,” “target,” and similar
expressions, and include statements concerning plans, objectives, goals,
strategies, future events or performance, and underlying assumptions (many of
which are based, in turn, upon further assumptions) and other statements that
are other than statements of historical facts. From time to time, the Company
may publish or otherwise make available forward-looking statements of this
nature, including statements contained within Item 7 – “Management’s Discussion
and Analysis of Financial Condition and Results of Operations.”





Forward-looking
statements involve risks and uncertainties, which could cause actual results or
outcomes to differ materially from those expressed. The Company's expectations,
beliefs and projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including without limitation, management's
examination of historical operating trends, data contained in the Company's
records and other data available from third parties. Nonetheless, the Company's
expectations, beliefs or projections may not be achieved or
accomplished.  While it is not possible to identify all such factors,
factors that could cause actual results to differ materially from those
estimated by us include:




·
              Fluctuations
      in the price and market for ethanol and distillers
  grains;
 ·
              Availability
      and costs of products and raw materials, particularly corn and
      coal;
 ·
              Changes
      in the environmental regulations that apply to our plant operations and
      our ability to comply with such
regulations;
 ·
              Ethanol
      supply exceeding demand and corresponding ethanol price reductions
      impacting our ability to operate profitably and maintain a positive spread
      between the selling price of our products and our raw material
      costs;
 ·
              Our
      ability to generate and maintain sufficient liquidity to fund our
      operations, meet debt service requirements and necessary capital
      expenditures;
 ·
              Our
      ability to continue to meet our loan
covenants;
 ·
              Limitations
      and restrictions contained in the instruments and agreements governing our
      indebtedness;
 ·
              Results
      of our hedging transactions and other risk management
      strategies;
 ·
              Changes
      in plant production capacity, variations in actual ethanol and distillers
      grains production from expectations or technical difficulties in operating
      the plant;
 ·
              Changes
      in our business strategy, capital improvements or development
      plans;
 ·
              Changes
      in interest rates and the availability of credit to support capital
      improvements, development, expansion and
  operations;
 ·
              Our
      ability to market and our reliance on third parties to market our
      products;
 ·
              Changes
      in or elimination of governmental laws, tariffs, trade or other controls
      or enforcement practices that currently benefit the ethanol industry
      including:
 o
              national,
      state or local energy policy – examples include legislation already passed
      such as the California low-carbon fuel standard as well as potential
      legislation in the form of carbon cap and
trade;
 o
              federal
      and state ethanol tax incentives;
 o
              legislation
      mandating the use of ethanol or other oxygenate
  additives;
 o
              state
      and federal regulation restricting or banning the use of
    MTBE;
 o
              environmental
      laws and regulations that apply to our plant operations and their
      enforcement; or
 o
              reduction
      or elimination of tariffs on foreign
ethanol.
 ·
              The
      development of infrastructure related to the sale and distribution of
      ethanol including:
 o
              expansion
      of rail capacity,
 o
              possible
      future use of ethanol dedicated pipelines for
    transportation,
 o
              increases
      in truck fleets capable of transporting ethanol within localized
      markets,
 o
              additional
      storage facilities for ethanol, expansion of refining and blending
      facilities to handle ethanol,
 o
              growth
      in service stations equipped to handle ethanol fuels,
  and
 o
              growth
      in the fleet of flexible fuel vehicles capable of using higher blends of
      ethanol fuel;
 ·
              Increased
      competition in the ethanol and oil
industries;
 ·
              Fluctuations
      in U.S. oil consumption and petroleum
prices;
 ·
              Changes in general economic
      conditions or the occurrence of certain events causing an economic impact
      in the agriculture, oil or automobile
  industries;
 ·
              Ongoing disputes with our
      management consultant and design-build
  contractor;
 ·
              Our liability resulting from
      litigation;
 ·
              Our ability to retain key
      employees and maintain labor
relations;
 ·
              Changes and advances in ethanol
      production technology; and
 ·
              Competition from alternative
      fuels and alternative fuel
additives.




1




Any
forward-looking statement contained in this document speaks only as of the date
on which the statement is made, and the Company undertakes no obligation to
update any forward-looking statement or statements to reflect events or
circumstances that occur after the date on which the statement is made or to
reflect the occurrence of unanticipated events. New factors emerge from time to
time, and it is not possible for management to predict all of the factors, nor
can it assess the effect of each factor on the Company's business or the extent
to which any factor, or combination of factors, may cause actual results to
differ materially from those contained in any forward-looking statement. All
forward-looking statements, whether written or oral and whether made by or on
behalf of the Company, are expressly qualified by the risk factors and
cautionary statements in this Form 10-K, including statements contained within
Item 1A – “Risk Factors.”




Available
Information




The
public may read and copy materials we file with the Securities and Exchange
Commission (the “SEC”) at the SEC’s Public Reference Room at 100 F Street NE,
Washington, D.C., 20549.  Information on the operation of the Public
Reference Room may be obtained by calling the SEC at
1-800-SEC-0330.  In addition, the SEC maintains an Internet site that
contains reports, proxy and information statements and other information
regarding issuers that file electronically with the SEC.  Reports we
file electronically with the SEC may be obtained at www.sec.gov.




In
addition, information about us is available at our website at www.redtrailenergyllc.com.  The
contents of our website are not incorporated by reference in this Annual Report
on Form 10-K.




PART
I




ITEM 1. BUSINESS.




Overview




Red Trail
Energy, LLC (“Red Trail” or the “Company”) owns and operates a 50 million
gallon per year (“MMGY”) corn-based ethanol manufacturing plant located near
Richardton, North Dakota in Stark County in western North Dakota (the “Plant”).
(Red Trail is referred to in this report as “we,” “our,” or
“us.”).  We were formed as a North Dakota limited liability company in
July 2003.




Fuel
grade ethanol and distillers grains are our primary products.  Both
products are marketed and sold primarily within the continental United
States.  For the year ended December 31, 2009, the Plant produced
approximately 49.8 million gallons of ethanol and approximately 107,000 tons of
dry distillers grains and 82,000 tons of wet distillers grains from
approximately 18.0 million bushels of corn.




General
Development of Business




The year
ended December 31, 2009 was a difficult but successful year for the
Company.  Many plants were forced to shut down and/or declare
bankruptcy during late 2008 and early 2009.  While the Company
continued to struggle financially during the first six months of 2009, the
timely negotiation of the deferral of two principal payments allowed the Company
enough liquidity to continue to operate.  Certain cost cutting
measures implemented by the Company, stricter limits placed on how many bushels
of corn will be purchased under fixed price contracts and how far out in the
future it will be contracted and, most significantly, a positive change in the
spread between ethanol and corn prices during the second half of 2009 allowed
the Company to show a profit for the year of approximately
$360,000.




A number
of cost cutting measures and policy changes implemented during late 2008 and
early 2009 are still in place as we continue to evaluate our cost structure and
plant efficiency in an effort to keep our costs as low as
possible.  As previously reported, in various Current Reports on Form
8-K, the Company went through some management changes during 2009 and feels it
is well positioned for the future.




During
2009, the Company worked closely with its senior lender, First National Bank of
Omaha (“FNBO” or the “Bank”).  The Company has entered into the 7th
Amendment to its Construction Loan Agreement (“7th
Amendment”).  The 7th
Amendment waives all prior covenant violations and changes the definition and
levels of some of the financial covenants in our loan agreements to allow us to
regain compliance with those covenants and increase our ability to maintain
compliance in the future.  As of December 31, 2009, the Company is in
compliance with all of its loan covenants, as amended, and is evaluating its
options to help ensure compliance in the future.  The Company’s
financial condition has improved from December 31, 2008 and it expects to be
able to maintain compliance with its loan covenants through December 31,
2010.  See the “Capital Resources” section of this Annual Report for
additional information on the assumptions used in the Company’s
projections.




The Plant
produced 49.8 million gallons of ethanol during 2009 – basically right at its
nameplate capacity.  This is approximately 5 million gallons lower
than the 54.8 million gallons produced during 2008 as the Company slowed down
its production early in 2009 due to poor margins that were experienced across
the industry.  The Company also experienced an unplanned 15 day outage
during October 2009 to repair an issue with tubes in its
boiler.  Fiscal 2009 was the second full year of the plant operating
on powder river basin (“PRB”) coal and the operational benefits continued as the
Plant did not experience any down time related to coal
quality.  Fiscal 2009 marked the first full year of operation of the
Company’s coal unloading facility.  The facility is operating as
intended and providing an estimated cost savings of $9 - $10 per ton of coal
used which should amount to an annual savings of approximately $900,000 to
$1,000,000.  The Plant maintained an excellent safety record during
2009 with no lost time accidents recorded.




2




The
Company is still operating under its original permit to construct and has not
been able to consistently meet all of the emissions requirements contained in
this permit since start up.  The Company continues to work closely
with the North Dakota Department of Health (“NDDH”) in monitoring its emissions
and working toward permit limits it can achieve with its Best Available Control
Technology (“BACT”) controls.




The
Company had previously applied for a new designation from the NDDH that would
have changed the Company to a synthetic minor source.  During 2009 it
became clear that our BACT would not allow us to meet the requirements of being
designated a synthetic minor source and we have decided to stay a major source
based on feedback from the NDDH.  We currently have submitted a new
permit application to the NDDH that would maintain our designation as a major
source and increases certain of the emissions limits in our
permits.  As of March 15, 2010, the Company is waiting for a new draft
air permit to be made available for review from the NDDH.




Our
design build contract stated that the Plant was designed to run on lignite coal
and meet emissions requirements.  Problems were encountered with
running the Plant on lignite during the first three to four months of operation
in 2007 which caused us to switch to PRB coal.  To date, the Company
has not been able to consistently meet all of its emissions requirements even
while running on the cleaner burning PRB coal.  The Company is
withholding $3.9 million from the general contractor until these issues can be
resolved.  An amount approximately equal to the final payment has been
set aside in a separate money market account.  We have been in contact
with the general contractor on a regular basis regarding this issue and are
currently moving toward a mediation process.




Climate
change legislation introduced during 2009 and early 2010 meant to limit
greenhouse gas emissions and/or limit the carbon intensity of the production
cycle of fuels will most likely have a wide ranging impact on businesses in
general (including ethanol plants), but may have a greater impact on Red Trail
Energy since we are a coal fired plant.  At this time we cannot
accurately predict the impact on our Company as the legislation has either not
yet been passed or the rules surrounding the legislation are not yet
complete.  It is possible that, in order to meet the requirements
imposed by such legislation, we will have to make changes to our plant that will
require us to make capital improvements.  Depending on the magnitude
of the required solutions, we may not have the required resources to make those
capital improvements.  We are currently researching projects to enable
us to meet the requirements of the low carbon fuel standard enacted in
California.  At this time we believe we would have to lower the carbon
intensity of the life cycle of our fuel by approximately 22% by January 1, 2011
to meet these requirements.  These are only estimates based on our
current understanding and may change as additional information becomes
available.




During
2008, the Company entered into an agreement to operate a third party’s corn oil
extraction equipment to be installed in our Plant.  Due to the
downturn in the economy that occurred during the last six months of 2008, the
third party we contracted with was unable to obtain financing for its operation
until some time during 2009.  The Company terminated its agreement
with the third party during 2009 due to the Company’s decision not to install
such equipment at this time.  The Company may revisit this project in
the future.




Financial
Information




Please
refer to “ Item 7 —
Management’s Discussion and Analysis of Financial Condition and Results of
Operations” for information about our revenues, profit and loss
measurements and total assets.  Our consolidated financial statements
and supplementary data are included beginning at page F-1 of this Annual
Report.




Principal
Products and Their Markets




The
principal products we produce at our Plant are fuel grade ethanol and distillers
grains.




Ethanol




Ethanol
is ethyl alcohol, a fuel component made primarily from corn and other grains. Ethanol can be used as:  (i) an octane enhancer in
fuels; (ii) an oxygenated fuel additive for the purpose of reducing ozone
and carbon monoxide vehicle emissions; and (iii) a non-petroleum-based
gasoline substitute.  More than 95% of all ethanol is used in its
primary form for blending with unleaded gasoline and other fuel products. Used
as a fuel oxygenate, ethanol provides a means to control carbon monoxide
emissions in large metropolitan areas. The principal purchasers of ethanol are
petroleum terminals in the continental United States.




The
Renewable Fuels Association (“RFA”) estimates annual domestic production
capacity to be approximately 13.5 billion gallons as of March
2010.  The RFA also estimates that approximately 10.6 billion gallons
was actually produced during 2009.




Revenue
from the sale of ethanol, net of derivative activity, was approximately 83%, 84%
and 88% of total revenues for the years ended December 31, 2009, 2008 and 2007,
respectively.




Distillers
Grains




A
principal co-product of the ethanol production process is distillers grains, a
high protein, high-energy animal feed supplement primarily marketed to the dairy
and beef industry. Distillers grains contain by-pass protein that is superior to
other protein supplements such as cottonseed meal and soybean meal. By-pass
proteins are more digestible to the animal, thus generating greater lactation in
milk cows and greater weight gain in beef cattle. The dry mill ethanol
processing used by the Plant results in two forms of distiller
grains:  Distillers Modified Wet Grains (“DMWG”) and Distillers Dried
Grains with Solubles (“DDGS”).  DMWG is processed corn mash that has
been dried to approximately 50% moisture.  DMWG have a shelf life of
approximately ten days and are often sold to nearby markets. DDGS is processed
corn mash that has been dried to 10% to 12% moisture.  DDGS has an
almost indefinite shelf life and may be sold and shipped to any market
regardless of its vicinity to an ethanol plant.  At our Plant, the
composition of the distillers grains we produce was approximately 70% DDGS and
30% DMWG during 2009.




3




Revenues
from sale of distillers grains was approximately 17%, 16% and 12% of total
revenues for the years ended December 31, 2009, 2008 and 2007,
respectively.




Marketing
and Distribution of Principal Products




Our
ethanol Plant is located near Richardton, North Dakota in Stark County, in the
western section of North Dakota. We selected the Richardton site because of its
location to existing coal supplies and accessibility to road and rail
transportation. Our Plant is served by the Burlington Northern and Santa Fe
Railway Company.




We sell
and market the ethanol and distillers grains produced at the Plant through
normal and established markets, including local, regional and national markets.
We have entered into a marketing agreement with RPMG, Inc. (“RPMG”) to sell our
ethanol. Whether or not ethanol produced by our Plant is sold in local markets
will depend on decisions made by our marketer. Local ethanol markets may be
limited and must be evaluated on a case-by-case basis. We have also entered into
a marketing agreement with CHS, Inc. (“CHS”) for our DDGS. We market and sell
our DMWG internally.




Ethanol




We have a
marketing agreement with RPMG for the purposes of marketing and distributing all
of the ethanol we produce at the Plant.  RPMG markets a total of
approximately 1 billion gallons of ethanol on an annual
basis.  Currently we own 8.33% of the outstanding capital stock of
RPMG.  Our ownership interest will fluctuate as other ethanol plants
that utilize RPMG’s marketing services may become owners of RPMGor decide to change marketers.  Our ownership interest
in RPMG entitles us a seat on its board of directors which is filled by our
Chief Executive Officer (“CEO”).  The marketing agreement will be in
effect as long as we continue to be a member in RPMG.  Prior to
completing our ownership buy-in during 2009, we paid RPMG $.01 per gallon to
market our ethanol.  After completing the ownership buy-in we are
currently paying RPMG approximately $.004 per gallon for each gallon RPMG sells,
per the terms of the agreement.




Distillers
Grains




We have a
marketing agreement with CHS for the purpose of marketing and selling our
DDGS.  The marketing agreement has a term of six months which is
automatically renewed at the end of the term.  The agreement can be
terminated by either party upon written notice to the other party at least
thirty days prior to the end of the term of the agreement.  Under the
terms of the agreement, we pay CHS a fee for marketing our distillers
grains.  The fee is 2% of the selling price of the distillers grain
subject to a minimum of $1.50 per ton and a maximum of $2.15 per
ton.




We market
and sell our DMWG internally.  Substantially all of our sales of DMWG
are to local farmers and feed lots.




New
Products and Services




We did
not introduce any new services or products during our fiscal year ended December
31, 2009.




Dependence
on One or a Few Major Customers




We are
substantially dependent upon RPMG for the purchase, marketing and distribution
of our ethanol. RPMG purchases 100% of the ethanol produced at our Plant, all of
which is marketed and distributed to its customers. Therefore, we are highly
dependent on RPMG for the successful marketing of our ethanol. In the event that
our relationship with RPMG is interrupted or terminated for any reason, we
believe that we could locate another entity to market the
ethanol.  However, any interruption or termination of this
relationship could temporarily disrupt the sale and production of ethanol and
adversely affect our business and operations and potentially result in a higher
cost to the Company.




We are
substantially dependent on CHS for the purchase, marketing and distribution of
our DDGS. CHS purchases 100% of the DDGS produced at the Plant (approximately
12.5% of our total revenue), all of which are marketed and distributed to its
customers. Therefore, we are highly dependent on CHS for the successful
marketing of our DDGS. In the event that our relationship with CHS is
interrupted or terminated for any reason, we believe that another entity to
market the DDGS could be located. However, any interruption or termination of
this relationship could temporarily disrupt the sale and production of DDGS and
adversely affect our business and operations.




Seasonal
Factors in Business




We
believe there is some seasonality in the demand for ethanol.  Since
ethanol is predominantly blended with conventional gasoline for use in
automobiles, ethanol demand tends to fluctuate with gasoline
demand.  As a result ethanol demand tends to increase during the
summer driving season and tends to decrease during the winter
months.  Historically, this seasonality has had more of an impact on
the price we receive for ethanol than our production output.  Our
production tends to remain constant throughout the year but ethanol prices vary
with supply and demand.  We monitor our production levels in
conjunction with margins to determine the best rate at which to operate the
Plant.




Financial
Information about Geographic Areas




All of
our operations and all of our long-lived assets are located in the United
States. We believe that all of the products we will sell to our customers in the
future will be produced and marketed in the United States.




Sources
and Availability of Raw Materials




Corn
Feedstock Supply




4




During
2009, we were able to secure sufficient grain to operate the Plant and do not
anticipate any problems securing enough corn during 2010.  We do
anticipate that, due to poor growing conditions in our region during 2009, at
least a portion of the corn we procure will be at a lower
quality.  Almost all of our corn is supplied from farmers and local
elevators in North Dakota and South Dakota.




During
January 2010, the United States Department of Agriculture’s 2009 Crop
Production Summary listed national corn production at approximately
13.2 billion bushels, which is the second largest corn crop on
record.  North Dakota produced an estimated 208 million bushels
in 2009.  We expect the demand for corn grown in our area to increase
resulting fromnew ethanol plants in North Dakota that became
operational during 2008 and will be at full production during 2010 (some were
idled for various reasons during 2009).  We expect that this increased
demand will lead to greater competition for corn in our geographic area, which
could increase the price we pay for corn.




Although
a significant amount of corn is grown in our region and we do not anticipate
encountering problems sourcing corn, a shortage of corn could develop,
particularly if there were an extended drought or other production
problem.  Poor weather can be a major factor in increasing corn
prices.  If the United States were to endure an entire growing season
with poor weather conditions, it could result in a prolonged period of higher
than normal corn prices.  Corn prices depend on several factors,
including world supply and demand and the price of other
commodities.  United States production of corn can be volatile as a
result of a number of factors, including weather, current and anticipated
stocks, domestic and export prices and supports and the government’s current and
anticipated agricultural policy.  The price of corn was volatile
during our 2009 fiscal year and we anticipate that it will continue to be
volatile in the future.  We anticipate that increases in the price of
corn, which are not offset by corresponding increases in the prices we receive
from sale of our products, will have a negative impact on our financial
performance.




Coal




Coal is
also an important input to our manufacturing process. During the fiscal year
ended December 31, 2009, we used approximately 88,800 tons of
coal.  Our Plant was originally designed to run on lignite coal but
problems running on lignite during start up caused us to change to PRB
coal.  If we cannot modify the coal combustor to use lignite coal, we
may have to use PRB coal instead of lignite coal as a long-term
solution.  Whether the Plant runs long-term on lignite or PRB coal,
there can be no assurance that the coal we need will always be delivered as we
need it, that we will receive the proper size or quality of coal or that our
coal combustor will always work properly with lignite or PRB coal. Any
disruption could either force us to reduce our operations or shut down the
Plant, both of which would reduce our revenues.




We
believe we could obtain alternative sources of PRB or lignite coal if necessary,
though we could suffer delays in delivery and higher prices that could hurt our
business and reduce our revenues and profits. We believe there is sufficient
supply of coal from the PRB coal regions in Wyoming and Montana to meet our
demand for PRB coal.  We also believe there is sufficient supply of
lignite coal in North Dakota to meet our demand for lignite coal.  The
table below shows information related to estimated coal reserves and production
numbers for Wyoming, Montana and North Dakota.




Estimated
      Coal Reserves at 12-31-08 and Production forthe
      12 months ended September 30, 2009 (in millions of
tons)State
              
              Estimated
      Reserves
              
              12
      month ProductionWyoming
              
              70,100
              
              445.42Montana
              
              9,250
              
              41.85North
      Dakota
              
              12,250
              
              29.95




If there
is an interruption in the supply or quality of coal for any reason, we may be
required to halt production. If production is halted for an extended period of
time, it may have a material adverse affect on our operations, cash flows and
financial performance.




In
addition to coal, we could use natural gas as a fuel source if our coal supply
is significantly interrupted. There is a natural gas line within three miles of
our Plant and we believe we could contract for the delivery of enough natural
gas to operate our Plant at full capacity. Natural gas tends to be significantly
more expensive than coal and we would also incur significant costs to install
natural gas delivery infrastructure and adapt our power systems to natural gas.
Because we are already operating on coal, we do not expect to need natural gas
unless coal interruptions impact our operations.




While it
may not directly impact our supply of coal, there are currently a number of
proposed government regulations (regulating carbon dioxide emissions, greenhouse
gas emissions, carbon cap and trade, low carbon fuel standards, etc) being
looked at that could impact our use of coal as a fuel source in the
future.




Electricity




The
production of ethanol is an energy intensive process that uses significant
amounts of electricity. We have entered into a contract with Roughrider Electric
Cooperative to provide our needed electrical energy.  Despite this
contract, there can be no assurance that they will be able to reliably supply
the electricity that we need.  If there is an interruption in the
supply of electricity for any reason, such as supply, delivery or mechanical
problems, we may be required to halt production. If production is halted for an
extended period of time, it may have a material adverse affect on our
operations, cash flows and financial performance.  Our rate for
electricity will increase approximately 7.5% for fiscal year 2010 as compared to
2009.




5




Water




Water
supply is also an important consideration. To meet the Plant’s full operating
requirements for water, we have entered into a ten-year contract with Southwest
Water Authority to purchase raw water.  Our contract requires us to
purchase a minimum of 160 million gallons per year.  Our rate for
water usage during fiscal year 2010 will be $2.54 per 1,000
gallons.  The rates for fiscal years 2009 and 2008 were $2.54 per
1,000 gallons and $2.49 per 1,000 gallons, respectively.  The Plant
anticipates receiving adequate water supplies during 2010.




Federal
Ethanol Supports




Various
federal and state laws, regulations, and programs have led to an increasing use
of ethanol in fuel, including subsidies, tax credits, policies and other forms
of financial incentives. Some of these laws provide economic incentives to
produce and blend ethanol, and others mandate the use of ethanol.




The most
recent ethanol supports are contained in the Energy Independence and Security
Act of 2007 (the “2007 Act”). Most notably, the 2007 Act accelerates and expands
the renewable fuels standard (“RFS”). The RFS requires refiners, importers and
blenders (the “Obligated Party,” or “Obligated Parties”) to show that a required
volume of renewable fuel is used in the nation’s fuel supply.  In
February 2010, the EPA set the limits for 2010, by type of renewable fuel, to be
blended into gasoline.  They called for 11.75 billion gallons of corn
based ethanol to be blended in 2010.  As of March 2010, the ethanol
industry in the United States has an annual production capacity estimated at
13.5 billion gallons which is greater than the amount needed to meet the 2010
RFS requirements.




The
ethanol industry is benefited by the Renewable Fuels Standard (RFS) which
requires that a certain amount of renewable fuels must be used in the United
States each year.  In February 2010, the EPA issued new regulations
governing the RFS.  These new regulations have been called
RFS2.  The most controversial part of RFS2 involves what is commonly
referred to as the lifecycle analysis of green house gas
emissions.  Specifically, the EPA adopted rules to determine which
renewable fuels provided sufficient reductions in green house gases, compared to
conventional gasoline, to qualify under the RFS program.  RFS2
establishes a tiered approach, where regular renewable fuels are required to
accomplish a 20% green house gas reduction compared to gasoline, advanced
biofuels and biomass-based biodiesel must accomplish a 50% reduction in green
house gases, and cellulosic biofuels must accomplish a 60% reduction in green
house gases.  Any fuels that fail to meet this standard cannot be used
by fuel blenders to satisfy their obligations under the RFS
program.  The scientific method of calculating these green house gas
reductions has been a contentious issue.  Many in the ethanol industry
were concerned that corn based ethanol would not meet the 20% green house gas
reduction requirement based on certain parts of the environmental impact model
that many in the ethanol industry believed was scientifically
suspect.  However, RFS2 as adopted by the EPA provides that corn-based
ethanol from modern ethanol production processes does meet the definition of a
renewable fuel under the RFS program.  However, many in the ethanol
industry are concerned that certain provisions of RFS2 as adopted may
disproportionately benefit ethanol produced from sugarcane.  This
could make sugarcane based ethanol, which is primarily produced in Brazil, more
competitive in the United States ethanol market.  If this were to
occur, it could reduce demand for the ethanol that we produce.




Recently
the RFS has come under scrutiny.  Many in the ethanol industry believe that
it is not possible to reach the RFS requirement in coming years without allowing
higher percentage blends of ethanol to be used in conventional automobiles.
 Currently, ethanol is blended with conventional gasoline for use in
standard vehicles to create a blend which is 10% ethanol and 90% gasoline. 
Estimates indicate that approximately 135 billion gallons of gasoline are sold
in the United States each year.  Assuming that all gasoline in the United
States is blended at a rate of 10% ethanol and 90% gasoline, the maximum demand
for ethanol is 13.5 billion gallons per year.  This is commonly referred to
as the “blending wall,” which represents a theoretical limit where more ethanol
cannot be blended into the national gasoline pool.  This is a theoretical
limit because it is believed that it would not be possible to blend ethanol into
every gallon of gasoline that is being used in the United States and it
discounts the possibility of additional ethanol used in higher percentage blends
such as E85 used in flex fuel vehicles.  Many in the ethanol industry
believe that we will reach this blending wall in 2010.




The RFS
mandate requires that 36 billion gallons of renewable fuels be used each year by
2022 which equates to approximately 27% renewable fuels used per gallon of
gasoline sold.  In order to meet the RFS mandate and expand demand for
ethanol, management believes higher percentage blends of ethanol must be
utilized in conventional automobiles.  Such higher percentage blends of
ethanol have continued to be a contentious issue.  The EPA is currently
considering allowing a blend of 15% ethanol and 85% gasoline for use in standard
automobiles but the EPA has delayed making a decision on this issue until
mid-2010.  Further, as discussed above, there may be additional
restrictions on what vehicles may use a 15% ethanol blend which may lead to
gasoline retailers refusing to carry such a blend.  Automobile
manufacturers and environmental groups are lobbying against higher percentage
ethanol blends.  State and federal regulations prohibit the use of higher
percentage ethanol blends in conventional automobiles and vehicle manufacturers
have indicated that using higher percentage blends of ethanol in conventional
automobiles would void the manufacturer’s warranty.  Without increases in
the allowable percentage blends of ethanol, demand for ethanol may not continue
to increase and it may not be possible to meet the RFS in coming years. 
This could negatively impact demand for ethanol.




The use
of ethanol as an alternative fuel source has been aided by federal tax policy,
which directly benefits gasoline refiners and blenders, and increases demand for
ethanol. On October 22, 2004, President Bush signed H.R. 4520, which
contained the Volumetric Ethanol Excise Tax Credit (“VEETC”) and amended the
federal excise tax structure effective as of January 1, 2005. Prior to
VEETC, ethanol-blended fuel was taxed at a lower rate than regular gasoline
(13.2 cents on a 10% blend). Under VEETC, the ethanol excise tax exemption has
been eliminated, thereby allowing the full federal excise tax of 18.4 cents per
gallon of gasoline to be collected on all gasoline and allocated to the highway
trust fund.  In place of the exemption, the bill created a volumetric
ethanol excise tax credit of 4.5 cents per gallon of ethanol blended at 10%.
Refiners and gasoline blenders apply for this credit on the same tax form as
before, only it is a credit from general revenue, not the highway trust fund.
Based on volume, the VEETC allows much greater refinery flexibility in blending
ethanol since it makes the tax credit available on all ethanol blended with all
gasoline, diesel and ethyl tertiary butyl ether (“ETBE”), including ethanol in
E85 and the E20 in Minnesota. The VEETC is scheduled to expire on
December 31, 2010.  If this credit is not renewed, it likely
would have a negative impact on the price of ethanol.  On December 31,
2009, the portion of VEETC that benefits the biodiesel industry was allowed to
expire and it has had a devastating impact on the biodiesel
industry.




6




The 2005
Act also expanded who qualifies for the small ethanol producer tax credit.
Historically, small ethanol producers were allowed a 10-cents-per-gallon
production income tax credit on up to 15 million gallons of production
annually. The size of the plant eligible for the tax credit was limited to
30 million gallons. Under the 2005 Act, the size limitation on the
production capacity for small ethanol producers increased from 30 million
to 60 million gallons. As a 50 MMGY ethanol producer, we expect to qualify for
the small ethanol producer tax credit.  The credit can be taken on the
first 15 million gallons of production. The tax credit is capped at
$1.5 million per year per producer. The small ethanol producer tax credit
is set to expire December 31, 2010.




In
addition, the 2005 Act created a new tax credit that permits taxpayers to claim
a 30% credit (up to $30,000) for the cost of installing clean-fuel vehicle
refueling equipment, such as an E85 fuel pump, to be used in a trade or business
of the taxpayer or installed at the principal residence of the taxpayer. Under
the provision, clean fuels are any fuels in which at least 85% of the volume
consists of ethanol, natural gas, compressed natural gas, liquefied natural gas,
liquefied petroleum gas, and hydrogen and any mixture of diesel fuel and
biodiesel containing at least 20% biodiesel. The provision is effective for
equipment placed in service after December 31, 2005 and before
December 31, 2010. While it is unclear how this credit will affect the
demand for ethanol in the short term, we expect it will help raise consumer
awareness of alternative sources of fuel and could positively impact future
demand for ethanol.




On
June 18, 2008, the United States Congress overrode a presidential veto to
approve the Food, Conservation and Energy Act of 2008 (the “2008 Farm Bill”) and
to ensure that all parts of the 2008 Farm Bill were enacted into law. 
Passage of the 2008 Farm Bill reauthorizes the 2002 farm bill and adds new
provisions regarding energy, conservation, rural development, crop insurance as
well as other subjects.   The energy title continues the energy
programs contained in the 2002 farm bill but refocuses certain provisions on the
development of cellulosic ethanol technology.  The new legislation provides
assistance for the production, storage and transport of cellulosic feedstocks
and provides support for ethanol production from such feedstocks in the form of
grants, loans and loan guarantees.  The 2008 Farm Bill also reduced the
VEETC from 51 cents per gallon to 45 cents per gallon beginning in 2009. 
The bill also extends the 54 cent per gallon ethanol tariff on imported ethanol
for two years, to January 2011.  If this tariff is allowed to
expire, imported ethanol could have a significant negative impact on ethanol
prices and our profitability.




Effect
of Government Regulation




The
ethanol industry and our business depend, in large part, upon continuation of
the federal ethanol supports discussed above.  These incentives have
supported a market for ethanol that might disappear without the
incentives.  Alternatively, the incentives may be continued at lower
levels.  The elimination or reduction of such federal ethanol supports
would likely reduce our net income and negatively impact our future financial
performance.




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 employees.  In addition,
some of these laws and regulations require our plant to operate under permits
that are subject to renewal or modification.  The government’s regulation
of the environment changes constantly.  It is possible that more stringent
federal or state environmental rules or regulations could be adopted, which
could increase our operating costs and expenses.




On
September 22, 2009, the EPA issued the “Final Mandatory Reporting of Greenhouse
Gases Rule” that became effective on January 1, 2010. This new rule requires
certain facilities that emit 25,000 metric tons or more of CO2 per year to
report certain greenhouse gas emissions data from that facility to the EPA on an
annual basis. The first annual reports covering calendar year 2010 will need to
be submitted to the EPA in 2011.  We have a greenhouse gas emissions
monitoring plan in place and are prepared to submit the required data in
2011.




Our
business may be indirectly affected by environmental regulation of the
agricultural industry as well.  It is also possible that federal or state
environmental rules or regulations could be adopted that could have an adverse
effect on the use of ethanol.  For example, changes in the environmental
regulations regarding ethanol’s use due to currently unknown effects on the
environment could have an adverse effect on the ethanol industry. 
Furthermore, plant operations are governed by the Occupational Safety and Health
Administration (OSHA).  OSHA regulations may change such that the costs of
the operation of the plant may increase.  Any of these regulatory factors
may result in higher costs or other materially adverse conditions affecting our
operations, cash flows and financial performance.




Other
Factors Affecting Demand and Supply




Demand
for ethanol may increase as a result of increased consumption of E85 fuel. E85
fuel is a blend of 85% ethanol and 15% gasoline.  According to United
States Department of Energy estimates, there are currently more than 8 million
flexible fuel vehicles capable of operating on E85 in the United States. 
Further, the United States Department of Energy reports that there are currently
more than 1,900 retail gasoline stations supplying E85.  The number of
retail E85 suppliers increases significantly each year, however, this remains a
relatively small percentage of the total number of U.S. retail gasoline
stations, which is approximately 170,000.  In order for E85 fuel to
increase demand for ethanol, it must be available for consumers to purchase
it.  As public awareness of ethanol and E85 increases along with E85’s
increased availability, management anticipates some growth in demand for ethanol
associated with increased E85 consumption.




7




The 2005
Act established a tax credit of 30% for infrastructure and equipment to dispense
E85. This tax credit became effective in 2006 and is expected to encourage more
retailers to offer E85 as an alternative to regular gasoline. The tax credit,
unless renewed, will expire December 31, 2010.




In
February 2009, the United States Congress passed the American Reinvestment and
Recovery Act (“ARRA”).  Provisions of the ARRA increase a federal
income tax credit for alternative fuel infrastructure that was included in the
2005 Act.  The ARRA allows retailers to claim up to 50% or $50,000 of
the cost to install or retrofit equipment for dispensing E85 at their
facilities.  In addition, the ARRA may further boost the expansion of
E85 infrastructure by granting up to $300 million to the Clean Cities Program
for implementing Section 721 of the 2005 Act which we believe will increase the
demand for ethanol and, in particular, higher blends of ethanol
fuel.




In
February 2009, Underwriters Laboratories (“UL”) announced that it supports
Authorities Having Jurisdiction who decide to permit legacy system dispensers,
listed to UL 87, and currently installed in the market, to be used with fuel
blends containing a maximum ethanol content of up to 15 percent.  UL
stresses that existing fuel dispensers certified under UL 87 were intended for
use with ethanol blends up to E10, which is the current legal limit for non-flex
fuel vehicles in the United States under the federal Clean Air
Act.  However, data gathered by UL through its ongoing research to
investigate the impact of using higher ethanol blends in fuel dispensing systems
supports that existing dispensers can be used with ethanol blends up to 15
percent.  This indication and announcement may also increase the
demand for ethanol.




Consumer
awareness may also have an impact on demand for ethanol.  While we
feel strongly that ethanol is a viable product that is an important piece of
reducing our reliance on imported oil, not all consumers may
agree.  There continues to be many news stories attributing negative
economic and environmental impacts to the rise in ethanol
production.  These concerns have included ethanol production creating
higher food prices, using excessive energy in the production process and
consuming high quantities of water.  While we believe that these
perceptions are based on information that is not accurate, we cannot be assured
that all consumers will share our views which may impact the overall demand for
ethanol.




Our
Competition




We will
be in direct competition with numerous other ethanol producers, many of whom
have greater resources than we do. We also expect that additional ethanol
producers will enter the market if the demand for ethanol increases. Ethanol is
a commodity product, like corn, which means our ethanol Plant competes with
other ethanol producers on the basis of price and, to a lesser extent, delivery
service.  Larger ethanol producers may be able to realize economies of
scale in their operations that we are unable to realize.  This could
put us at a competitive disadvantage to other ethanol producers.  We
anticipate that, without an increase in the amount of ethanol that can be
blended into gasoline for use in conventional automobiles, ethanol demand may
not significantly increase which may result in ethanol supply capacity exceeding
ethanol demand for the foreseeable future.




Recently
the United States Environmental Protection Agency has been researching
increasing the amount of ethanol that can be blended into gasoline for use in
automobiles from 10% to 15%.  We believe such an increase would lead
to an increase in demand for ethanol but could also result in additional ethanol
production facilities being built or expanded.  This could lead to
further overcapacity in the ethanol industry if supply continues to be higher
than demand.




In
December 2009, the California Office of Administrative Law approved the Low
Carbon Fuel Standard (“LCFS”) for implementation.  The LCFS is an
attempt to achieve a 10% reduction in motor vehicle’s emissions of greenhouse
gases by 2020 through the use of low-carbon fuels like hydrogen or cellulosic
ethanol.  The LCFS attempts to consider the life cycle carbon content
of all fuels used in California by taking into account indirect land use change
theories when determining a fuel’s potential for reducing emissions of
greenhouse gases.  Currently, most corn based ethanol, and
specifically not our ethanol (since we are a coal fired plant), would not meet
the criteria of the LCFS which may in turn limit the demand for corn based
ethanol and increase the demand for ethanol derived from sugar cane or cellulose
based feedstocks.  Renewable fuels that do not use corn as the primary
feedstock may be an important competitive factor facing our company given the
LCFS adopted in California.  There have been announcements of several
other states looking at similar legislation.




According
to the RFA, as of March 2010, the ethanol industry has grown to over 200
production facilities in the United States with another sixteen facilities
either under construction or expanding.  North Dakota currently has
the capacity to produce over 300 million gallons of ethanol
annually.  The Renewable Fuels Association currently estimates that
the United States ethanol industry has capacity to produce approximately 13.5
billion gallons of ethanol per year.  The new ethanol plants under
construction along with the plant expansions under construction could push
United States production of fuel ethanol in the near future to nearly 14.5
billion gallons per year.  Some of the largest ethanol producers include
Archer Daniels Midland, POET, Valero and The Andersons, Inc. each of which
are capable of producing more ethanol than we produce.




Competition from Alternative Ethanol Production
Methods




Alternative
ethanol production methods are continually under development. New ethanol
products or methods of ethanol production developed by larger and
better-financed competitors could provide them competitive advantages and harm
our business.




Most
ethanol is currently produced from corn and other raw grains, such as milo or
sorghum - especially in the Midwest.  The current trend in ethanol
production research is to develop an efficient method of producing ethanol from
cellulose-based biomass.  Cellulose is the main component of plant
cell walls and is the most common organic compound on earth.  Cellulose is
found in wood chips, corn stalks, rice straw, amongst other common plants.
Cellulosic ethanol is ethanol produced from cellulose.  Many of the
government incentives that have recently been passed, including the expanded
Renewable Fuels Standard and the 2008 Farm Bill, have included significant
incentives to assist in the development of commercially viable cellulosic
ethanol.  Currently, the technology is not sufficiently advanced to produce
cellulosic ethanol on a commercial scale, however, due to these new government
incentives we anticipate that commercially viable cellulosic ethanol technology
will be developed in the near future.  Several companies and researchers
have commenced pilot projects to study the feasibility of commercially producing
cellulosic ethanol.  If this technology can be profitably employed on a
commercial scale, it could potentially lead to ethanol that is less expensive to
produce than corn based ethanol, especially if corn prices remain high. 
Cellulosic ethanol may also capture more government subsidies and assistance
than corn based ethanol.  This could decrease demand for our product or
result in competitive disadvantages for our ethanol production
process.




8




Competition
with Ethanol Imported from Other Countries




Ethanol
production is also expanding internationally. Brazil has long been the world’s
largest producer and exporter of ethanol; however, since 2005, United States
ethanol production slightly exceeded Brazilian production. Ethanol is produced
more cheaply in Brazil than in the United States because of the use of
sugarcane, a less expensive raw material than corn. However, in 1980, Congress
imposed a tariff on foreign produced ethanol to make it more expensive than
domestic supplies derived from corn. This tariff was designed to protect the
benefits of the federal tax subsidies for United States farmers; however, there
is still a significant amount of ethanol imported into the United States from
Brazil. The tariff is currently set to expire in January 2011.  We do
not know the extent to which the volume of imports would increase or the effect
on United States prices for ethanol if the tariff is not renewed.




Ethanol
imports from 24 countries in Central America and the Caribbean Islands are
exempted from this tariff under the Caribbean Basin Initiative. Under the terms
of the Caribbean Basin Initiative, exports from membernations
are capped at 7% of the total United States production from the previous year
(with additional exemptions from ethanol produced from feedstock in the
Caribbean region over the 7% limit). However, as total production in the United
States grows, the amount of ethanol produced from the Caribbean region and sold
in the United States will also grow, which could impact our ability to sell
ethanol.




Competition
from Alternative Fuels




Our Plant
also competes with producers of other gasoline additives having similar octane
and oxygenate values as ethanol, such as producers of MTBE, a petrochemical
derived from methanol that costs less to produce than ethanol. Although
currently the subject of several state bans, many major oil companies can
produce MTBE and because it is petroleum-based, its use is strongly supported by
major oil companies.




Alternative
fuels, gasoline oxygenates and alternative ethanol production methods are also
continually under development by ethanol and oil companies with far greater
resources. The major oil companies have significantly greater resources than we
have to develop alternative products and to influence legislation and public
perception of MTBE and 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.




A number
of automotive, industrial and power generation manufacturers are developing
alternative clean power systems using fuel cells or clean burning gaseous fuels.
Like ethanol, the emerging fuel cell industry offers a technological option to
address increasing worldwide energy costs, the long-term 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 in order 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
negatively impact our profitability.




Distillers
Grains Competition




Ethanol
plants in the Midwest produce the majority of distillers grains and primarily
compete with other ethanol producers in the production and sales of distillers
grains. According to the RFA, approximately 30.5 million metric tons of
distillers grains were produced by ethanol plants in 2009. The amount of
distillers grains produced is expected to increase as the number of ethanol
plants increase, which will increase competition in the distillers grains market
in our area. In addition, our distillers grains compete with other livestock
feed products such as soybean meal, corn gluten feed, dry brewers grain and mill
feeds.




Research
and Development




We do not
conduct any research and development activities associated with the development
of new technologies for use in producing ethanol or distillers
grains.




Costs
and Effects of Compliance with Environmental Laws




We are
subject to extensive air, water and other environmental regulations and we have
been required to obtain a number of environmental permits to construct and
operate the Plant.  As mentioned above, we are operating under our
original permit to construct for air quality and have submitted an application
to the NDDH for an amended permit with increased emissions limits.  If
the application is approved as submitted by the NDDH then the permit will be
reviewed by the United States Environmental Protection Agency
(“EPA”).  The EPA will have 45 days to comment on the application and,
if approved, will then make the permit available for a 30 day public comment
period.  We expect to be subject to ongoing environmental regulations
and testing.




9




We
performed a Relative Accuracy Test Audit (“RATA”) on our Continuous Emissions
Monitoring System (“CEMS”) between September 23, 2009 and October 31,
2009.  The test results indicated that the CEMS equipment was
operating accurately.




Additionally,
the NDDH performed the annual Compliance Evaluation of our Plant on September 3,
2009.  The resulting report from the NDDH indicated “Based on the
inspection findings, and on reports submitted to our office, it appears that the
facility is in compliance with the applicable Air Pollution Control Rules and
the current Permit to Operate, with exception of DDGS Cooling (SO1) VOC, Boiler
(S60) PM (filterable and condensable) and Boiler NOx.”




Our
National Pollutant Discharge Elimination System (“NPDES”) permit, which
regulates the water treatment, water disposal and storm water systems at the
facility, requires renewal every five years.  Our current permit
expires on September 30, 2010.  Our application for renewal is due in
April 2010.  We do not anticipate any problems in renewing this
permit.




We are
subject to oversight activities by the EPA. There is always a risk that the EPA
may enforce certain rules and regulations differently than North Dakota’s
environmental administrators. North Dakota and EPA rules are subject to change,
and any such changes could result in greater regulatory burdens on our Plant
operations. We could also be subject to environmental or nuisance claims from
adjacent property owners or residents in the area arising from possible foul
smells or air/or water discharges from the Plant. Such claims may result in an
adverse outcome in court if we are found to engage in a nuisance that
substantially impairs the fair use and enjoyment of real estate.




The
government’s regulation of the environment changes constantly. It is possible
that more stringent federal or state environmental rules or regulations could be
adopted, which could increase our operating costs and expenses. It also is
possible that federal or state environmental rules or regulations could be
adopted that could have an adverse effect on the use of ethanol. For example,
changes in the environmental regulations regarding the required oxygen content
of automobile emissions could have an adverse effect on the ethanol industry.
Furthermore, Plant operations likely will be governed by the Occupational Safety
and Health Administration. OSHA regulations may change such that the costs of
the operation of the Plant may increase. Any of these regulatory factors may
result in higher costs or other materially adverse conditions affecting our
operations, cash flows and financial performance.




We
anticipate that we may have some capital expenditures for environmental control
facilities during fiscal 2010 to either help our Plant meet the requirements of
our permits or meet the requirements of the low carbon fuel standard enacted in
California but cannot accurately estimate the amounts at this time.




Employees




We
presently have 42 full-time employees.  Eight of our employees are
primarily involved in management and administration and the remainder are
primarily involved in Plant operations.




Our
success depends in part on our ability to attract and retain qualified personnel
at a competitive wage and benefit level. We must hire qualified managers,
accounting and other personnel. We operate in a rural area with low
unemployment. There is no assurance that we will be successful in attracting and
retaining qualified personnel for our Plant within our wage and benefit
assumptions. If we are unsuccessful in this regard, we may not be competitive
with other ethanol plants, which could increase our operating costs and decrease
our revenues and profits.




ITEM 1A. RISK FACTORS.




You
should carefully read and consider the risks and uncertainties below and the
other information contained in this Report. The risks and uncertainties
described below are not the only ones we may face. The following risks, together
with additional risks and uncertainties not currently known to us or that we
currently deem immaterial could impair our financial condition and results of
operation.




Risks
Relating to Our Business




We have a
significant amount of debt, and our existing debt financing agreements contain,
and our future debt financing agreements may contain, restrictive covenants that
limit distributions and impose restrictions on the operation of our
business.  The use of debt financing makes it more difficult
for us to operate because we must make principal and interest payments on the
indebtedness and abide by covenants contained in our debt financing
agreements.  The level of our debt may have important implications on
our operations, including, among other things: (a) limiting our ability to
obtain additional debt or equity financing; (b) placing us at a competitive
disadvantage because we may be more leveraged than some of our competitors; (c)
subjecting all or substantially all of our assets to liens, which means that
there may be no assets left for unit holders in the event of a liquidation; and
(d) limiting our ability to make business and operational decisions regarding
our business, including, among other things, limiting our ability to pay
dividends to our unit holders, make capital improvements, sell or purchase
assets or engage in transactions we deem to be appropriate and in our best
interest.




Our inability to
secure credit facilities we may require in the future may negatively impact our
liquidity.  Due to current conditions in the credit markets, it has
been increasingly difficult for businesses to secure financing.  Although
we do not currently require more financing (as of December 31, 2009) than we
have we may need additional financing if there is another prolonged period of
negative margins in the ethanol industry.  If we require financing in the
future and we are unable to secure such financing, or we are unable to secure
the financing we require on reasonable terms, it may have a negative impact on
our liquidity and the long-term viability of our business.




The spread
between ethanol and corn prices can vary significantly and has started to
decrease. Corn costs significantly impact our cost of goods sold. Our
gross margins are principally dependent upon the spread between ethanol and corn
prices.  While the spread between ethanol and corn prices improved to
the point where we were able to operate at a profit during the last six months
of 2009, corn and ethanol are commodities and we cannot predict what this spread
will be in the future.  If we were to experience another prolonged
period of negative margins it would adversely affect our results of operations
and financial condition.




10




Our financial
performance is significantly dependent on corn prices and generally we cannot
pass on increases in corn prices to our customers. Our results of
operations and financial condition are significantly affected by the cost and
supply of corn. Changes in the price and supply of corn are subject to and
determined by market forces over which we have no control.  Ethanol
production requires substantial amounts of corn. Corn, as with most other crops,
is affected by weather, disease and other environmental conditions. The price of
corn is also influenced by general economic, market and government factors.
These factors include weather conditions, farmer planting decisions, domestic
and foreign government farm programs and policies, global supply and demand and
quality. Changes in the price of corn can significantly affect our business.
Generally, higher corn prices will produce lower profit margins and, therefore,
represent unfavorable market conditions. This is especially true if market
conditions do not allow us to pass along increased corn costs to our customers.
The price of corn has fluctuated significantly in the past and may fluctuate
significantly in the future.  We cannot offer any assurance that we
will be able to offset any increase in the price of corn by increasing the price
of our products. If we cannot offset increases in the price of corn, our
financial performance may be adversely affected.  We may seek to
minimize the risks from fluctuations in the prices of corn through the use of
hedging instruments. However, these hedging transactions also involve risks to
our business. See “Item 1A. Risks Relating to Our Business — We engage in hedging transactions
which involve risks that can harm our business.”




We engage in
hedging transactions, which involve risks that can harm our business. We
are exposed to market risk from changes in commodity prices. Exposure to
commodity price risk results from our dependence on corn and coal in the ethanol
production process. We may seek to minimize the risks from fluctuations in the
prices of corn through the use of hedging instruments.  There is no
assurance that our hedging activities will successfully reduce the risk caused
by price fluctuation, which may leave us vulnerable to high corn
prices.  Alternatively, we may choose not to engage in or may not have
the available capital to engage in corn hedging transactions in the future. As a
result, our results of operations and financial conditions may also be adversely
affected during periods in which corn prices increase.




We are
also exposed to market risk from changes in the price of ethanol. We may seek to
minimize the risks from fluctuations in ethanol prices through the use of
ethanol swaps.  In addition, RPMG may have a percentage of our future
production gallons contracted through fixed price contracts, ethanol rack
contracts and gas plus contracts. There is no assurance that our hedging
activities will successfully reduce the risk caused by price fluctuation, which
may leave us vulnerable to fixed contracts below the current market value for
ethanol. Alternatively, we may choose not to engage in or may not have the
available capital to engage in ethanol hedging transactions in the future. As a
result, our results of operations and financial conditions may also be adversely
affected during periods in which ethanol prices decrease.




Hedging
activities themselves can be very capital intensive because price movements in
corn and ethanol contracts are highly volatile and are influenced by many
factors that are beyond our control.  There are several variables that
could affect the extent to which our derivative instruments are impacted by
price fluctuations in the cost of corn and ethanol.  However, it is
likely that commodity cash prices will have the greatest impact on the
derivatives instruments with delivery dates nearest the current cash
price.  If we do not have sufficient liquidity to hold our positions
our hedging activities may effectively increase our cost of corn and/or decrease
the price of our ethanol which could have an adverse impact on the financial
condition of the Company.




We have
derivative instruments in the form of interest rate swaps in an agreement with
bank financing. Market value adjustments and net settlements related to these
agreements are recorded as a gain or loss from non-designated hedging activities
and included in interest expense. Significant increases in the variable rate
could greatly affect our operations.




We have withheld
$3.9 million from our design-builder, Fagen, related to the coal
combustor.We have withheld $3.9 million from our
design-builder, Fagen, due to punch list items which are not complete as of
March 31, 2010 and problems with the coal combustor. The punch list are items
that must be complete under the terms of the Lump Sum Design-Build Agreement
between Fagen and us dated August 29, 2005 (the “Design-Build Contract”) in
order for us to sign off on final completion and authorize payment of the
$3.9 million.  In addition to a number of other punch list items,
the Design-Build Contract specified that the coal combustor would operate on
lignite coal and meet the emissions requirements in our air quality permits;
however, numerous plant shutdowns during start up in early 2007 related to using
lignite coal forced the Company to switch to PRB coal.  While running
on lignite coal and subsequently, while running on cleaner burning PRB coal, we
have not been able to maintain compliance with our air quality
permits.  There is no assurance that any potentially agreed upon
solution would solve the problems or solve the problems for $3.9 million or
less.  Any potential fixes could cost significantly more than $3.9
million.  There is also no assurance that Fagen and its subcontractors
will agree on any solution or even agree that the problem is their
responsibility to correct. If Fagen disputes the withholding of the $3.9 million
and demands payment, we may be forced to pay the $3.9 million and there
would be no assurance that the punch list items would be completed or that the
coal combustor would be able to use lignite coal.




Declines in the
price of ethanol or distillers grain would significantly reduce our
revenues. The sales prices of ethanol and distillers grains can be
volatile as a result of a number of factors such as overall supply and demand,
the price of gasoline and corn, levels of government support, and the
availability and price of competing products.  We are dependant on a
favorable spread between the price we receive for our ethanol and distillers
grains and the price we pay for corn, coal and electricity.  Any decrease
in ethanol and distillers grains prices, especially if it is associated with
increases in corn, coal and electricity prices may reduce our revenues and
affect our ability to operate profitably.




Our financial
performance is significantly dependent on coal prices and generally we cannot
pass on increases in coal prices to our customers.  The prices
for and availability of coal may be subject to volatile market conditions. These
market conditions often are affected by factors beyond our control such as
higher prices as a result of colder than average weather conditions, overall
economic conditions, including energy prices, and foreign and domestic
governmental regulations and relations. Significant disruptions in the supply of
coal could impair our ability to manufacture ethanol for our customers.
Furthermore, long-term increases in coal prices or changes in our costs relative
to energy costs paid by competitors may adversely affect our results of
operations and financial condition.




11




We currently buy
all of our coal from one supplier, Westmoreland. Westmoreland is
currently the sole provider of all of our coal and we rely on them for the coal
to run our Plant. If Westmoreland cannot or will not deliver the coal pursuant
to the contract terms, our business will be materially and adversely affected.
If our contract with Westmoreland terminates, we would seek alternative supplies
of coal, but we may not be able to obtain the coal we need on favorable terms,
if at all. If we cannot obtain an adequate supply of coal at reasonable prices,
or enough coal at all, our financial condition would suffer and we could be
forced to reduce or shut down operations.




Technological
advances could significantly decrease the cost of producing ethanol or result in
the production of higher-quality ethanol, and if we are unable to adopt or
incorporate technological advances into our operations, our Plant could become
uncompetitive or obsolete. We expect that technological advances in the
processes and procedures for processing ethanol will continue to occur. It is
possible that those advances could make the processes and procedures that we
utilize at our Plant less efficient or obsolete, or cause the ethanol we produce
to be of a lesser quality and/or value. Advances and changes in the technology
of ethanol production are expected to occur.  Such advances and
changes may make the ethanol production technology installed in our Plant less
desirable or obsolete. These advances could also allow our competitors to
produce ethanol at a lower cost than us. If we are unable to adopt or
incorporate technological advances, our ethanol production methods and processes
could be less efficient than our competitors, which could cause our Plant to
become uncompetitive or completely obsolete. If our competitors develop, obtain
or license technology that is superior to ours or that makes our technology
obsolete, we may be required to incur significant costs to enhance or acquire
new technology so that our ethanol production remains competitive.
Alternatively, we may be required to seek third-party licenses, which could also
result in significant expenditures. We cannot guarantee or assure you that
third-party licenses will be available or, once obtained, will continue to be
available on commercially reasonable terms, if at all. These costs could
negatively impact our financial performance by increasing our operating costs
and reducing our net income.




Ethanol
production methods are also constantly advancing. Most ethanol is currently
produced from corn and other raw grains, such as milo or sorghum — especially in
the Midwest. However, the current trend in ethanol production research is to
develop an efficient method of producing ethanol from cellulose-based biomass
such as agricultural waste, forest residue and municipal solid waste. This trend
is driven by the belief that cellulose-based biomass is generally cheaper than
corn and producing ethanol from cellulose-based biomass would create
opportunities to produce ethanol in areas that are unable to grow corn. Another
trend in ethanol production research is to produce ethanol through a chemical
process rather than a fermentation process, thereby significantly increasing the
ethanol yield per pound of feedstock. Although current technology does not allow
these production methods to be competitive, new technologies may develop that
would allow these methods to become viable means of ethanolproduction in the future. If we are unable to adopt or incorporate these
advances into our operations, our cost of producing ethanol could be
significantly higher than those of our competitors, which could make our Plant
obsolete.




In
addition, alternative fuels, additives and oxygenates are continually under
development. Alternative fuel additives that can replace ethanol may be
developed, which may decrease the demand for ethanol. It is also possible that
technological advances in engine and exhaust system design and performance could
reduce the use of oxygenates, which would lower the demand for ethanol, and our
business, results of operations and financial condition may be materially
adversely affected.




Operational
difficulties at our Plant could negatively impact our sales volumes and could
cause us to incur substantial losses. Our operations are subject to labor
disruptions, unscheduled downtime and other operational hazards inherent in our
industry, such as equipment failures, fires, explosions, abnormal pressures,
blowouts, pipeline ruptures, transportation accidents and natural disasters.
Some of these operational hazards may cause personal injury or loss of life,
severe damage to or destruction of property and equipment or environmental
damage, and may result in suspension of operations and the imposition of civil
or criminal penalties. Our insurance may not be adequate to fully cover the
potential operational hazards described above or we may not be able to renew
this insurance on commercially reasonable terms or at all.




Disruptions to
infrastructure, or in the supply of feedstock, fuel, coal or water, could
materially and adversely affect our business. Our business depends on the
continuing availability of rail, road, storage and distribution infrastructure.
Any disruptions in this infrastructure network, whether caused by labor
difficulties, earthquakes, storms, other natural disasters, human error,
malfeasance, or other reasons, could have a material adverse effect on our
business. We rely upon third-parties to maintain the rail lines from our Plant
to the national rail network, and any failure on their part to maintain the
lines could impede our delivery of products, impose additional costs on us and
could have a material adverse effect on our business, results of operations and
financial condition.




Our
business also depends on the continuing availability of raw materials, including
corn and coal. The production of ethanol, from the planting of corn to the
distribution of ethanol to refiners, is highly energy-intensive. Significant
amounts of fuel are required for the growing, fertilizing and harvesting of
corn, as well as for the fermentation, distillation and transportation of
ethanol and coal for the drying of distillers grains. A serious disruption in
supplies of fuel or coal, or significant increases in the prices of fuel or
coal, could significantly reduce the availability of raw materials at our Plant,
increase our production costs and have a material adverse effect on our
business, results of operations and financial condition.  We may
experience short-term disruptions in our coal supply as the result of the
transition to a new coal unloading facility and an ongoing work stoppage at
Westmorland.




Our Plant
also requires a significant and uninterrupted supply of suitable quality water
to operate. If there is an interruption in the supply of water for any reason,
we may be required to halt production at our Plant. If production is halted at
our Plant for an extended period of time, it could have a material adverse
effect on our business, results of operations and financial
condition.




12




We sell all of
the ethanol we produce to RPMG in accordance with an ethanol marketing agreement
and we rely heavily on RPMG’s marketing efforts for our ethanol
distribution. RPMG is the sole buyer of all of our ethanol and we rely
heavily on its marketing efforts to successfully sell our product. Because RPMG
sells ethanol for a number of other producers, we have limited control over its
sales efforts. Our financial performance is dependent upon the financial health
of RPMG, as a significant portion of our accounts receivable are attributable to
RPMG. If RPMG breachesthe ethanol marketing agreement or is
not in the financial position to purchase all of the ethanol we produce, we
could experience a material loss and we may not have any readily available means
to sell our ethanol and our financial performance will be adversely and
materially affected. If our agreement with RPMG terminates, we may seek other
arrangements to sell our ethanol, including selling our own product, but we give
no assurance that our sales efforts would achieve results comparable to those
achieved by RPMG.




Our business is
not diversified. Our success depends largely upon our ability to
profitably operate our ethanol Plant. We do not have any other lines of business
or other sources of revenue if we are unable to operate our ethanol Plant and
manufacture ethanol and distillers grains. If economic or political factors
adversely affect the market for ethanol, we have no other line of business as a
revenue-generating alternative. Our business would also be significantly harmed
if the Plant could not operate at full capacity for any extended period of
time.




Competition for
qualified personnel in the ethanol industry is intense and we may not be able to
hire and retain qualified personnel to operate our Plant.  Our
success depends in part on our ability to attract and retain competent
personnel, which can be challenging in a rural community. For the operation of
our Plant, we have hired qualified managers, engineers, operations and other
personnel. Competition for both managers and Plant employees in the ethanol
industry is intense, and we may not be able to maintain qualified personnel. If
we are unable to maintain productive and competent personnel or hire qualified
replacement personnel, our operations may be adversely affected, the amount of
ethanol we produce may decrease and we may not be able to efficiently operate
our Plant and execute our business strategy.




Risks
Related to Conflicts of Interest




We may have
conflicting interests with Greenway that could cause Greenway to put its
interests ahead of ours. Greenway advises our board of governors on
substantially all material aspects of operations.  Consequently, the
terms and conditions of any future agreements and understandings with Greenway
may not be as favorable to us as they could be if they were to be obtained from
other third parties. In addition, because of the extensive role that Greenway
had in the construction of the Plant and has in its operations, it may be
difficult or impossible for us to enforce claims that we may have against
Greenway. Such conflicts of interest may reduce our profitability.




Our governors
have other business and management responsibilities, which may cause conflicts
of interest, including working with other ethanol plants and in the allocation
of their time and services to our project.  Some of our
governors are involved in third party ethanol-related projects that might
compete against the ethanol and co-products produced by our Plant. Our governors
may also provide goods or services to us or our contractors or buy our ethanol
co-products. We have not adopted a Board policy restricting such potential
conflicts of interests at this time. Our governors have adopted procedures for
reviewing potential conflicts of interests; however, we cannot be assured that
these procedures will ensure that conflicts of interest are
avoided.




In
addition, our governors have other management responsibilities and business
interests apart from us. These responsibilities include, but may not be limited
to, being the owner and operator of non-affiliated businesses that our governors
and executive officers derive the majority of their income from and to which
they devote most of their time. We generally expect that each governor attend
our monthly Board meetings, either in person or by telephone, and attend any
special Board meetings in the same manner. Historically, our Board meetings have
lasted between three and six hours each, not including any preparation time
before the meeting. Therefore, our governors may experience difficulty in
allocating their time and services between us and their other business
responsibilities. In addition, conflicts of interest may arise because of their
position to substantially influence our business and management because the
governors, either individually or collectively, hold a substantial percentage of
the units of our Company.




Our CEO may have
a conflict of interest in his capacity as a board member of
RPMG.  While we believe the board members of RPMG will act in
the best interest of the member companies, we cannot guarantee that this will
always be the case which could have a negative impact on our
Company.  In addition, our CEO, in his capacity as an RPMG board
member, owes a duty to RPMG and may find that his obligations to act in the best
interest of RPMG place him at a conflict with the best interests of Red
Trail.




Risks
Related to Taxes




We are taxed as a
partnership and must comply with certain provisions of the tax code to avoid
being taxed as a corporation. We are a limited liability
company and, subject to complying with certain safe harbor provisions to avoid
being classified as a publicly traded partnership, we expect to be taxed as a
partnership for federal income tax purposes. Our Member Control Agreement
provides that no member shall transfer any unit if, in the determination of the
Board, such transfer would cause us to be treated as a publicly traded
partnership, and any transfer of unit(s) not approved by the Board or that would
result in a violation of the restrictions in the agreement would be null and
void. In addition, as a condition precedent to any transfer of units, we have
the right under the Member Control Agreement to seek an opinion of counsel that
such transfer will not cause us to be treated as a publicly traded partnership.
As a non-publicly traded partnership we are a pass-through entity and not
subject to income tax at the company level. Our income is passed through to our
members. If we become a publicly traded partnership we will be taxed as a C
Corporation. We believe this would be harmful to us and to our members because
we would cease to be a pass-through entity. We would be subject to income tax at
the company level and members would also be subject to income tax on
distributions they receive from us. This would have the affect of lowering our
after-tax income, amount available for distributions to members and cash
available to pay debt obligations and expenses.




13




We expect
to be treated as a partnership for income tax purposes. As such, we will pay no
tax at the company level and members will pay tax on their proportionate share
of our net income. The income tax liability associated with a member’s share of
net income could exceed any cash distribution the member receives from us. If a
member does not receive cash distributions sufficient to pay his or her tax
liability associated with his or her respective share of our income, he or she
will be forced to pay his or her income tax liability associated with his or her
respective units out of other personal funds.




Risks
Related to the Units




No public trading
market exists for our units and we do not anticipate the creation of such a
market, which means that it will be difficult for unit holders to liquidate
their investment.
There is currently no established public trading market for our units and an
active trading market will not develop. To maintain 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).
We, therefore, will not apply for listing on any securities exchange or on the
NASDAQ Stock Market. As a result, unit holders will not be able to readily sell
their units.  During 2007 we
entered into an agreement with Alerus Securities (“Alerus”) to allow our shares
to be traded through their qualified matching service (the “Qualified Matching
Service”).  This arrangement allows buyers and sellers to list their
offers to buy or sell our units on the Alerus website.




We have placed
significant restrictions on transferability of the units, limiting a unit
holder’s ability to withdraw from Red Trail. The units are subject to
substantial transfer restrictions pursuant to our Member Control Agreement and
tax and securities laws. This means that unit holders will not be able to easily
liquidate their units and may have to assume the risks of investments in us for
an indefinite period of time. Transfers will only be permitted in the following
circumstances:





•
            
            Transfers
      by gift to the member’s descendants;•
            
            Transfers
      upon the death of a member;•
            
            Certain
      other transfers provided that for the applicable tax year, the transfers
      in the aggregate do not exceed 2% of the total outstanding units;
      and•
            
            Transfers
      that comply with the Qualified Matching Service
    requirements.




There is no
assurance that a unit holder will receive cash distributions, which could result
in a unit holder receiving little or no return on his or her
investment.
Distributions are payable at the sole discretion of our Board, subject to the
provisions of the North Dakota Limited Liability Company Act, our Member Control
Agreement and our loan agreements with the Bank. We do not know the amount of
cash that we will generatein any given year. Cash
distributions are not assured, and we may never be in a position to make
distributions. Our Board may elect to retain future profits to provide
operational financing for the Plant or debt retirement.  This means
that unit holders 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 governors and
managers will not be liable for any breach of their fiduciary duty, except as
provided under North Dakota law. Under North Dakota law, no governor or
manager will be liable for any of our debts, obligations or liabilities merely
because he or she is a governor or manager. In addition, our Operating Agreement
contains an indemnification provision which requires us to indemnify any
governor or manager to the extent required or permitted by the North Dakota
Century Code, Section 10-32-99, as amended from time to time, or as
required or permitted by other provisions of law.




Risks
Related to Ethanol Industry




Overcapacity
within the ethanol industry could cause an oversupply of ethanol and a decline
in ethanol prices.  The total available production capacity of
the ethanol industry is currently greater than the demand for
ethanol.  This oversupply situation caused many plants to slow down,
shut down or declare bankruptcy in late 2008 and early 2009.  This
helped to bring the actual operating production capacity more in line with
demand and margins have improved as a result.  Because margins have
increased, however, some of the plants that were slowed down or shut down have
started to produce ethanol again which could lead to another oversupply
situation.  We believe the industry is going to operate in a period of
fluctuating supply and demand until the demand increases to meet total available
ethanol production capacity.  Excess capacity in the ethanol industry
may have an adverse impact on our results of operations, cash flows and general
financial condition.




Competition from
the advancement of alternative fuels may lessen the demand for ethanol.
Alternative fuels, gasoline oxygenates and ethanol production methods are
continually under development. A number of automotive, industrial and power
generation manufacturers are developing alternative clean power systems using
fuel cells or clean burning gaseous fuels. Like ethanol, the emerging fuel cell
industry offers a technological option to address increasing worldwide energy
costs, the long-term 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 in order 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 tocompete effectively. This additional
competition could reduce the demand for ethanol, resulting in lower ethanol
prices that might adversely affect our results of operations and financial
condition.




14




Certain countries
can export ethanol to the United States duty-free, which may undermine the
ethanol production industry in the United States.  Imported ethanol
is generally subject to a 54 cents per gallon tariff and a 2.5% ad valorem tax
that was designed to offset the 51 cents per gallon ethanol subsidy available
under the federal excise tax incentive program for refineries that blend ethanol
in their fuel. There is a special exemption from the tariff for ethanol imported
from 24 countries in Central America and the Caribbean islands, which is limited
to a total of 7.0% of United States production per year. The tariff is set to
expire in January 2011.  We do not know the extent to which the volume
of imports would increase if the tariff is not renewed.  Increased
imports could lead to an oversupply of ethanol in the United States which may
adversely affect our results of operations and financial condition.




In
addition, the North American Free Trade Agreement countries, Canada and Mexico,
are exempt from duty. Imports from the exempted countries have increased in
recent years and are expected to increase further as a result of new plants
under development.




Consumer
resistance to the use of ethanol based on the belief that ethanol is expensive,
adds to air pollution, harms engines and takes more energy to produce that it
contributes may affect the demand for ethanol. Certain individuals
believe that use of ethanol will have a negative impact on gasoline prices at
the pump. Many also believe that ethanol adds to air pollution and harms car and
truck engines. Still other consumers believe that the process of producing
ethanol actually uses more fossil energy, such as oil and coal, than the amount
of ethanol that is produced. These consumer beliefs could potentially be
wide-spread. If consumers choose not to buy ethanol, it would affect the demand
for the ethanol we produce which could lower demand for our product and
negatively affect our profitability and financial condition.




Risks Related to Regulation and Governmental
Action




The use of coal
as a fuel source could limit the markets in which ethanol produced at our Plant
can be marketed.  At least one state (California) has passed
legislation initiating a “low-carbon fuel standard” to reduce the carbon
intensity of transportation fuels used within the state.  This
legislation uses a lifecycle approach meaning that carbon emissions resulting
from the production process would increase the carbon intensity of the fuel
produced.  Since we are a coal fired Plant we may not be able to
market our ethanol in California and other states that develop such
standards.  This could potentially have a severe negative impact on
the viability of our Plant unless we can devise a way to limit our carbon
emissions.  We have started to explore alternatives for reducing our
carbon emissions but there is no guarantee we will be able to find an
acceptable, cost effective process for doing so.




Changes in
environmental regulations or violations of the regulations could be expensive
and reduce our profitability. We are subject to extensive air, water and
other environmental laws and regulations. In addition, some of these laws
require our Plant to operate under a number of environmental permits. These
laws, regulations and permits can often require expensive pollution control
equipment or operational changes to limit actual or potential impacts to the
environment. A violation of these laws and regulations or permit conditions can
result in substantial fines, damages, criminal sanctions, permit revocations
and/or Plant shutdowns. We can not assure you that we have been, are or will be
at all times, in complete compliance with these laws, regulations or permits or
that we have had or have all permits required to operate our business. We do not
assure you that we will not be subject to legal actions brought by environmental
advocacy groups and other parties for actual or alleged violations of
environmental laws or our permits. Additionally, any changes in environmental
laws and regulations, both at the federal and state level, could require us to
invest or spend considerable resources in order to comply with future
environmental regulations. The expense of compliance could be significant enough
to reduce our profitability and negatively affect our financial
condition.




If the Federal
Volumetric Ethanol Excise Tax Credit (“VEETC”) expires on December 31, 2010, it
could negatively impact our profitability.  The ethanol
industry is benefited by VEETC which is a federal excise tax credit of 4.5 cents
per gallon of ethanol blended with gasoline at a rate of at least
10%.  This excise tax credit is set to expire on December 31,
2010.  We believe that VEETC positively impacts the price of
ethanol.  On December 31, 2009, the portion of VEETC that benefits the
biodiesel industry was allowed to expire.  This resulted in the
biodiesel industry ceasing to produce biodiesel because the price of biodiesel
without the tax credit was uncompetitive with the cost of petroleum based
diesel.  If the portion of VEETC that benefits ethanol is allowed to
expire, it could negatively impact the price we receive for our ethanol and
could negatively impact our profitability.




Our Plant may not
be able to meet the emissions requirements in its permits.The
Company has operated under its permit to construct since it began
operations.  The Company has maintained close contact with the NDDH
regarding its inability to meet emissions under its current
permit.  The Company has currently submitted a new permit application
to the NDDH that would increase certain of the emissions limits in our
permits.  .




The fact
that our Plant has not consistently met certain emissions requirements is part
of our dispute with our design.  There is no guarantee that we will be
able to operate our Plant in compliance with our permits which could potentially
subject our Plant to significant fines and/or shut down our operation which
would have a negative impact on our financial condition.




The use of coal
as a fuel source could subject us to additional environmental compliance costs.As a consumer of coal, we may be subject to more stringent air emissions
regulations in the future.  There is emerging consensus that the
federal government will begin regulating greenhouse gas emissions, including
carbon dioxide, in the near future.  Since coal emits more carbon
dioxide than alternative fuel sources, including natural gas, which most ethanol
plants use, we may need to make significant capital expenditures to reduce
carbon dioxide emissions from the Plant.  In addition, we may incur
substantial additional costs for regulatory compliance, such as paying a carbon
tax or purchasing emissions credits under a cap-and-trade regime. If the costs
of regulatory compliance become prohibitively expensive, we may have to switch
to an alternate fuel source such as natural gas or biomass.  The
switch to an alternate fuel source could result in a temporary slow down or
disruption in operations.  The switch to an alternate fuel source like
natural gas or biomass could also result in a material adverse effect on our
financial performance, as coal is currently the least expensive fuel source
available for Plant operations.




15




Our business is
affected by the regulation of greenhouse gases, or GHG, and climate change. New
climate change regulations could impede our ability to successfully operate our
business.Our plant emits carbon dioxide as a by-product of
the ethanol production process.  In 2007, the U.S. Supreme Court
classified carbon dioxide as an air pollutant under the Clean Air Act in a case
seeking to require the EPA to regulate carbon dioxide in vehicle
emissions.  On February 3, 2010, the EPA released its final
regulations on the Renewable Fuel Standard program, or RFS 2.  We
believe these final regulations grandfather our plant at its current operating
capacity, though expansion of our plant will need to meet a threshold of a 20%
reduction in GHG emissions from a 2005 baseline measurement for the ethanol over
current capacity to be eligible for the RFS 2
mandate.  Additionally, legislation is pending in Congress on a
comprehensive carbon dioxide regulatory scheme, such as a carbon tax or
cap-and-trade system.  We may be required to install carbon dioxide
mitigation equipment or take other steps unknown to us at this time in order to
comply with this or other future laws or regulations.  Compliance with
future law or regulation of carbon dioxide, or if we choose to expand capacity
at our plant, compliance with then-current regulation of carbon dioxide, could
be costly and may prevent us from operating our plant as profitably, which may
have a material adverse impact on our operations, cash flows and financial
position.




The
California Air Resources Board has adopted a Low Carbon Fuel Standard requiring
a 10% reduction in GHG emissions from transportation fuels by 2020.
Additionally, an Indirect Land Use Change, or ILUC, component is included in the
lifecycle GHG emissions calculation. While this standard is currently being
challenged by various lawsuits, implementation of such a standard may have an
adverse impact on our market for corn-based ethanol if it is determined that in
California corn-based ethanol fails to achieve lifecycle GHG emission
reductions.




Loss of or
ineligibility for favorable tax benefits for ethanol production could hinder our
ability to operate at a profit and reduce the value of your investment in
us. The ethanol industry and our business are assisted by various federal
ethanol tax incentives, including those included in the Energy Independence and
Security Act of 2007 and the 2008 Farm Bill. The provision of the Energy
Independence and Security Act of 2007 most likely to have the greatest impact on
the ethanol industry is the amendment to the RFS created in 2005.  The
revised RFS calls for 11.1 billion gallons of corn based ethanol to be produced
in 2010, growing to 36 billion gallons in 2022, with 15 billion gallons to be
derived from conventional biofuels like corn-based ethanol.  The RFS
helps support a market for ethanol that might disappear without this incentive.
The elimination or reduction of tax incentives to the ethanol industry could
reduce the market for ethanol, which could reduce prices and our revenues by
making it more costly or difficult for us to produce and sell ethanol. If the
federal tax incentives are eliminated or sharply curtailed, we believe that a
decreased demand for ethanol will result, which could depress ethanol prices and
negatively impact our financial performance.




A change in
government policies favorable to ethanol may cause demand for ethanol to
decline. Growth and demand for ethanol may be driven primarily by federal
and state government policies, such as state laws banning MTBE and the national
RFS. The continuation of these policies is uncertain, which means that demand
for ethanol may decline if these policies change or are discontinued. A decline
in the demand for ethanol is likely to cause lower ethanol prices, which in turn
will negatively affect our results of operations, financial condition and cash
flows.




ITEM 2.
PROPERTIES.




The Plant
is located just east of the city limits of Richardton, North Dakota, and just
north and east of the entrance/exit ramps to Highway I-94. The Plant complex is
situated inside a footprint of approximately 25 acres of land which is part of
an approximately 135 acre parcel.  We acquired ownership of the land
in 2004 and 2005. Included in the immediate campus area of the Plant are
perimeter roads, buildings, tanks and equipment. An administrative building and
parking area are located approximately 400 feet from the Plant
complex.  During 2008 we purchased an additional 10 acre parcel of
land that is adjacent to our current property.  Our coal unloading
facility and storage site was built on this property.




The site
also contains improvements such as rail tracks and a rail spur, landscaping,
drainage systems and paved access roads.  Our plant was placed in
service in January 2007 and is in excellent condition and is capable of
functioning at 100 percent of its production capacity.




ITEM 3. LEGAL
PROCEEDINGS.




From time
to time in the ordinary course of business, we may be named as a defendant in
legal proceedings related to various issues, including without limitation,
workers’ compensation claims, tort claims, or contractual disputes. We are not
currently involved in any material legal proceedings, directly or indirectly,
and we are notaware of any claims pending or threatened
against us or any of our governors that could result in the commencement of
legal proceedings.




ITEM 4. SUBMISSION OF
MATTERS TO A VOTE OF SECURITY HOLDERS.




We did
not submit any matter to a vote of our unit holders through the solicitation of
proxies or otherwise during the fourth quarter of 2009.




PART II




ITEM 5. MARKET FOR REGISTRANT’S
COMMON EQUITY, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASE OF EQUITY
SECURITIES.




Market
Information




16




There is
no established trading market for our membership units.  We have
engaged Alerus to create a Qualified Matching Service (“QMS”) in order to
facilitate trading of our units.  The QMS consists of an electronic
bulletin board that provides information to prospective sellers and buyers of
our units.  Please see the table below for information on the prices of
units transferred in transactions completed via the QMS.  We do not
become involved in any purchase or sale negotiations arising from the QMS and we
take no position as to whether the average price or the price of any particular
sale is an accurate gauge of the value of our units.  As a limited
liability company, we are required to restrict the transfers of our membership
units in order to preserve our partnership tax status.  Our membership
units may not be traded on any established securities market or readily trade on
a secondary market (or the substantial equivalent thereof).  All transfers
are subject to a determination that the transfer will not cause the Company to
be deemed a publicly traded partnership.






We have
no role in effecting the transactions beyond approval, as required under our
Operating Agreement and the issuance of new certificates.  So long as we
remain a public reporting company, information about us will be publicly
available through the SEC’s EDGAR filing system.  However, if at any time
we cease to be a public reporting company, we may continue to make information
about us publicly available on our website.




Completed
      Unit TransactionsFiscal
      Quarter
              
              Low
      PerUnit Price
              
              
              High
      PerUnit Price
              
              
              Number
      of Units Traded2008
      1st Quarter
              
              $
              1.20
              
              
              $
              1.30
              
              
              
              330,0002008
      2nd Quarter
              
              $
              1.10
              
              
              $
              1.10
              
              
              
              1,0002008
      3rd Quarter
              
              $
              1.00
              
              
              $
              1.00
              
              
              
              120,0002008
      4th Quarter
              
              $
              ―
              
              
              $
              ―
              
              
              
              ―2009
      1st Quarter
              
              $
              ―
              
              
              $
              ―
              
              
              
              ―2009
      2nd Quarter
              
              $
              0.30
              
              
              $
              0.30
              
              
              
              10,0002009
      3rd Quarter
              
              $
              0.20
              
              
              $
              0.20
              
              
              
              50,0002009
      4th Quarter
              
              $
              ―
              
              
              $
              ―
              
              
              
              ―




Unit
Holders




As of
March 15, 2010, we had 40,193,973 Class A Membership Units outstanding and
a total of approximately 900 membership unit holders. There is no other class of
membership units issued or outstanding.  In December 2007, we acquired
and held 200,000 units in treasury related to equity based compensation
agreements for our President and Plant Manager.  The individuals
covered by these equity based compensation agreements are no longer working for
our Company therefore there are no longer any units vested pursuant to the terms
of these agreements.  20,000 units were vested and issued under these
agreements prior to their termination.  The Company currently holds
180,000 units in treasury.




Distributions




We did
not make any distributions to our members for the fiscal years ended
December 31, 2009 or 2008. Distributions are payable at the discretion of
our Board, subject to the provisions of the North Dakota Limited Liability
Company Act and our Member Control Agreement. Distributions to our unit holders
are also subject to certain loan covenants and restrictions that require us to
make additional loan payments based on excess cash flow. These loan covenants
and restrictions are described in greater detail under “ Item 7 — Management’s Discussion
and Analysis of Financial Condition and Results of Operations — Capital
Resources.” We may distribute a portion of the net profits generated from
Plant operations to unit holders. A unit holder’s distribution is determined by
dividing the number of units owned by such unit holder by the total number of
units outstanding. Ourunit holders are entitled to receive
distributions of cash or property if and when a distribution is declared by our
Board. Subject to the North Dakota Limited Liability Company Act, our Member
Control Agreement and the requirements of our creditors, our Board has complete
discretion over the timing and amount of distributions, if any, to our unit
holders. There can be no assurance as to our ability to declare or pay
distributions in the future.




Purchases
of Equity Securities




We did
not purchase any equity securities during the year ended December 31,
2009.




Unregistered
Sales of Equity Securities.




We did
not have any unregistered sales of equity securities during the year ended
December 31, 2009.




ITEM 6. SELECTED FINANCIAL
DATA.




The
following tables set forth selected financial data of Red Trail for the periods
indicated. The audited financial statements included in Item 8 of this
Annual Report have been audited by our independent auditors, Boulay, Heutmaker,
Zibell & Co., P.L.L.P.




Due to
uncertainty regarding our ability to meet certain financial covenants in our
loan agreements as of December 31, 2008, our debt was classified as a current
liability as of that date.  With the completion of the Seventh
Amendment to our Construction Loan Agreement (“Seventh Amendment”), those
uncertainties do not apply to our December 31, 2009 financial statements which
were in compliance with our loan covenants.  Also, our projections
show we will be able to meet our loan covenants throughout 2010, based on market
conditions that exist in March 2010 and our assumptions about future margins
(see the “Capital Resources” section of this Annual Report for more information
on the assumptions used in our projections).  Accordingly, our debt
obligation was classified as current and long-term pursuant to the terms of our
debt agreement’s scheduled payment terms.  For more information about
our financial condition, please see “Item 7 – Management’s Discussion and
Analysis of Financial Condition and Results of Operation” in this Annual
Report on Form 10-K.




17




Statement
      of OperationsFor
      the year Ended December 31,
              2009
              
              2008
              
              2007
              
              2006
              
              2005Revenues,
      net of derivative loss
              
              $
              93,836,661
              
              
              $
              131,903,514
              
              
              $
              101,885,969
              
              
              $
              ―
              
              
              $
              ―Cost
      of goods sold
              
              
              87,850,869
              
              
              
              131,025,238
              
              
              
              87,013,208
              
              
              
              ―
              
              
              
              ―Gross
      margin
              
              
              5,985,792
              
              
              
              878,276
              
              
              
              14,872,761
              
              
              
              ―
              
              
              
              ―General
      and administrative expenses
              
              
              2,812,891
              
              
              
              2,857,091
              
              
              
              3,214,002
              
              
              
              3,747,730
              
              
              
              2,087,808Operting
      income (loss)
              
              
              3,172,901
              
              
              
              (1,978,815
              )
              
              
              11,658,759
              
              
              
              (3,747,730
              )
              
              
              (2,087,808
              )Interest
      expense
              
              
              3,988,916
              
              
              
              6,013,299
              
              
              
              6,268,707
              
              
              
              ―
              
              
              
              ―Other
      income, net
              
              
              1,176,675
              
              
              
              2,625,542
              
              
              
              767,276
              
              
              
              1,243,667
              
              
              
              360,204Net
      income (loss)
              
              $
              360,660
              
              
              $
              (5,366,572
              )
              
              $
              6,157,328
              
              
              $
              (2,504,063
              )
              
              $
              (1,727,604
              )Weighted
      average units - basic
              
              
              40,191,494
              
              
              
              40,176,974
              
              
              
              40,371,238
              
              
              
              39,625,843
              
              
              
              24,393,980Weighted
      average units - fully diluted
              
              
              40,191,494
              
              
              
              40,176,974
              
              
              
              40,416,238
              
              
              
              39,625,843
              
              
              
              24,393,980Net
      income (loss) per unit - basic
              
              $
              0.01
              
              
              $
              (0.13
              )
              
              $
              0.15
              
              
              $
              (0.06
              )
              
              $
              (0.07
              )Net
      income (loss) per unit - fully diluted
              
              $
              0.01
              
              
              $
              (0.13
              )
              
              $
              0.15
              
              
              $
              (0.06
              )
              
              $
              (0.07
              )
  Balance
      Sheet Data
              2009
              
              2008
              
              2007
              
              2006
              
              2005Cash
      and equivalents
              
              $
              13,214,091
              
              
              $
              4,433,839
              
              
              $
              8,231,709
              
              
              $
              421,722
              
              
              $
              19,043,811Total
      current assets
              
              
              25,384,612
              
              
              
              16,423,730
              
              
              
              25,733,307
              
              
              
              4,761,974
              
              
              
              19,069,156Net
      property, plant and equipment
              
              
              71,415,582
              
              
              
              78,010,042
              
              
              
              81,942,542
              
              
              
              84,039,740
              
              
              
              16,948,185Total
      assets
              
              
              97,677,401
              
              
              
              95,802,453
              
              
              
              108,524,254
              
              
              
              89,864,228
              
              
              
              36,972,579Total
      current liabilities
              
              
              19,907,012
              
              
              
              61,968,448
              
              
              
              16,807,461
              
              
              
              9,781,240
              
              
              
              8,258,885Other
      noncurrent liabilities
              
              
              275,000
              
              
              
              275,000
              
              
              
              275,000
              
              
              
              275,000
              
              
              
              ―Long-term
      debt
              
              
              43,620,026
              
              
              
              ―
              
              
              
              52,538,310
              
              
              
              46,878,960
              
              
              
              ―Members'
      equity
              
              
              33,875,364
              
              
              
              33,559,005
              
              
              
              38,903,483
              
              
              
              32,929,088
              
              
              
              28,713,694Book
      value per weighted unit
              
              $
              0.84
              
              
              $
              0.84
              
              
              $
              0.96
              
              
              $
              0.83
              
              
              $
              1.18




ITEM
7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION.




Except
for the historical information, the following discussion contains
forward-looking statements that are subject to risks and uncertainties. We
caution you not to put undue reliance on any forward-looking statements, which
speak only as of the date of this report. Our actual results or actions may
differ materially from these forward-looking statements for many reasons,
including the risks described in “Item 1A — Risk Factors ”
and elsewhere in this Annual Report on Form 10-K. Our discussion and analysis of
our financial condition and results of operations should be read in conjunction
with the financial statements and related notes and with the understanding that
our actual future results may be materially different from what we currently
expect.




Overview




We
operate a 50 MMGY name-plate ethanol plant near Richardton, North Dakota.
Construction of the Plant began in 2005 and was completed in
December 2006.




Since
January 2007, our revenues have been derived from the sale and distribution
of ethanol and distillers grains throughout the continental United
States.  During the year ended December 31, 2009, we produced
approximately 49.8 million gallons of ethanol (approximately 100% of name-plate
capacity).  We also produced approximately 107,000 tons of DDGS and
82,000 tons of DMWG.




Our 2008
financial statements disclosed uncertainties related to our ability to continue
as a going concern.  We had violated certain of our loan covenants,
were experiencing negative margins and cash flows, and had limited
liquidity.  We are pleased to report that, due to improved margins
along with cash and risk management actions taken by the Company (including the
timely negotiation of the deferral of two principal payments, institution of
certain cost cutting measures, and taking action to limit the amount of corn
under fixed price contract), our 2009 financial statements no longer contain
disclosure regarding uncertainties as to our ability to continue as a going
concern.  We have regained compliance with our loan covenants and
project that we will be able to meet them throughout 2010 under market
conditions that exist in March 2010 along with our assumptions about future
margins.




18




We ended
fiscal year 2009 with a net income of approximately $360,000 compared to a loss
of approximately $5.4 million for fiscal year 2008.  Through June 30,
2009 we had a net loss of approximately $3.3 million.  Over the last
six months of 2009 we experienced much better margins and had a net income of
approximately $3.6 million.  Our results of operations are described
in greater detail below.




Results
of Operations




Comparison
of Fiscal Years Ended December 31, 2009, 2008 and 2007




The
following table shows the results of our operations and the percentages of sales
and revenues, cost of sales, operating expenses and other items to total sales
and revenues in our statements of operations for the years ended
December 31, 2009, 2008 and 2007:




For
      the years ended December 31,
              
              2009
              
              
              2008
              
              
              2007Amount
              
              
              Percent
              
              
              Amount
              
              
              Percent
              
              
              Amount
              
              
              PercentRevenues,
      net of derivative activity
              
              $
              93,836,661
              
              
              
              100.00
              %
              
              $
              131,903,514
              
              
              
              100.00
              %
              
              $
              101,885,969
              
              
              
              100.00
              %Cost
      of goods sold
              
              
              87,850,869
              
              
              
              93.62
              %
              
              
              131,025,238
              
              
              
              99.33
              %
              
              
              87,013,208
              
              
              
              85.50
              %Gross
      margin
              
              
              5,985,792
              
              
              
              6.38
              %
              
              
              878,276
              
              
              
              0.67
              %
              
              
              14,872,761
              
              
              
              14.50
              %General
      and administrative expenses
              
              
              2,812,891
              
              
              
              3.00
              %
              
              
              2,857,091
              
              
              
              2.17
              %
              
              
              3,214,002
              
              
              
              3.20
              %Operating
      income (loss)
              
              
              3,172,901
              
              
              
              3.38
              %
              
              
              (1,978,815
              )
              
              
              -1.50
              %
              
              
              11,658,759
              
              
              
              11.40
              %Interest
      expense
              
              
              3,988,916
              
              
              
              4.25
              %
              
              
              6,013,299
              
              
              
              4.56
              %
              
              
              6,268,707
              
              
              
              -6.20
              %Other
      income (expense)Grant
      income
              
              
              36,518
              
              
              
              0.04
              %
              
              
              73,207
              
              
              
              0.06
              %
              
              
              27,750
              
              
              
              0.00
              %Interest
      income
              
              
              470,055
              
              
              
              0.50
              %
              
              
              426,233
              
              
              
              0.32
              %
              
              
              432,265
              
              
              
              0.40
              %Other
      income
              
              
              670,102
              
              
              
              0.71
              %
              
              
              2,126,102
              
              
              
              1.61
              %
              
              
              307,261
              
              
              
              0.30
              %Net
      income (loss)
              
              $
              360,660
              
              
              
              8.89
              %
              
              $
              (5,366,572
              )
              
              
              5.05
              %
              
              $
              6,157,328
              
              
              
              5.90
              %




Additional
      Data for the year ended December 31,
              
              2009
              
              
              2008Ethanol
      sold (thousands of gallons)
              
              
              49,832
              
              
              
              55,148Ethanol
      average sales price per gallon (net of hedging activity)
              
              $
              1.56
              
              
              $
              2.01Corn
      costs per bushel (net of hedging activity)
              
              $
              3.77
              
              
              $
              5.19




Revenues




2009 compared to
2008




During
2009, our total revenues decreased by 28.9% to $93.8 million.  Ethanol
and distillers grains represented 83% and 17% of 2009 revenue,
respectively.  The decrease in revenue is attributable to a number of
factors, including:




·
            Ethanol
      prices, net of hedging activity, averaged 23% lower in 2009 than 2008
      ($1.56 per gallon in 2009 vs. $2.01 per gallon in 2008).  We
      believe ethanol prices were lower overall due to the generally lower
      commodity prices (primarily corn, crude oil and gasoline) during 2009
      compared to 2008.  All three of these commodities reached record
      prices in late June and early July 2008 and then declined sharply in the
      last four to five months of 2008.  Prices rebounded somewhat
      during 2009 but were still lower overall than in 2008.  The
      average price we received for ethanol during 2009 ranged from $1.41 to
      $1.95.  The high was achieved in November 2009 as tight ethanol
      supplies during the last quarter of 2009 caused ethanol prices to increase
      relative to corn prices.  During 2009 and 2008, the Company
      realized losses on ethanol hedging activity of approximately $1.6 million
      and $2.4 million, respectively.




We
produced and sold approximately 5 million fewer gallons of ethanol during 2009
compared to 2008.  Approximately 3 million gallons of the reduction in
production and sales came in the first six months of 2009 when we experienced
very poor margin conditions and chose to run our plant at a slower
rate.  The remaining decrease in production and sales came in October
2009 when we experienced an unplanned outage related to an issue with our
boiler.




·
            Distillers
      grains – Our 2009 distillers grain sales volumes were roughly split 70-30
      between DDGS and DMWG compared to a 50-50 split during
      2008.  The change in product mix came as we changed the pricing
      on our DMWG product to more closely match that of DDGS.  On a
      dry matter basis (converting all distillers grains produced to a DDGS
      equivalent) our overall production of distillers grains decreased
      approximately 12% which is line with the decrease in ethanol production
      noted above.  We produced and sold approximately 3,000 more tons
      of DDGS so the decline in production was all in our DMWG
      product.  All of our DMWG product is transported by truck but
      our DDGS product is transported by both truck and rail.  As
      other ethanol plants located in North Dakota, that had been idled for
      various reasons, resumed production we saw a shift in our shipments of
      DDGS from truck to rail.




19




The
average price we received for our DDGS product in 2009 declined approximately
19% compared to 2008 and our revenue decreased by approximately
16%.  The average prices we received for DDGS during 2009 ranged from
$81 per ton to $141 per ton with our overall average price for the year being
approximately $111 per ton compared to an average of approximately $136 per ton
for 2008.  DDGS prices generally follow the price of corn which was
significantly lower in 2009 compared to 2008.  The average price we
receive for DDGS was also impacted by the shift from truck transportation to
rail transportation noted above.  We typically receive a premium of $7
- $10 per ton for product shipped by truck vs. rail.




The
average price we received for our DMWG product in 2009 declined approximately 6%
compared to 2008 and our revenue decreased approximately 35%.  The
decrease in revenue is primarily related to lower production due to the change
in product mix noted above.  We produced and sold approximately 37,500
fewer tons of DMWG (81,700 tons in 2009 vs. 119,300 tons in 2008) in 2009
compared to 2008.  Prices received for our DMWG in 2009 ranged from
$47 to $64 per ton with our average selling price for the year being
approximately $54 per ton compared to $57 per ton in 2008.  Prices for
DMWG also follow the price of corn but didn’t decrease as much compared to 2008
as our DDGS prices due to a price increase instituted for our 2009 contract
year.




·
            We
      entered into ethanol swap contracts at various times during both 2009 and
      2008.  We recognized losses on hedging from ethanol derivative
      instruments during 2009 and 2008 of approximately $1.6 million and $2.4
      million, respectively.  These losses are included in revenue on
      our financial statements.




2008 compared to
2007




During
2008, our total revenues increased by 29.5% to $131.9
million.  Ethanol and distillers grains represented 84% and 16% of
2008 revenue, respectively.  The increase in revenue is attributable
to a number of factors, including:




·
            Ethanol
      prices, net of hedging activity, averaged 10% higher in 2008 than 2007
      ($2.01 per gallon in 2008 vs. $1.82 per gallon in 2007).  We
      believe ethanol prices were higher overall due to the increase in
      commodity prices (primarily corn, crude oil and gasoline) during the first
      six months of 2008.  We believe ethanol prices are generally
      positively impacted by higher corn, gasoline and crude oil
      prices.  All three of these commodities reached record prices in
      late June and early July 2008.  The average price we received
      for ethanol during 2008 ranged from $1.46 to $2.50.  The high
      was achieved in June 2008.  Prices steadily declined the rest of
      the year to the low of $1.46 received in December.  We believe
      the decrease was again due to the decrease in corn, crude oil and gasoline
      prices the last half of the year along with decreases in demand for these
      commodities as well as ethanol due to the collapse of the world
      economy.




·
            Distillers
      grains – Our 2008 and 2007 distillers grain sales volumes were roughly
      split 50-50 between DDGS and DMWG.  Prices received by us for
      DDGS ranged from $126 to $157 per ton during 2008 with our average selling
      price for the year being approximately $136 per ton compared to an average
      of approximately $87 per ton in 2007.  The price of DDGS
      generally follows the price of corn so, as corn prices increased during
      the first half of 2008, the price we received for DDGS also increased to
      the high of $157 per ton received in June 2008.  Prices have
      since declined along with corn prices and we received an average price of
      approximately $135 per ton in December 2008.  Due to the high
      quality of our DDGS and the markets in which our product is typically sold
      we have been able to capture a small premium for our DDGS relative to
      other markets and plants.  Due to this premium, the price we
      receive for DDGS actually increased slightly from September 2008 through
      December 2008.  Prices received by us for DMWG during 2008
      ranged from $50 to $75 per ton with our average selling price for the year
      being approximately $57 per ton compared to an average of approximately
      $40 per ton for 2007.  Prices for DMWG also follow the price of
      corn and, as such, our price for DMWG peaked in July 2008 and steadily
      declined the rest of the year.  Our price was also positively
      impacted, compared to 2007, due to a change made in our contract pricing
      to index the price we receive for DMWG to the price of
      corn.  All of our 2007 contracts were based on a flat pricing
      schedule.




·
            During
      2008 we recognized a loss on hedging from ethanol derivative instruments
      of approximately $2.4 million compared to a loss of approximately $2
      million during 2007.  We held some ethanol swap contracts
      through July 2008.  The value of these swap contracts decreased
      as ethanol prices increased during the first half of 2008.  We
      exited the swaps as ethanol prices started to decrease in July
      2008.  These losses are included in revenue on our financial
      statements.




Prospective
Information:




·
            Ethanol
      – ethanol prices that increased sharply during the last quarter of 2009
      have declined rapidly during January - March 2010 as the supply of ethanol
      has become more readily available as production has increased industry
      wide.  We anticipate that ethanol prices will continue to
      increase or decrease with the price of corn, gasoline and crude oil and
      also be impacted by blending economics and the supply and demand for
      ethanol.  As plants have started up or increased production in
      response to the improved margins, some in the industry are predicting
      another possible oversupply situation similar to what the industry went
      through in late 2008 and early 2009.  If that were to happen we
      believe ethanol prices would decline relative to corn prices and could
      again lead to negative margins.  We believe there will continue
      to be a cyclical component to ethanol prices until demand for ethanol
      catches up with total available ethanol capacity but we cannot be certain
      of how the price of ethanol will change, as it is a market driven
      commodity.




At this
time we cannot predict the impact of the implementation of the low carbon fuel
standard (“LCFS”) in California.  The LCFS is scheduled to take effect
on January 1, 2011.  As of March 15, 2010, the LCFS has not had any
impact on our ethanol sales from companies trying to comply early with the
standard.




·
            Distillers
      Grains - Distillers grains prices normally follow the price of
      corn.  We believe distillers grains prices will remain
      consistent with corn price fluctuations but we cannot be certain of how
      the price of distillers grains will change, as it is a market driven
      commodity.




20




·
            Corn
      Oil Extraction – during 2009 we terminated an agreement we had to operate
      a third party’s corn oil extraction equipment at our
      plant.  This agreement was entered into during 2008 and was
      contingent upon the third party obtaining financing for its
      project.  The equipment was never installed at our plant
      site.  We are not currently seeking to install corn oil
      extraction equipment and do not anticipate pursuing this project in
      2010.




Cost
of Goods Sold and Gross Margin




We
experienced significantly lower costs of goods sold in 2009 compared to 2008
with a decrease of approximately $43 million.  The decrease was
largely due to lower corn costs (approximately $38 million) and were mostly
offset by the lower revenues noted above.  Our other costs of goods
sold decreased by approximately $5 million and largely contributed to the
increase in our gross margin of approximately the same amount.




2009 compared to
2008




Our gross
margin for 2009 was approximately $6 million compared to $900,000 for
2008.  Our total cost of goods sold per gallon of ethanol produced
decreased by 27% compared to 2008 ($1.76 per gallon vs. $2.39 per
gallon).  The decrease in cost of goods sold is attributable to a
number of factors including:




·
            Corn
      cost – our corn costs per gallon of ethanol produced decreased 30% during
      2009 due, in large part, to average market corn prices that were
      significantly lower in 2009 compared to 2008.  During 2009 we
      also took measures to decrease our exposure to losses on firm purchase
      commitments by limiting the amount of corn we had under fixed price
      contracts at any one time.  We also renewed our focus on
      procuring corn from and building relationships with local farmers and
      elevators.  As an end user of corn we typically enter in to
      fixed price contracts to ensure an adequate supply of corn to operate our
      Plant.  During 2008, we recognized losses on firm purchase
      commitments of approximately $3.5 million which resulted from having
      entered into fixed price contracts to purchase corn at prices that became
      significantly higher than market prices as corn prices dropped sharply
      during the last six months of 2008.  During 2009 we recognized
      losses of approximately $169,000 on firm purchase commitments due to
      having fewer bushels under fixed price contracts and less volatility in
      the corn market during 2009 as compared to 2008.  In addition,
      we had to write down our corn and ethanol inventory to the lower of cost
      or market.  For the periods ended December 31, 2009 and 2008, we
      had recorded lower of cost or market adjustments related to our corn and
      ethanol inventories of approximately $1.5 million and $771,000,
      respectively.




·
            We
      used options and futures contracts to hedge our long corn position during
      both 2008 and 2009.  We recognized a loss of approximately
      $475,000 and a gain of approximately $6.2 million related to our corn
      hedging activities during 2009 and 2008,
  respectively.




·
            Other
      cost of goods sold – our other cost of goods sold consists primarily of
      chemical ingredients, depreciation, denaturant, repairs, energy and labor
      needed to operate the Plant.  These costs decreased
      approximately $5.2 million in 2009 compared to 2008.  We
      experienced decreases in our chemical ($1.7 million), denaturant ($1.6
      million) and coal costs ($1.2 million) during the year.  Many of
      the chemicals we use, along with denaturant, are commodities – these items
      decreased in price during 2009 compared to 2008 as commodities in general
      decreased compared to the record highs in late June/early July
      2008.  Our coal costs decreased due to having our coal unloading
      facility operational for a full year.  This facility was placed
      in service in September 2008 and has been operating as intended and
      providing a savings of between $9 and $10 per ton of coal
      used.  These decreases were offset in part by an increase in our
      electrical costs ($262,000) as our rates increased in 2009 compared to
      2008 and also an increase in depreciation ($100,000) as we started to
      depreciate our coal unloading
facility.




2008 compared to
2007




Our gross
margin for 2008 was approximately $900,000 compared to approximately $14.8
million for 2007.  Our total cost of goods sold per gallon of ethanol
produced increased by 38% compared to 2007 ($2.39 per gallon vs. $1.73 per
gallon).  The increase in cost of goods sold is attributable to a
number of factors including:




·
            Corn
      cost – our corn costs per gallon of ethanol produced increased 42.5%
      during 2008.  As an end user of corn we typically enter in to
      fixed price contracts to ensure an adequate supply of corn to operate our
      Plant.  We reaped the benefits of this strategy during the first
      seven months of 2008 as we had entered in to fixed price contracts to
      purchase corn at prices that became significantly under the market value
      of corn as commodity prices increased to their peak in late June/early
      July 2008.  Because ethanol prices increased along with corn
      prices we were able to operate profitably during this
      period.  The decrease in prices during the last half of 2008 had
      the opposite effect on our margins as we had entered in to fixed price
      contracts to purchase corn at prices that became significantly higher than
      the market value of corn.  Because ethanol prices decreased
      along with corn prices we incurred significant losses during this period
      which more than offset the profit earned during the first six months of
      2008.  Further exacerbating our losses was the fact that we had
      to accrue losses on the corn under fixed price contracts that had not yet
      been delivered.  We recognized a loss on firm purchase
      commitments of approximately $3.1 million during the third quarter of 2008
      and had approximately $1.4 million accrued as of December 31,
      2008.  Our total loss on firm purchase commitments for 2008 was
      approximately $3.5 million.  In addition, we had to write down
      our corn and ethanol inventory to the lower of cost or
      market.  As of December 31, 2008 this amounted to a write down
      of $212,000 for corn inventory and $559,000 for ethanol.  We did
      not have any losses on firm purchase commitments or lower of cost or
      market inventory adjustments during
2007.




21




·
            Partially
      offsetting the increase in corn costs during 2008 were gains recognized
      from our corn hedging activities of approximately $6.2
      million.  During 2007, we recognized gains from our corn hedging
      activities of approximately $3 million.  The losses we sustained
      during 2008 along with difficulties we encountered in trying to raise
      additional short term liquidity through increasing our short term line of
      credit have left us with an amount of available capital that will not
      allow us to take aggressive hedge positions even if the opportunity arises
      where we could lock in a margin using either corn or ethanol related
      derivative instruments.




·
            Other
      cost of goods sold – our other cost of goods sold consists primarily of
      chemical ingredients, depreciation, repairs, energy and labor needed to
      operate the Plant.  We experienced increases in our chemical,
      coal and repair costs during the year.  Chemical costs increased
      due to price increases for some of our main chemicals (including anhydrous
      ammonia, sodium bicarbonate and sulfuric acid) as world demand for these
      chemicals increased causing a shortage in supply.  Our coal
      costs increased due to running a full year on more expensive PRB coal
      during 2008.  Repair costs increased as we entered our second
      year of operation and took the Plant down for two scheduled maintenance
      outages.




Prospective
Information:




·
            Corn
      – corn prices have remained fairly constant during January - March
      2010.  There has been a relative strengthening of corn prices
      vs. ethanol prices which has decreased margins in early 2010 compared to
      the fourth quarter of 2009.  We cannot be certain how the price
      of corn will change as it is a market driven
  commodity.




·
            Energy
      needs – we have contracts in place for our main energy
      needs.  See below for information on our main energy
      costs:




o
            Coal
      – we entered into a new two year coal supply agreement during
      2009.  Our raw coal costs increased approximately 6% under this
      new agreement.  We anticipate that our coal costs for 2010 will
      be slightly higher during 2010 due to this price increase.  A
      portion of our coal cost is related to removing and disposing of the ash
      generated from burning the coal.  We currently pay to dispose of
      this waste.  We are in the process of exploring alternative uses
      for our ash which may allow us to eliminate the cost of
      disposal.  If we are successful in this venture we would
      anticipate a reduction in our coal and ash costs of approximately $300,000
      on an annual basis.




o
            Electricity
      – we have an agreement with Roughrider Electric for our electric
      needs.  This contract does not offer price protection, however,
      and we have received notice that our rates will increase approximately 7%
      in 2010 compared to 2009 rates.




·
            Chemicals
      – we have contracts in place for our chemical supply needs.  The
      contracts call for competitive market pricing.  It is difficult
      to predict the pricing for our chemicals and denaturant as they are market
      driven commodities.  Through February 2010 we have seen some
      small increases in our main chemicals and denaturant – based on this
      information we would expect our chemical costs to be higher in 2010
      compared to 2009.




·
            Labor
      costs – we did institute some cost of living wage increases at the end of
      2009 and are also considering the reinstatement of our quarterly bonus
      program.  If the program is reinstated, we would expect our
      labor costs to be slightly higher in 2010 compared to
  2009.




General
and Administrative Expenses




2009 compared to
2008




General
and administrative expenses for 2009 were approximately $44,000 lower than
2008.




·
            A
      decrease of approximately $417,000 in management fees.  Our
      management company is paid a monthly fee plus 4% of our net
      income.  During 2008, the 4% of net income was paid based on our
      quarterly net income which resulted in an expense of approximately
      $325,000 compared to approximately $34,000 for 2009 based on our annual
      net income.




·
            The
      Company also recognized a decrease of in various general and
      administrative costs of approximately $219,000 due to cost cutting
      measures instituted at the beginning of 2009.  We had lower
      board meeting expense costs as our board members suspended their pay for
      2009, we also had lower office supplies expense costs, lower purchased
      services costs and smaller decreases in other
  areas.




The
decrease in general and administrative costs was partially offset
by:




·
            An
      increase in our bank fees of approximately $182,000 as we paid $175,000 in
      fees to our bank related to the negotiation of the principal
      deferral.




·
            An
      increase in legal fees of approximately $170,000 as additional work was
      required on our proxy statement related to the amended and restated member
      control agreement, the development of our corn procurement program and
      various other matters that took place during
  2009.




·
            An
      increase in permitting and licensing fees of approximately
      $154,000.  This included a one-time registration fee of
      approximately $66,000 to complete our registration as a fuel additive
      manufacturer and we also incurred additional permitting costs related to
      our new air permit application.




2008 compared to
2007




General
and administrative expenses decreased approximately $357,000 (11.1%) primarily
due to:




22




·
            A
      decrease of approximately $534,000 in professional service fees (including
      legal, accounting, consulting on permits and other professional services)
      as our employees started to take over additional responsibilities in these
      areas in an effort to reduce our dependence on outside
      services.




The
decrease in general and administrative costs was partially offset
by:




·
            An
      increase in our real estate taxes of approximately $157,000 as 2008
      represented the first year of the phase-out of our tax
      exemption.





Prospective
Information:





·
            We
      anticipate our general and administrative expenses for 2010 to be similar
      to 2009 with the following exceptions:  Our legal fees may
      increase as we move into mediation proceedings with our design
      builder.  We are scheduled to have an increase in our real
      estate taxes of approximately $90,000 as we enter the third year of the
      phase out of our tax exemption.




Interest
Expense




Our
interest costs are made up of the following components:




Interest
      expense for the year ended December 31,
              
              2009
              
              
              2008
              
              
              2007Interest
      expense on long-term debt
              
              $
              2,930,910
              
              
              $
              3,545,910
              
              
              $
              5,160,282Amortization/write-off
      of deferred financing costs
              
              
              567,386
              
              
              
              201,020
              
              
              
              214,169Change
      in fair value of interest rate swaps
              
              
              (500,843
              )
              
              
              1,817,338
              
              
              
              933,256Net
      settlements on interest rate swaps
              
              
              991,463
              
              
              
              449,031
              
              
              
              (39,000
              )Total
      interest expense
              
              $
              3,988,916
              
              
              $
              6,013,299
              
              
              $
              6,268,707




2009 compared to
2008




·
            Interest
      expense on long-term debt – approximately $600,000 lower than 2008 due
      primarily to interest rates that averaged approximately 1% lower during
      2009 than 2008.  The amount reported as interest expense on our
      long-term debt in our Annual Report on Form 10-K for the year ended
      December 31, 2008 was $4 million which included the net settlements on
      interest rate swaps.  This amount has been reported separately
      above.




·
            Amortization
      of deferred financing costs – during the first quarter of 2009 we wrote
      off the remaining balance of our deferred financing costs (approximately
      $517,000) due to uncertainties in our ability to meet our debt obligations
      that existed at the time.




·
            Change
      in fair value of interest rate swaps – we recorded a loss from the change
      in fair value of our interest rate swap during 2008 as interest rates
      decreased which decreases the value of our swap.  During 2009
      the replacement rates on our swaps remained fairly
      constant.  The increase in the fair value of our swaps during
      2009 had more to do with the passage of time - as we get closer to the
      expiration date of our swaps we anticipate the value of the swaps will
      move toward $0.




·
            Net
      settlements on interest rate swaps – the replacement rates on our swaps
      were lower for the whole year in 2009 compared to 2008 which lead to an
      increase in the settlement payments on our
  swaps.




2008
compared to 2007




·
            Interest
      expense on long-term debt – approximately $1.5 million lower than 2007 due
      to lower interest rates and also lower outstanding debt balances for a
      portion of the year as we paid down part of our Long-Term Revolving Note
      as a way to use our excess cash.




·
            Change
      in fair value of interest rate swaps – interest rates continue to decrease
      during 2008 in response to the global economic crisis that developed
      during the last six months of 2008.  The decrease in rates led
      to further declines in the fair value of our interest rate swaps which
      resulted in additional losses.




·
            Net
      settlements on interest rate swaps – as the replacement rates on our swaps
      continued to decline during 2008 and became lower than our swap rates, we
      started to have to make settlement payments on our
  swaps.




Prospective
Information:




Interest
rates stayed relatively constant at very low levels during
2009.  Because variable rates have been so low, the interest rate on
our senior debt for most of 2009 was 6% which is the floor established in the
6th
Amendment to our Construction Loan Agreement.  We do not feel we can
accurately predict interest rates for 2010 as it will largely depend on
government monetary policy.  In general, an increase in interest rates
will have a positive impact on the value of our interest rate swaps but will
increase the amount of interest we pay on the variable interest rate portion of
our notes.




23




Other
Income and Expense


Other
income includes payments from our state ethanol incentive program, interest
income and grant income.  Other income, net was approximately $1.2
million, $2.6 million and $800,000 for the fiscal years ended December 31, 2009,
2008 and 2007, respectively.




During
2009, conditions were met that triggered payments to be made under the state of
North Dakota’s ethanol incentive program.  We received approximately
$660,000 and $2.1 million and $0 under this program during 2009, 2008 and 2007,
respectively.  The program had a minimal amount of available funds at
the end of 2009 and will not be funded again until June 2010.  We
cannot accurately predict how much we may receive from this program in the
future and the amount could ultimately be $0.




Interest
income was approximately $470,000, $426,000 and $432,000 for the fiscal years
ended December 31, 2009, 2008 and 2007, respectively.




·
            2009
      interest income – primarily the result of interest earned on sales and use
      tax paid during Plant construction as explained below.  We
      received the remaining portion of the sales tax refund during 2009 which
      included interest of approximately $390,000.  The remaining
      interest income of approximately $80,000 was made up of interest earned on
      cash balances and finance charges charged to
  customers.




·
            2008
      interest income – primarily the result of interest earned on sales and use
      tax paid during Plant construction.  We received an exemption
      from sales and use tax for items used in the construction of our
      Plant.  Because our general contractor paid for most of the
      items and then billed us they had to pay the requisite sales and use tax
      and then turn around and request a refund of those amounts.  Due
      to the volume of invoices for materials used to construct the Plant a
      refund request was not completed until June 2008.  We have
      received a portion of the refund along with interest.  The
      interest portion totaled approximately $380,000.  The remaining
      interest income of approximately $46,000 was derived from excess operating
      cash and approximately $4.2 million set aside to cover the final
      construction costs that have not been paid to our general
      contractor.




·
            2007
      interest income – primarily the result of funds held in money market
      accounts.  The funds consisted of excess operating cash along
      with approximately $3.9 million set aside to cover the final construction
      costs that have not been paid to
Fagen.




Grant
income was approximately $37,000, $73,000 and $27,750 for the fiscal years ended
December 31, 2009, 2008 and 2007, respectively.  We do not anticipate
receiving any significant grant income during 2010.




Prospective
Information:




During
January 2010, we did record a business interruption insurance settlement of
approximately $983,000 related to the unplanned outage we experienced in October
2009.  We do not anticipate receiving any other significant amount of
other income during 2010.  We also do not anticipate receiving a
significant amount of interest income during 2010.  We do anticipate
receiving interest income on the cash set aside to pay our general contractor
for the final construction costs but, based on current interest rates paid on
deposits, feel the amount will not be material.




Plant
Operations




Operations
of Ethanol Plant




We
produced approximately 49.8 million gallons of ethanol in 2009 which is
approximately 100% of name-plate capacity.  At various times during
2009 we operated the plant at a reduced rate for economic
reasons.  Management will continue to evaluate the plant production
rate based on a number of factors, including market economics and corn
availability.  Based on margins that currently exist in the industry
we anticipate running the plant at what we consider its normal rate which would
lead to production of approximately 54 million gallons of ethanol.




Due to
the improvement in margins, the timely negotiation of the deferral of two
principal payments with the Bank during 2009 and various cost containment
measures implemented during 2009 the Company is now in a better financial
position than at the end of 2008.  We project that, under current
market conditions, we will maintain compliance with our loan covenants, meet our
debt obligations and be able to fund our operations through cash generated from
operations during 2010.




Critical
Accounting Estimates




Management
uses estimates and assumptions in preparing our financial statements in
accordance with generally accepted accounting principles. These estimates and
assumptions affect the reported amounts of assets and liabilities, the
disclosure of contingent assets and liabilities, and the reported revenues and
expenses. Of the significant accounting policies described in the notes to our
financial statements, we believe that the following are the most critical.




Derivative
Instruments




From time
to time the Company may enter into derivative transactions to hedge its exposure
to commodity price and interest rate fluctuations.  The Company is
required to record these derivatives on the balance sheet at fair
value.




In order
to reduce the risk caused by market fluctuations of corn, ethanol and interest
rates, we enter into option, futures and swap contracts. These contracts are
used to fix the purchase price of our anticipated requirements of corn in
production activities and the selling price of our ethanol product and limit the
effect of increases in interest rates. The fair value of these contracts is
based on quoted prices in active exchange-traded or over-the-counter markets and
discounted cash flow analysis on the expected cash flows of each instrument. The
fair value of the derivatives is continually subject to change due to the
changes in market conditions and interest rates. We do not typically enter into
derivative instruments other than for hedging purposes.  On the date
the derivative instrument is entered into, we will designate the derivative as
either a hedge of the variability of cash flows of a forecasted transaction or
will not designate the derivative as a hedge.  Currently, none of our
derivative instruments are classified as a cash flow hedge for accounting
purposes. Changes in the fair value of a derivative instrument that is
designated and meets all of the required criteria for a cash flow or fair value
hedge is recorded in accumulated other comprehensive income and reclassified
into earnings as the hedged items affect earnings. Changes in fair value of a
derivative instrument that is not designated and accounted for as a cash flow or
fair value hedge is recorded in current period earnings. Although certain
derivative instruments may not be designated and accounted for as a cash flow or
fair value hedge, they are effective economic hedges of specific
risks.




24




Inventory




We value
our inventory at the lower of cost or market.  Our estimates are based
upon assumptions believed to be reasonable, but which are inherently uncertain
and unpredictable.  These valuations require the use of management’s
assumptions which do not reflect unanticipated events and circumstances that may
occur.  In our analysis, we consider future corn costs, ethanol prices
and distillers gains prices, the effective yield and estimated future profit
margins.  Our inventory consists of raw materials, work in process,
and finished goods. The work in process inventory is based on certain
assumptions. The assumptions used in calculating work in process are the
quantities in the fermenter and beer well tanks, the lower of cost or market
price used to value corn at the end of the month, the effective yield, and the
amount of dried distillers grains assumed to be in the tanks.




Commitments and
Contingencies




Contingencies,
by their nature, relate to uncertainties that require management to exercise
judgment both in assessing the likelihood that a liability has been incurred, as
well as in estimating the amount of the potential expense. In conformity with
United States generally accepted accounting principles, we accrue an expense
when it is probable that a liability has been incurred and the amount can be
reasonably estimated.




Long-Lived
Assets




Depreciation
and amortization of our property, plant and equipment is applied on the
straight-line method by charges to operations at rates based upon the expected
useful lives of individual or groups of assets placed in service. Economic
circumstances or other factors may cause management’s estimates of expected
useful lives to differ from the actual useful lives. Differences between
estimated lives and actual lives may be significant, but management does not
expect events that occur during the normal operation of our Plant related to
estimated useful lives to have a significant effect on results of
operations.




Long-lived
assets, including property, plant and equipment are evaluated for impairment on
the basis of undiscounted cash flows whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable. An
impaired asset is written down to its estimated fair market value based on the
best information available. Considerable management judgment is necessary to
estimate future cash flows and may differ from actual cash flows. Management
does not expect that an impairment of assets will exist based on their
assessment of the risks and rewards related to the ownership of these assets and
the expected cash flows generated from the operation of the Plant.




Liquidity and Capital Commitments




Statement
      of Cash Flows for the years ended December 31,
              
              2009
              
              
              2008
              
              
              2007Cash
      flows from operating activities
              
              $
              7,936,258
              
              
              $
              8,495,564
              
              
              $
              2,684,633Cash
      flows from (used in) investing activities
              
              
              532,170
              
              
              
              (2,300,195
              )
              
              
              (3,974,839
              )Cash
      flows from (used in) financing activities
              
              
              311,824
              
              
              
              (9,993,239
              )
              
              
              9,100,193





Cash
flows




As noted
in the footnotes to the financial statements on page F-7 of this Annual Report,
certain items in the cash flow statement have been reclassified to conform to
the presentation provided in fiscal year 2009.  The reclassification
had no effect on total operating, investing or financing cash flows, net income
(loss) or members’ equity as previously reported.




Operating
activities.




Typically
our net income (loss) before depreciation, amortization and certain other
noncash charges is a significant contributor to cash flows from operating
activities. The changes in cash flows from operating activities generally follow
the results of operations as discussed in Financial and Operating Data and also
are affected by changes in working capital.




2009 Compared to
2008




Cash
flows provided by operating activities in 2009 decreased approximately $600,000
from the comparable prior period, as a result of:




·
            A
      net decrease in the change in various non-cash charges of approximately
      $2.9 million primarily related to a decrease in the change in market value
      of our interest rates swaps and other derivative instruments of
      approximately $3.4 offset by an increase in depreciation of approximately
      $100,000 and an increase in amortization of approximately $360,000 due to
      the write-off of our remaining deferred financing costs earlier in
      2009.




25




·
            A
      net decrease in cash flow from changes in working capital items of
      approximately $3.4 million.  This change is primarily the result
      of a decrease in the change in the accrual for our loss on firm purchase
      commitments of approximately $2.9 million along with normal changes in
      other working capital items of approximately
  $500,000.




Partially
offsetting the decrease in cash flows from working capital items
was:




·
            An
      increase in net income of approximately $5.7 million.  Please
      review the “Results of Operations” for an in depth explanation of our net
      income for 2009 as compared to
2008.


2008 Compared to
2007




Cash
flows provided by operating activities in 2008 increased $5.8 million from the
comparable prior period, as a result of:




·
            A
      net increase in cash flow from changes in working capital items of
      approximately $11.9 million.  This change is primarily the
      result of:




o
            A
      net decrease in cash flow from working capital items during 2007 as the
      Plant started operations.  Most production related working
      capital items started at a balance close to zero on January 1, 2007 and
      were built to their resulting balance at the end of December 31, 2007
      through normal plant operations.  This resulted in a net use of
      cash from changes in working capital items of approximately $7.4
      million.




o
            At
      December 31, 2008, the change in the balance of our working capital items
      resulted in a positive cash flow of approximately $4.5 million - primarily
      as a result of the following:




§
            Our
      receivable balances were lower by approximately $3.3 million due to lower
      ethanol prices.




§
            The
      combined total of inventory and prepaid inventory  decreased
      approximately $557,000 due lower inventories on hand, the result of normal
      fluctuations and timing of production and delivery of
  corn.




§
            The
      cash held in our margin account was lower by approximately $1.5 million as
      our risk management committee had reduced our hedging position in response
      to the uncertain market conditions.




§
            An
      increase in the accrued loss on firm purchase commitments of approximately
      $1.4 million




Offset in
part by:




§
            Our
      accounts payable and accrued expenses decreased by a combined $1.8 million
      due to lower inventories being maintained and the fluctuations due to the
      timing of purchases.




§
            Net
      settlements on our interest rate swaps of approximately
      $450,000




·
            A
      net increase in various non-cash charges of approximately $5.4 primarily
      related to an increase in the change in the fair value of our hedging
      derivative instruments of approximately $4 million and an increase in the
      change in the fair value of our interest rates swaps of approximately $1.4
      million




Partially
offsetting the increase in cash flows from working capital items
was:




·
            A
      decrease in net income of approximately $11.5 million.  Please
      review the “Results of Operations” for an in depth explanation of our net
      income for 2008 as compared to
2007.




Investing
activities.




Cash
flows used in investing activities in 2009 decreased $2.8 million compared to
2008, the result of lower capital expenditures in 2009.  We had very
minimal capital expenditures during 2009 as we didn’t have any major projects to
complete and conserved cash in an effort to maintain liquidity.  We
also received a refund of sales tax amounts paid on the original construction of
our plant which reduced the cost of our plant and are shown as an offset to our
capital expenditures on the cash flow statement.  We had one major
capital project during 2008 which was our coal unloading facility.




Cash
flows used in investing activities in 2008 decreased $1.7 million compared to
2007, the result of lower capital expenditures in 2008.  We only had
one major capital project during 2008 which was to build a coal unloading
facility on our site.  The capital expenditures made during 2007 were
made to finalize Plant construction.




Financing
activities.




Cash
flows used in financing activities in 2009 decreased $10.3 million compared to
2008 primarily related to lower debt payments in 2009 and borrowing the
remaining capacity on our Long-Term Revolving note during 2009.  Our
bank allowed us to defer two principal payments during 2009 which decreased our
debt service requirements by approximately $2.2 million.  These
payments will be added to the end of the term of the loan.  We made
scheduled debt service payments of approximately $2.5 million.  In
addition we borrowed the remaining $3.5 million of available capacity on our
Long-Term Revolving note during 2009.




26




Cash
flows used in financing activities in 2008 decreased $19.1 million compared to
2007, primarily the result of a transition to debt service.  We
borrowed approximately $9.3 million of long-term debt under our construction
loan agreements during 2007 as Plant construction was
finalized.  During 2008 we made principal payments of approximately
$10.1 million on our long term debt.  This consisted of our scheduled
principal payments of approximately $4.3 million along with an additional
principal payment of $2.3 million in accord with the excess cash flow payment
terms of our note agreements.  In addition we made a temporary pay
down of $3.5 million on our Long-Term Revolving note as a way to better use our
excess cash.






Capital
Expenditures




We did
not incur any significant capital expenditures during 2009 and had one major
project during 2008 which was the construction of our coal unloading
facility.  For 2010 we anticipate that we may have approximately
$500,000 of capital expenditures related to the replacement of certain rolling
stock and upgrades to our Plant.  We could also have additional
capital expenditures related to meeting emissions requirements and/or preparing
to try and meet requirements of low-carbon fuel standards.  At this
time we cannot accurately estimate the dollar amount of these potential
expenditures and whether we would be able to fund them from
operations.  Based on our projections as of March 2010, we believe we
can fund our planned capital expenditures from our operating cash flows and/or
financing options that may be available to us.




Capital
Resources




We are
subject to a number of covenants and restrictions in connection with our credit
facilities, including:





•
            
            Providing
      the Bank with current and accurate financial
statements;•
            
            Maintaining
      certain financial ratios including minimum net worth, working capital and
      fixed charge coverage ratio;•
            
            Maintaining
      adequate insurance;•
            
            Make,
      or allow to be made, any significant change in our business or tax
      structure; and•
            
            Limiting
      our ability to make distributions to
members.




The
original construction loan agreement, as amended, also contains a number of
events of default (including violation of our loan covenants) which, if any of
them were to occur, would give the Bank certain rights, including but not
limited to:





•
            
            declaring
      all the debt owed to the Bank immediately due and payable;
    and•
            
            taking
      possession of all of our assets, including any contract
      rights.




The Bank
could then sell all of our assets or business and apply any proceeds to repay
their loans. We would continue to be liable to repay any loan amounts still
outstanding.




During
2009, we successfully negotiated the deferral of two principal payments with our
Bank which allowed us sufficient liquidity to continue operations through
2009.  In March 2010, we also entered into the 7th
Amendment which changed the definition of some of our loan covenants and waived
all prior covenant violations.  These changes allowed us to regain
compliance with all of our loan covenants as of December 31, 2009, and we
project that, under market conditions that exist during March 2010 and our
assumptions about future market conditions, we will maintain compliance with
those covenants throughout 2010.  Our projections assume slight
improvement in the spread between ethanol and corn prices during the last six
months of 2010 as we anticipate that the current oversupply situation will be
mitigated, in part, by an increase in gasoline demand through the summer driving
season and more discretionary blending due to the significant favorable spread
that currently exists between gasoline and ethanol prices (when ethanol prices
are lower than gasoline prices, blenders have an incentive to blend more ethanol
into gasoline).




As of
February 2010, we had available cash of approximately $10 million.  We
did not have any available borrowing capacity as our Bank did not renew our $3.5
million line of credit when it expired in July 2009.  Our available
cash does not include approximately $4.2 million that has been aside in
conjunction with amounts withheld from Fagen as described earlier in this
document.  Under current market conditions and our assumptions about
future margins, we anticipate that we will have sufficient available capital to
meet all of our obligations during 2010.




Short-Term
Debt Sources




We do not
currently have any short-term debt sources as our $3.5 million line of credit
was not renewed during July 2009.  Under current market conditions and
our assumptions about future margins, we would not anticipate needing to borrow
any funds from a short-term line of credit to fund our operations during
2010.




27




Long-Term
Debt Sources




The
Company has four long-term notes (collectively the “Term Notes”) in place as of
December 31, 2009.  Three of the notes were established in conjunction
with the termination of the original construction loan agreement on April 16,
2007.  The fourth note was entered into during December 2007 (the
“December 2007 Fixed Rate Note”) when the Company entered into a second interest
rate swap agreement which effectively fixed the interest rate on an additional
$10 million of debt.  The construction loan agreement requires the
Company to maintain certain financial ratios and meet certain non-financial
covenants.  Each note has specific interest rates and terms as
described below.




Term
Notes - Construction Loan




Outstanding
      Balance (Millions)
              
              
              
              Interest
      Rate
              
              
              
              Range of Estimated Quarterly
      Principal
              
              
              
              Estimated
      FinalTerm
      Note
              
              
              December
      31, 2009
              
              
              
              December
      31, 2008
              
              
              
              December
      31, 2009
              
              
              
              December
      31, 2008
              
              
              
              Payment
      Amounts
              
              
              
              Payment
      (millions)
              
              
              
              NotesFixed
      Rate Note
              
              $
              23.60
              
              
              $
              24.70
              
              
              
              6.00
              %
              
              
              5.79
              %
              
              $
              540,000
      - $650,000
              
              
              $
              18.30
              
              
              
              1,
      2, 4Variable
      Rate Note
              
              
              2.10
              
              
              
              3.00
              
              
              
              6.00
              %
              
              
              6.04
              %
              
              $
              450,000
      - $460,000
              
              
              
              1.20
              
              
              
              1,
      2, 3, 5Long-Term
      Revolving Note
              
              
              10.00
              
              
              
              6.40
              
              
              
              6.00
              %
              
              
              5.74
              %
              
              $
              277,000
      - $535,000
              
              
              
              7.70
              
              
              
              1,
      2, 6, 72007
      Fixed Rate Note
              
              
              8.80
              
              
              
              9.20
              
              
              
              6.00
              %
              
              
              6.19
              %
              
              $
              200,000
      - $239,000
              
              
              
              6.10
              
              
              
              1,
      2, 5
  Notes
  1
      -
                The
      scheduled maturity date is April
2012
  2
      -
                  Range
      of estimated quarterly principal payments is based on principal balances
      and interest rates as of December 31,
2009
  3
      -
                  Quarterly
      payments of $634,700 are applied first to interest on the Long-Term
      Revolving Note, next to accrued interest on theVariable
      Rate Note and finally to principal on the Variable Rate
      Note.  Variable Rate Note is estimated to be paid off in April
      2010 asExcess
      Cash Flow payment that is due will be applied to the Variable Rate Note
      and to the Long-Term Revolving
Note.
  4
      -
                Interest
      rate based on 5.0% over three-month LIBOR with a 6% minimum, reset
      quarterly
  5
      -
                Interest
      rate based on 5.0% over three-month LIBOR with a 6% minimum, reset
      quarterly
  6
      -
                Interest
      rate based on 5.0% over one-month LIBOR with a 6% minimum, reset
      monthly
  7
      -
                Principal
      payments would be made on the Long-Term Revolving Note once the Variable
      Rate Note is paid in full.
  The
Company also has $5.5 million in subordinated debt that matures in February
2011.  Interest is charged on these notes at 2% over the rate charged
on the variable rate note.




Please
see Note 5 to our Financial Statements in this Annual Report for a comprehensive
discussion of our Long-Term Debt Sources.




Interest
Rate Swap Agreements




In
December 2005, we entered into an interest rate swap transaction that
effectively fixed the interest rate at 8.08% on the outstanding principal of the
Fixed Rate Note.  In December 2007, we entered into a second interest
rate swap transaction that effectively fixed the interest rate at 7.695% on the
outstanding principal of the December 2007 Fixed Rate Note.




The
interest rate swaps were not designated as either a cash flow or fair value
hedge. Market value adjustments and net settlements were recorded in interest
expense.




Letters
of Credit




During
2009, the Company issued $750,000 in letters of credit from the Bank in
conjunction with the issuance of two bonds needed for
operations.  There is no expiration date on the letters of credit and
the Company does not anticipate the Bank having to advance any funds under these
letters of credit.  The $137,000 letter of credit that was outstanding
at December 31, 2008 has been allowed to expire.




Contractual
Obligations and Commercial Commitments




We have
the following contractual obligations as of December 31, 2009:




Contractual
      Obligations
              
              Total
              
              
              Less
      than 1 Yr
              
              
              1-3
      Years
              
              
              3-5
      Years
              
              
              More
      than 5 YrsLong-term
      debt obligations *
              
              $
              57,494,934
              
              
              $
              9,911,028
              
              
              $
              47,561,776
              
              
              $
              22,130
              
              
              $
              ―Capital
      leases
              
              
              56,978
              
              
              
              45,518
              
              
              
              6,708
              
              
              
              4,752
              
              
              
              ―Operating
      lease obligations
              
              
              1,411,065
              
              
              
              489,660
              
              
              
              886,705
              
              
              
              34,700
              
              
              
              ―Corn
      Purchases **
              
              
              4,095,920
              
              
              
              4,095,920
              
              
              
              ―
              
              
              
              ―
              
              
              
              ―Coal
      purchases
              
              
              2,895,300
              
              
              
              1,408,050
              
              
              
              1,487,250
              
              
              
              ―
              
              
              
              ―Contractual
      Obligation
              
              
              176,000
              
              
              
              176,000
              
              
              
              ―
              
              
              
              ―
              
              
              
              ―Management
      Agreement
              
              
              343,200
              
              
              
              171,600
              
              
              
              171,600
              
              
              
              ―
              
              
              
              ―Water
      purchases
              
              
              2,844,800
              
              
              
              406,400
              
              
              
              812,800
              
              
              
              812,800
              
              
              
              812,800Total
              
              $
              69,318,197
              
              
              $
              16,704,176
              
              
              $
              50,926,839
              
              
              $
              874,382
              
              
              $
              812,800







* -
Long-term debt obligations shown in this table are based on the scheduled
payments contained in the Term Notes including the effects of the waiver of
principal and interest rate floor provided for in the Sixth Amendment as well as
provisions of the Seventh Amendment.  We used the rates fixed in the
interest rate swap agreements (see “Interest Rate Swap
Agreements” in Note 5 to our audited financial statements) for the Fixed
Rate Note and December 2007 Fixed Rate Note, respectively which should account
for possible net cash settlements on the interest rate swaps.




** -
Amounts determined assuming prices, including freight costs, at which corn had
been contracted for cash corn contracts and current market prices as of December
31, 2009 for basis contracts that had not yet been fixed.




28




Grants




In 2006,
we entered into a contract with the State of North Dakota through the Industrial
Commission for a lignite coal grant not to exceed $350,000.  We
received $275,000 from this grant during 2006.  We are in the process
of submitting the final report to the Industrial Commission at which time
repayment of the grant will commence.   Because we have not met
the minimum lignite usage requirements specified in the grant for any year in
which the Plant has operated, we expect to repay the grant at a rate of
approximately $35,000 per year.  This repayment could begin in
2010.




We have
entered into an agreement with Job Service North Dakota for a new jobs training
program. This program provides incentives to businesses that are creating new
employment opportunities through business expansion and relocation to the state.
The program provides no-cost funding to help offset the cost of
training.  We will receive up to approximately $270,000 over ten
years. For the years ended December 31, 2009, 2008 and 2007 we received
approximately $37,000, $73,000 and $0, respectively.  We anticipate
receiving approximately $40,000 from this grant for the year ended December 31,
2010.




North
Dakota Ethanol Incentive Program




Under the
program, eligible ethanol plants may receive a production incentive based on the
average North Dakota price per bushel of corn received by farmers during the
quarter, as established by the North Dakota agricultural statistics service, and
the average North Dakota rack price per gallon of ethanol during the quarter, as
compiled by AXXIS Petroleum. We received approximately $660,000, $2.1 million
and $0 from this program during 2009, 2008 and 2007,
respectively.  Because we cannot predict the future prices of corn and
ethanol, we cannot predict whether we will receive any funds in the
future.  The fund used to pay for this incentive program receives most
of its funds on an annual basis.  Currently, there are no funds
available for this program and it will not be funded again until June
2010.  The incentive received is calculated by using the sum arrived
at for the corn price average and for the ethanol price average as calculated in
number 1 and number 2 below:





1.
            
            Corn Price
      :a.
            
            For
      every cent that the average quarterly price per bushel of corn exceeds
      $1.80, the state shall add to the amounts payable under the program $.001
      multiplied by the number of gallons of ethanol produced by the facility
      during the quarter.b.
            
            If
      the average quarterly price per bushel of corn is exactly $1.80, the state
      shall not add anything to the amount payable under the
      program.c.
            
            For
      every cent that the average quarterly price per bushel of corn is below
      $1.80, the state shall subtract from the amounts payable under the program
      $.001 multiplied by the number of gallons of ethanol produced by the
      facility during the quarter.2.
            
            Ethanol
      Price:a.
            
            For
      every cent that the average quarterly rack price per gallon of ethanol is
      above $1.30, the state shall subtract from the amounts payable under the
      program $.002 multiplied by the number of gallons of ethanol produced by
      the facility during the quarter.b.
            
            If
      the average quarterly price per gallon of ethanol is exactly $1.30, the
      state shall not add anything to the amount payable under the
      program.c.
            
            For
      every cent that the average quarterly rack price per gallon of ethanol is
      below $1.30, the state shall add to the amounts payable under the program
      $.002 multiplied by the number of gallons of ethanol produced by the
      facility during the quarter.




Under the
program, no facility may receive payments in excess of $1.6 million during the
State of North Dakota’s fiscal year (July 1 – June 30).  If corn
prices are low compared to historical averages and ethanol prices are high
compared to historical averages, we will receive little or no funds from this
program.




Off-Balance
Sheet Arrangements




We do not
have any off-balance sheet arrangements.




ITEM 7A QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK.




29




We are
exposed to the impact of market fluctuations associated with interest rates and
commodity prices as discussed below. We have no exposure to foreign currency
risk as all of our business is conducted in Unites States Dollars. We use
derivative financial instruments as part of an overall strategy to manage market
risk. We use cash, futures and option contracts to hedge changes to the
commodity prices of corn and we use ethanol swaps to hedge changes in the
commodity price of ethanol.  We do not enter into these derivativefinancial instruments for trading or speculative purposes, nor
do we designate these contracts as hedges for accounting purposes pursuant to
the requirements of SFAS 133, Accounting for Derivative
Instruments and Hedging Activities.




Interest
Rate Risk




We are
exposed to market risk from changes in interest rates. Exposure to interest rate
risk results primarily from holding a revolving promissory note and construction
term notes which bear variable interest rates. Approximately $17.6 million of
our outstanding long-term debt is at a variable rate as of December 31,
2009.  The Sixth Amendment to our Construction Loan Agreement places a
minimum interest rate of 6% on our long-term debt outstanding with FNBO and
increased the spread on the variable rate notes to 400 basis points over the
one-month or three-month LIBOR rates.  One-month and three-month LIBOR
rates were very low as of December 31, 2009 and, therefore, the interest rate on
our debt was set at the floor of 6%.  Because of the interest rate
floor placed on our debt we will not benefit from a decrease in rates from their
current levels.  We anticipate that a hypothetical 1% increase in
interest rates, from those in effect on December 31, 2009, would have a minimal
impact on our interest expense as the variable rates noted above are almost 1%
lower than the interest rate floor.  In order to achieve a fixed
interest rate on the construction loan and reduce our risk to fluctuating
interest rates, we entered into an interest rate swap contract that effectively
fixes the interest rate at 8.08% on approximately $23.6 million of the
outstanding principal of the construction loan.  We entered into a
second interest rate swap in December 2007 and effectively fixed the interest
rate at 7.695% on an additional $10 million of our outstanding long-term
debt.  The interest rate swaps are not designated as either a cash
flow or fair value hedge. Fair value adjustments and net settlements are
recorded in interest expense.  We anticipate that a hypothetical 1%
change in interest rates, from those in effect on December 31, 2009, would
change the fair value of our interest rate swaps by approximately
$650,000.




Commodity
Price Risk




We expect
to be exposed to market risk from changes in commodity
prices.  Exposure to commodity price risk results from our dependence
on corn in the ethanol production process and the sale of ethanol.




We enter
in to fixed price contracts for corn purchases on a regular basis.  It
is our intent that, as we enter in to these contracts, we will use various
hedging instruments (puts, calls and futures) to maintain a near even market
position.  For example, if we have 1 million bushels of corn under
fixed price contracts we would generally expect to enter into a short hedge
position to offset our price risk relative to those bushels we have under fixed
price contracts.  Because our ethanol marketing company (RPMG) is
selling substantially all of the gallons it markets on a spot basis we also
include the corn bushel equivalent of the ethanol we have produced that is
inventory but not yet priced as bushels that need to be hedged.




Although
we believe our hedge positions will accomplish an economic hedge against our
future purchases, they are not designated as hedges for accounting purposes,
which would match the gain or loss on our hedge positions to the specific
commodity purchase being hedged.  We use fair value accounting for our
hedge positions, which means as the current market price of our hedge positions
changes, the gains and losses are immediately recognized in our cost of
sales.  The immediate recognition of hedging gains and losses under
fair value accounting can cause net income to be volatile from quarter to
quarter and year to year due to the timing of the change in value of derivative
instruments relative to the cost of the commodity being hedged.




As of
December 31, 2009 we had approximately 1.1 million bushels of corn under fixed
price contracts.  These contracts were priced below current market
prices so we did not have any accrued a loss on firm purchase commitments
related to these contracts.  We would expect a sustained $0.10 change
in the price of corn to have an approximate $110,000 impact on our net
income.




We
entered into ethanol swap contracts and corn futures and options positions
equivalent to approximately 3.2 million bushels of corn to offset our net long
position which includes corn in inventory, corn purchased under fixed price
contracts and corn converted to ethanol but not yet priced.  The
immediate recognition of hedging gains and losses under fair value accounting
can cause net income to be volatile from quarter to quarter due to the timing of
the change in value of the derivative instruments relative to the cost and use
of the commodity being hedged.  There are several variables that could
affect the extent to which our derivative instruments are impacted by price
fluctuations in the cost of corn or ethanol.  However, it is likely
that commodity cash prices will have the greatest impact on the derivatives
instruments with delivery dates nearest the current cash price.




It is the
current position of RPMG (our ethanol marketing company) that, under current
market conditions, selling ethanol in the spot market will yield the best price
for our ethanol.  RPMG will, from time to time, contract a portion of
the gallons they market with fixed price contracts.  We had no fixed
price contracts for the sale of physical ethanol outstanding at December 31,
2009 or 2008.




We
estimate that our expected corn usage will be between 18 million and 20
million bushels per year for the production of approximately 50 million to 54
million gallons of ethanol.  As corn prices move in reaction to market
trends and information, our income statements will be affected depending on the
impact such market movements have on the value of our derivative
instruments.




To manage
our coal price risk, we entered into a coal purchase agreement with our supplier
to supply us with coal, fixing the price at which we purchase coal. If we are
unable to continue buying coal under this agreement, we may have to buy coal in
the open market.




30




ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.




Our
financial statements and supplementary data are included on pages F-1 to F-22 of
this Report.




ITEM 9. CHANGES IN AND
DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES.




Boulay,
Heutmaker, Zibell & Co., P.L.L.P. has been our independent auditor since
2005 and is our independent auditor at the present time. We have had no
disagreements with our auditors.




ITEM 9A(T). CONTROLS
AND PROCEDURES.





Evaluation of
Disclosure Controls and Procedures





We
conducted an evaluation under the supervision and with the participation of our
management, including our Chief Executive Officer and Chief Financial Officer of
the effectiveness of the design and operation of our disclosure controls and
procedures.  The term “disclosure controls and procedures, as defined
in Rule 13a-15(e) and rule 15d-15(e) under the Securities Exchange Act of
1934 (“Exchange Act”), as amended, means controls and other procedures of a
company that are designed to ensure that information required to be disclosed by
the company in the reports it files or submits under the Exchange Act is
recorded, processed, summarized and reported, within the time periods specified
in the Securities and Exchange Commission’s (“SEC”) rules and
forms.  Disclosure controls and procedures also include, without
limitation, controls and procedures designed to ensure that information required
to be disclosed by a company in the reports that it files or submits under the
Exchange Act is accumulated and communicated to the company’s management,
including its principal executive and principal financial officers, or persons
performing similar functions, as appropriate, to allow timely decisions
regarding required disclosure.




Our Chief
Executive Officer and Chief Financial Officer, after evaluating the
effectiveness of our disclosure controls and procedures as of December 31, 2009,
have concluded that our disclosure controls and procedures are effective and are
adequately designed to ensure that information required to be disclosed by us in
the reports we file or submit under with the Exchange Act is recorded,
processed, summarized and reported, within the time periods specified in the
applicable rules and forms.





Management’s
Annual Report on Internal Control Over Financial Reporting





Management
is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the Company.   Management assessed the effectiveness of our
internal control over financial reporting as of December 31, 2009. In making
this assessment, management used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control–Integrated Framework.





Based on
our evaluation under the framework in Internal Control–Integrated Framework,
management concluded that our internal control over financial reporting was
effective as of December 31, 2009.





This
report does not include an attestation report of our registered public
accounting firm regarding internal control over financial
reporting.  Management’s report was not subject to the attestation by
our registered public accounting firm pursuant to temporary rules of the SEC
that permit us to provide only management’s report in this Annual
Report.





Changes in Internal
Controls





There
have been no changes in our internal control over financial reporting (as
defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the
fiscal quarter ended December 31, 2009, that have materially affected, or are
reasonably likely to materially affect, the Company’s internal control over
financial reporting.





Inherent
Limitations on the Effectiveness of Controls





Management
does not expect that our disclosure controls and procedures or our internal
control over financial reporting will prevent or detect all errors and all
fraud.  A control system, no matter how well conceived and operated,
can provide only reasonable, not absolute, assurance that objectives of the
control systems are met.  Further, the design of a control system must
reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs.  Because of the
inherent limitations in a cost-effective control system, no evaluation of
internal controls over financial reporting can provide absolute assurance that
misstatements due to error or fraud will not occur or that all control issues
and instances of fraud, if any, have been detected or will be
detected.





These
inherent limitations include the realities that judgments in decision-making can
be faulty and that breakdowns can occur because of a simple error or
mistake.  Controls can also be circumvented by the individual acts of
some persons, by collusion of two or more people, or by management override of
the controls.  The design of any system of controls is based in part
on certain assumptions about the likelihood of future events, and there can be
no assurance that any design will succeed in achieving its stated goals under
all potential future conditions.  Projections of any evaluation of
controls effectiveness to future periods are subject to risks.  Over
time, controls may become inadequate because of changes in conditions or
deterioration in the degree of compliance with policies and
procedures.





31




All
internal control systems, no matter how well designed, have inherent
limitations. Therefore, even those systems determined to be effective can
provide only reasonable assurance with respect to financial statement
preparation and presentation. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to
the risk that controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may
deteriorate.




ITEM 9B. OTHER
INFORMATION




None.




PART
III





ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE




Red Trail
Energy has seven (7) governors.  Each governor is elected to a three
year term.  The terms of the governors are staggered, so that the
terms of two governors expire in one year (Group I), two expire the next year
(Group II), and three expire the following year (Group III).  The
staggering of the terms of the governors commenced at the Annual Meeting of the
members which was held on May 30, 2007, at which meeting two governors were
elected to an initial one year term, two governors were elected to an initial
two year term, and three governors were elected to an initial three year
term.  The governors’ seats, as voted on at the 2007 Annual Meeting,
were assigned to a class as follows:





Group I:   Jody Hoff and
Ronald Aberle


Group II:  Mike Appert and
William Price


Group III: Tim Meuchel, Frank
Kirschenheiter and Roger Berglund (now filled by Sid Mauch)





The
initial two year term of the governors in Group II expired at the 2009 Annual
Meeting and the Group II governor seats were filled via the election of Mr.
Price and Mr. Appert for an additional three-year term.  The initial
three year term of governors in Group III expires at the 2010 Annual Meeting,
and nominees elected at the 2010 Annual Meeting will serve for an additional
three year term that will expire at the 2013 Annual Meeting.  One
Group III governor, Roger Berglund, resigned as a governor of the Company
effective December 10, 2008.  At a March 31, 2009 Board of Governors
meeting, the Board filled Mr. Berglund’s seat by the appointment of Sid Mauch,
who will serve the remainder of Mr. Berglund’s term.





GOVERNORS





Our
Board of Governors





Our
current Board of Governors consists of seven (7) governors.  The names
and ages of all of our governors and the positions held by each with the Company
are as follows:





Name
            
            Age
            
            PositionMike
      Appert
            
            41
            
            Governor,
      ChairmanWilliam
      Price
            
            47
            
            Governor,
      SecretaryJody
      Hoff
            
            37
            
            Governor,
      Vice ChairmanFrank
      Kirschenheiter
            
            59
            
            Governor,
      TreasurerTim
      Meuchel
            
            51
            
            GovernorRonald
      Aberle
            
            47
            
            GovernorSid
      Mauch
            
            64
            
            Governor




Identification
of Governors




32





Mike
Appert




Mr. Appert
currently serves as the Chairman of the Board of Governors.  He
previously served as Secretary.  He is a member of our Acquisition,
Governance, Nominating and Risk Management Committees and has been a Governor
since our inception.




Mr. Appert
has been the owner and president of Appert Acres, Inc., a corn, soybean,
sunflowers and small grains farming operation since 1991, as well as operating a
Mycogen Seeds Dealership.  He also serves on several boards which
include the Hazelton Airport Authority as president, the Goose Lake
Chapter Pheasants Forever as Treasurer and the Hazelton Lions
Club.




William
Price




Mr. Price
has served as a Governor since our inception and is a member of our Acquisition
Committee.  He served as Vice President from inception of the Company
until May 2007, and currently serves as Secretary and is the chairman of the
Nominating Committee.




Since
1980, Mr. Price has been the managing partner and is currently vice
president of Price Cattle Ranch LLP, a cattle operation.  Since 1997,
he has been the managing partner and is currently the president of Missouri
River Feeders LLP, a feedlot and diversified farm.  He also serves as
a governor of Quality Dairy Growers, LLC, a dairy operation, and is a governor
of Sunnyside Feeds, LLC, a custom feed plant.  Mr. Price is also a
governor of North Dakota Sow Center LLLP, a 10,000 head ISO wean
facility.  Mr. Price is a member of multiple associations,
including the North Dakota Stockmen’s Association, the National Cattlemen’s Beef
Association, and the Great Bend Irrigation District, and has served on the
Missouri Slope Irrigation Board of Governors and served as Chairman of the North
Dakota Feeder Council.




Jody
Hoff




Mr. Hoff
currently serves as Vice Chairman, has served as a Governor since our inception
and serves as the chairman of our Audit Committee and is a member of our
Acquisition, Compensation and Nominating Committees.




Mr. Hoff
is a Mechanical Engineer, registered with the State of North
Dakota.  Since 2002, he has been a partner, vice president, chief
engineer and head of operations of Amber Waves, Inc., a manufacturing
company.  Prior to starting Amber Waves, Inc., Mr. Hoff spent over
five years working for Fagen Engineering where he led a design team working on
commercial and industrial projects including ethanol plant
design.  Mr. Hoff holds a BS degree in mechanical engineering from
North Dakota State University.




Frank
Kirschenheiter




Mr.
Kirschenheiter currently serves as Treasurer of the Board of Governors and is a
member of our Audit Committee.  He has been a Governor since May
2007.




Mr.
Kirschenheiter has served as the chief executive officer of Charmark
International, LLC since 2005.  He and his wife Earlene are involved
with their children in a small cattle operation.  Mr. Kirschenheiter
has served as the mayor of the City of Richardton for the past 14
years.




Tim
Meuchel




Mr.
Meuchel has been the president of Modern Grain, Inc., a grain elevator located
in Hebron, North Dakota, since 1986.  Mr. Meuchel currently serves as
a member of the Governance, Acquisition and Risk Management.  He has
been a Governor since May 2007.




Ronald
Aberle




Mr. Aberle
has served as a Governor since our inception and is the chairman of our
Nominating Committee and also serves as a member of our Audit, Acquisition,
Compensation, Nominating and Risk Management Committees.




Mr. Aberle
is an owner and managing partner of Aberle Farms, a diversified farm and ranch,
and most recently added an RV Campground to the
enterprise.  Mr. Aberle serves as an Advisory Board member of
U.S. Bank in Bismarck, North Dakota, and is a Trustee of St. Hildegards
Church.




Sid
Mauch




Mr. Mauch
has served as a Governor since March 2009, replacing Roger Berglund, who
resigned as a Governor of the Company in December 2008.  He serves on
our Risk Management committee.




Mr. Mauch
has been the manager and controller of Maple River Grain & Agronomy, LLC, a
grain elevator and agronomy supplier located in Casselton, North Dakota, since
1976.




There are
no material proceedings to which any of our governors or executive officers or
any associates of any of our governors or executive officers are a party adverse
to us or have material interests adverse to us.




INFORMATION ABOUT
OFFICERS




The
names, ages, and positions of our executive officers are as
follows:




Name
            
            Age
            
            PositionCalvin
      Diehl
            
            49
            
            Chief
      Executive OfficerMark
      E. Klimpel
            
            37
            
            Chief
      Financial Officer





33




Calvin
Diehl, Chief Executive Officer




Mr. Diehl
was appointed Chief Executive Officer of the Company on January 1, 2010 and
previously served as the Company’s Grain Merchandiser from December 2008 to
December 2009.  Prior to joining the Company, he was the General
Manager for James Valley Grain, a grain elevator with shuttle car loading
capabilities located in Oakes, North Dakota.  Mr. Diehl was also
previously employed as a field representative with Cenex Harvest States from
June 1996 to June 2005.  In his capacity as a field representative,
Mr. Diehl consulted with various elevators on their financing, insurance and
risk management needs.




Mark
E. Klimpel, Chief Financial Officer




Mr.
Klimpel is currently and has been since October 2007 the Chief Financial Officer
for the Company.  Prior to joining the Company, he worked for Knife
River Corporation in Bismarck, North Dakota beginning in 1998.  At
Knife River he held various positions within the corporate accounting department
and, most recently, was ERP Implementation Project Manager.  Mr.
Klimpel is a Certified Public Accountant with a Bachelors of Accountancy degree
from the University of North Dakota, located in Grand Forks, North
Dakota.




Mick
Miller, Former Chief Executive Officer




Mr. Miller
resigned his position as President and Chief Executive Officer of the Company
effective on June 15, 2009, a position to which he was appointed in August
2006.  From June 2005 to August 2006, he was the General Manager for
the Company.  Prior to joining the Company, he worked for Diversified
Energy Company LLC (DENCO), an ethanol plant in Morris, Minnesota beginning in
September 1999.  At DENCO, Mr. Miller was Operations Supervisor
from July 2000 through May 2002 and Plant Manager from May 2002 to June
2005.  Mr. Miller also served as the Vice President of Operations
for Greenway.  Mr. Miller also represented the Company on the board of
directors of RPMG, Inc.  He has served since May 2005 to the present
on the Advisory Board for the Process Plant Technology Program at Bismarck State
College in Bismarck, North Dakota and has served on the board since October 2006
as the Vice President for the North Dakota Ethanol Producers
Association.




Gerald
Bachmeier, Former Interim Chief Executive Officer




Mr.
Bachmeier was appointed Interim Chief Executive Officer effective on June 15,
2009.  Mr. Bachmeier is also the Chief Manager of our management
consulting company, Greenway, and is also the Company’s largest shareholder
through his affiliation with RTSB, LLC.  Under the terms of the
Management Agreement, Greenway was responsible to provide the Company’s Chief
Executive Officer and Plant Manager.  Upon Mr. Miller’s resignation,
Mr. Bachmeier assumed the duties of Chief Executive Officer pursuant to the
terms of the Management Agreement until he was replaced by Mr. Diehl on January
1, 2010.




Mr.
Bachmeier has been involved in the ethanol industry for the past eighteen years.
He has served as a Plant Manager of Morris Ag Energy and Chief Marketing Manager
of United Ethanol Sales. He was instrumental in the formation of DENCO, LLC and
was the major role player for the acquisition of Morris Ag Energy. He was also
instrumental in the design and construction of DENCO, LLC as it stands today. He
is currently the Chief Manager of DENCO, LLC and Greenway and has held various
board positions with many industry trade groups.




CORPORATE
GOVERNANCE




Governor
Independence




The
Company has voluntarily adopted the NASDAQ Marketplace Rules for determining
whether a governor is independent and our Board of Governors has determined that
three (3) of our current seven (7) governors are “independent” within the
meaning of Rule 4200(a)(15) of the NASDAQ Marketplace Rules.  As a
non-listed issuer, we are not required to comply with the NASDAQ Marketplace
Rules, but have voluntarily adopted the Rule 4200(a)(15)
definition.  Our independent governors under the definition are Jody
Hoff, Sid Mauch and Frank Kirschenheiter.  None of our governors are
officers.  Mike Appert, Ron Aberle and Tim Meuchel are not considered
independent because of their sales of corn to the Company.  William
Price is not considered independent because of his ownership in operations that
purchase distillers grains from the Company.  Transactions with our
governors are based on the same terms and conditions as those that are available
to the public.  In evaluating the independence of our governors, we
considered the following factors:  (i) the business relationships
of our governors; (ii) positions our governors hold with other companies;
(iii) family relationships between our governor and other individuals
involved with the Company; (iv) transactions between our governors and the
Company; and (v) compensation arrangements between our governors and the
Company.




Board
Meetings and Committees; Annual Meeting Attendance




The Board
of Governors generally meets once per month.  The Board of Governors
is directly responsible for governance of the Company.  The Board held
regular meetings on twelve (12) occasions in fiscal 2009; additionally the Board
held six (6) special meetings.  The Board has a standing acquisition
committee, audit committee, compensation committee, governance committee,
nominating committee, and risk management committee.  Each governor
attended 75% or more of the aggregate number of meetings of the Board and of
committees of which he was a member.




34




Member
Communication with the Board of Governors




Members
seeking to communicate with the Board of Governors should submit their written
comments to the Secretary of the Company, P.O. Box 11, 3682 Highway 8 South,
Richardton, ND 58652.  The Secretary will forward all such
communications (excluding routine advertisements and business solicitations and
communications which the Secretary, in his or her sole discretion, deems to be a
security risk or for harassment purposes) to each member of the Board or, if
applicable, to the individual governors(s) named in the
correspondence.




Governor
Attendance at Annual Meeting of Members




The Board
of Governors does not have a policy with regard to governors’ attendance at
annual meetings, but governors are encouraged to attend each Annual
Meeting.  All Board members were present at the 2009 Annual
Meeting.




Code
of Ethics




The
Company has adopted a Code of Business Conduct that applies to all of our
employees, officers and governors, and a Code of Ethics for Senior Financial
Officers that applies to our Chief Executive Officer, Chief Financial Officer or
Controller and other persons performing similar functions.  The Code
of Business Conduct and Code of Ethics are available on the Investors section of
our website at http://redtrailenergyllc.com/investors.  The Company
intends to satisfy the disclosure requirements of Form 8-K involving an
amendment to, or a waiver from, a provision of its code of ethics that applies
to our principal executive officer, principal financial officer, principal
accounting officer or controller, or persons performing similar functions, by
posting such information on the Investors section of our website, located at
http://redtrailenergyllc.com/investors, or in a current report on Form
8-K.




Audit
Committee




The Audit
Committee of the board of governors operates under a charter adopted by the
board of governors on April 9, 2007.  Under the charter, the Audit
Committee must have at least three members.  Our audit committee
members are Mr. Hoff, Mr. Kirschenheiter and Mr. Aberle.  The
chairperson of the Audit Committee is Mr. Hoff.  Our audit committee
currently does not have an individual designated as a financial expert and has
communicated this to the Nominating Committee for their consideration as they
review potential nominees for the board of governors.  The Audit
Committee is exempt from the independence listing standards because the
Company’s securities are not listed on a national securities exchange or listed
in an automated inter-dealer quotation system of a national securities
association or to issuers of such securities.  Under NASDAQ rules 4200
and 4350, a majority of our Audit Committee is independent within the definition
of independence provided by NASDAQ rules 4200 and 4350.  In addition,
our Audit Committee charter requires a majority of our committee members to be
independent.  A majority of the members of our Audit Committee is
independent as required by our Audit Committee charter.





The Audit
Committee held 6 meetings during the fiscal year ended December 31,
2009.  All of our Audit Committee members attended at least 75% of the
audit committee meetings.





Audit
Committee Report




The Audit
Committee delivered the following report to the board of governors of the
Company on March 31, 2010. The following report of the Audit Committee shall not
be deemed to be incorporated by reference in any previous or future documents
filed by the Company with the Securities and Exchange Commission under the
Securities Act of 1933 or the Securities Exchange Act of 1934, except to the
extent that the Company specifically incorporates the report by reference in any
such document.




The Audit
Committee reviews the Company’s financial reporting process on behalf of the
board of governors. Management has the primary responsibility for the financial
statements and the reporting process.  The Company’s independent
auditors are responsible for expressing an opinion on the conformity of the
audited financial statements to generally accepted accounting
principles.  The Audit Committee reviewed and discussed with
management the Company’s audited financial statements as of and for the fiscal
year ended December 31, 2009.  The Audit Committee has discussed with
Boulay, Heutmaker, Zibell & Co. P.L.L.P., its independent auditors, the
matters required to be discussed by ASU section 380 Communication with audit
committees, as amended, by the Auditing Standards Board of the American
Institute of Certified Public Accountants and as adopted by the Public Company
Accounting Oversight Board in Rule 3200T. The Audit Committee has received and
reviewed the written disclosures and the letter to management from Boulay,
Heutmaker, Zibell & Co. P.L.L.P., as required by Independence Standards
Board Standard No. 1, as adopted by the Public Company Accounting Oversight
Board in Rule 3600T, and has discussed with the independent accountants the
independent accountants’ independence.  The Audit Committee has
considered whether the provision of services by Boulay, Heutmaker, Zibell &
Co. P.L.L.P., not related to the audit of the financial statements referred to
above and to the reviews of the interim financial statements included in the
Company’s Forms 10-Q, and concluded that the provision of such services is
compatible with maintaining Boulay, Heutmaker, Zibell & Co. P.L.L.P’s
independence.





Based on
the reviews and discussions referred to above, the audit committee recommended
to the board of governors that the audited financial statements referred to
above be included in the Company’s annual report on Form 10-K for the
fiscal year ended December 31, 2009.





Audit Committee


Jody Hoff, Frank Kirschenheiter, Ron
Aberle


35





Compensation
Committee




The
Company's standing compensation committee consists of Jody Hoff and Ron Aberle,
however, the Company’s board of governors has the overall responsibility for
approving and evaluating the Company's governor and executive compensation
plans, policies and programs.  The compensation committee was formed
primarily to review an employment agreement and make a recommendation to the
board of governors on this matter.  Neither the Company nor the
compensation committee has historically engaged compensation consultants to
assist in determining or recommending the amount or form of executive or
governor compensation, but would consider doing so in those situations where
either the Company or the compensation committee felt it was warranted or
appropriate.  The compensation committee did not hold any meetings
during the fiscal year ended December 31, 2009.





The
compensation committee does not operate under a charter.  The
compensation committee is exempt from the independence listing standards because
the Company's securities are not listed on a national securities exchange or
listed in an automated inter-dealer quotation system or a national securities
association or to issuers of such securities.




SECTION
16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE




Section
16(a) of the Securities Exchange Act of 1934 requires the Company's officers and
governors, and persons who own more than 10% of a registered class of the
Company's equity securities, to file reports of ownership and changes in
ownership with the Securities and Exchange Commission.  Officers,
governors and greater than 10% percent Unit holders are required by SEC
regulation to furnish the Company with copies of all Section 16(a) forms they
file.  All of our Section 16(a) reporting persons timely filed reports
during the fiscal year ended December 31, 2009, except that Jody Hoff and Gerald
Bachmeier failed to file a Form 4 related to various transfers, which were later
reported in a timely filed Form 5.





ITEM 11. EXECUTIVE COMPENSATION




EXECUTIVE OFFICER AND
GOVERNOR COMPENSATION




Compensation
Discussion and Analysis




The
compensation committee has responsibility for establishing, implementing and
regularly monitoring adherence to the Company’s compensation philosophy and
objectives.  The compensation committee ensures that the total compensation
paid to the named Chief Executive Officer and Chief Financial Officer is fair,
reasonable and competitive.


The
compensation committee receives input from the Chief Executive Officer on his
personal performance achievements and that of the employees who report to
him.  This individual performance assessment determines a portion of the
annual compensation for the Chief Executive Officer.




The
compensation committee does its own performance review of the Chief Executive
Officer.  The compensation committee annually evaluates the performance of
our Chief Executive Officer in light of the Company’s goals and objectives and
determines and approves the executive’s compensation level based on this
evaluation.




Compensation
Committee Report




The
compensation committee has reviewed and discussed the Compensation Discussion
and Analysis with management.  Based upon this review and discussion, the
board of governors determined that the Compensation Discussion and Analysis
should be included in this annual report.





Compensation
Committee


Jody
Hoff, Ron Aberle, Mike Appert, William Price, Tim Meuchel, Sid Mauch, Frank
Kirschenheiter




Governors’
compensation




The
following table sets forth all compensation paid or payable by the Company
during the 2009 fiscal year to our governors.





Name
            
            Fees
      Earned or
              Paid
      in Cash
            
            TotalJody
      Hoff
            
            $
            1,000
            
            $
            1,000Mike
      Appert
            
            $
            1,000
            
            $
            1,000Ronald
      Aberle
            
            $
            900
            
            $
            900William
      Price
            
            $
            1,000
            
            $
            1,000Sid
      Mauch
            
            $
            8,400
            
            $
            8,400Tim
      Meuchel
            
            $
            900
            
            $
            900Frank
      Kirschenheiter
            
            $
            500
            
            $
            500





36




Our Board
of Governors adopted a governor compensation policy on July 24,
2007.  However, in December 2008, compensation was suspended on a
voluntary basis and subsequently reinstated during January
2010.  Pursuant to the governor compensation policy, we pay governor
fees as follows:




·
            $500.00 per Board
      meeting




·
              $400.00
      per audit committee meeting




·
            $100.00 per meeting
      for all other committee meetings




The
compensation policy also provides for reimbursement to governors for all
out-of-pocket costs and mileage for travel to and from meetings and other
locations to perform these tasks.




In the
year ending December 31, 2009, the Company had incurred an aggregate of
$13,700 in governor fees and related expenses.




The
following table sets forth all compensation paid or payable by us during the
last two fiscal years to our President and Chief Executive Officer, who
functions as our principal executive officer, and our Chief Financial Officer,
who functions as our principal financial and accounting officer (the “Named
Executive Officers”).  The Company has no other executive officers
that received in excess of $100,000 during the fiscal years ended December 31,
2009 and 2008, respectively.  While the Company does have a standing
compensation committee, the main focus of that committee was to review and
approve the employment agreement entered into with Mr. Klimpel during
2008.  Prior to January 1, 2010, the Chief Executive Officer was an
employee of Greenway Consulting, LLC, our management consulting company and was
compensated pursuant to the terms of our Management Agreement with
Greenway.  The full board was involved in selecting and determining
the compensation for Mr. Diehl who is an employee of the Company.




Summary
      Compensation TableAnnual
      CompensationName
      and Principal Position
              
              Year
              
              Salary
              
              
              Bonus
              
              
              Stock
      Award
              
              
              TotalCalvin
      Diehl(1)
              
              2009
              
              $
              ―
              
              
              $
              ―
              
              
              $
              ―
              
              
              $
              ―Chief
      Executive Officer
              
              2008
              
              $
              ―
              
              
              $
              ―
              
              
              $
              ―
              
              
              $
              ―Gerald
      Bachmeier(2)
              
              2009
              
              $
              76,154
              
              
              $
              ―
              
              
              $
              ―
              
              
              $
              76,154Former
      Chief Executive Officer
              
              2008
              
              $
              ―
              
              
              $
              ―
              
              
              $
              ―
              
              
              $
              ―Mick
      J. Miller(3)
              
              2009
              
              $
              65,154
              
              
              $
              ―
              
              
              $
              ―
              
              
              $
              65,154Former
      Chief Executive Officer
              
              2008
              
              $
              135,000
              
              
              $
              ―
              
              
              $
              15,000
              (4)
              
              $
              150,000Mark
      E Klimpel
              
              2009
              
              $
              119,475
              (7)
              
              $
              25,500
              (6)
              
              $
              ―
              
              
              $
              144,975Chief
      Financial Officer
              
              2008
              
              $
              116,327
              
              
              $
              3,087
              (5)
              
              $
              ―
              
              
              $
              119,414




(1)
            Mr.
      Diehl was appointed Chief Executive Officer on January 1,
      2010.  Mr. Diehl is an employee of Red Trail Energy, LLC where
      our previous Chief Executive Officer’s have been employees of our
      management company – Greenway Consulting, LLC (“Greenway”).  His
      salary for 2010 has been set at
$116,000.




(2)
            Mr.
      Bachmeier was appointed interim Chief Executive Officer on June 15, 2009
      and was compensated pursuant to the Management Agreement with
      Greenway.  Mr. Bachmeier resigned his position as CEO on
      December 31, 2009.




(3)
            Mr.
      Miller resigned his position as CEO effective June 15,
      2009.  Mr. Miller was compensated pursuant to our Management
      Agreement with Greenway.




(4)
            On
      September 8, 2006, Mr. Miller was awarded an equity based, incentive
      compensation award of up to 150,000 Units, effective as of July 7,
      2005, the date he formally began working in the role of General Manager
      (the “Grant Date”).  The first 15,000 Units vested on July 1,
      2008.  All remaining unvested Units were lost upon Mr. Miller’s
      resignation.




(5)
            Bonus
      reflects payment from the employee bonus program for the first quarter of
      fiscal 2008.  Mr. Klimpel ceased participation in the employee
      bonus program upon executing his employment agreement with the Company in
      August 2008.




(6)
            Paid
      pursuant to the terms of Mr. Klimpel’s employment agreement – see
      additional information below under “Employment
      Agreements.”  This reflects payment for 2008 and
      2009.




(7)
            Mr.
      Klimpel voluntarily took a salary reduction at the beginning of 2009 so
      the increase in base salary does not equal
6%.




EMPLOYMENT
AGREEMENTS




As
disclosed in footnotes 2 and 3 to the Summary Compensation Table, Mick Miller
and Gerald Bachmeier, both of whom served as our former Chief Executive Officer,
were compensated pursuant to our Management Agreement with Greenway, executed in
December 2003 and Amended and Restated during 2009.  The original
Management Agreement provided that the Company would reimburse Greenway for the
salary and benefit package of the Chief Executive Officer, in addition to a
monthly payment to Greenway for management of plant operations.  The
Amended and Restated Management Agreement now allows the Company the flexibility
to hire its own Chief Executive Officer.




37




Mark
Klimpel, our Chief Financial Officer, executed a written employment agreement
with the Company in August 2008.  The agreement provides that Mr.
Klimpel’s base salary shall increase at a rate of six percent per year, and that
Mr. Klimpel is eligible for a bonus of 20 percent of base salary per year, which
bonus is based 50% on remaining employed with the Company and 50% on a
performance determination by the Compensation Committee of the Board in
consultation with the President and Chief Executive Officer.  The
Agreement also provides that if Mr. Klimpel is terminated by the Company without
cause or because of a change-in-control, Mr. Klimpel is entitled to unpaid base
salary and benefits up to the date of termination, and six months salary
thereafter.




The
Company recently announced that Mr. Klimpel has resigned his position as the
Company’s Chief Financial Officer effective May 13, 2010.  Pursuant to
the terms of Mr. Klimpel’s employment agreement, the Company is required to pay
any accrued salary and benefits through the effective date of the
resignation.




ITEM
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS




SECURITY OWNERSHIP OF
CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED MEMBER
MATTERS




The
following table sets forth certain information concerning the beneficial
ownership of persons known to management of the Company owning 5% or greater of
the outstanding Class A Membership Units, based on 40,193,973 Units outstanding
as of March 15, 2010, as follows:




Name
      and Address of
              Beneficial
      Owner
            
            Amount
      and Nature of Beneficial Ownership
            
            
            Percent
      ofClassRTSB,
      LLC
            
            
            2,619,500
            (1)
            
            
            6.52
            %3150
      136th
      Avenue NEBaldwin,
      ND  58521







(1)
            RTSB,
      LLC is a limited liability company, whose members have direct beneficial
      ownership of all of the Units.  Mr. Bachmeier was our interim
      Chief Executive Officer from June 15, 2009 through December 31, 2009 and
      is a principal owner in RTSB, LLC.




The Named
Executive Officers, including our former CEO’s who served the Company during our
fiscal year ended December 31, 2009, and the Governors own the following number
of Class A Membership Units as of March 15, 2010, based on 40,193,973 Membership
Units outstanding, as follows:




Name
      of
              Beneficial
      Owner
            
            Amount
      and Nature of Beneficial Ownership
            
            
            Percent
      ofClassMick
      J. Miller
            
            
            67,500
            (1)
            
            
            *Mark
      E. Klimpel
            
            
            0
            
            
            
            *William
      A. Price
            
            
            400,000
            (2)
            
            
            *Calvin
      Diehl
            
            
            0
            
            
            
            *Tim
      Meuchel
            
            
            1,020,000
            (3)
            
            
            2.54
            %Frank
      Kirschenheiter
            
            
            100,000
            (4)
            
            
            *Ron
      Aberle
            
            
            372,920
            (5)
            
            
            *Mike
      Appert
            
            
            1,095,000
            (6)
            
            
            2.72
            %Jody
      Hoff
            
            
            437,241
            (7)
            
            
            1.09
            %Gerald
      Bachmeier
            
            
            2,619,500
            (8)
            
            
            6.52
            %Sid
      Mauch
            
            
            1,000
            
            
            
            *Officers/Governors
      as a Group (9 persons)
            
            
            6,113,161
            
            
            
            15.21
            %







*
            Designates less than
      one percent ownership.




38




(1)
            Includes
      30,000 Units which Mr. Miller holds beneficially in his IRA
      account.  As mentioned above, Mr. Miller served as the Company’s
      President and Chief Executive Officer until June 15,
  2009.




(2)
            Includes
      300,000 Units which Mr. Price owns jointly with his brother and
      100,000 Units held jointly with his brother and
  mother.




(3)
            Includes
      110,000 Units indirectly held by Mr. Meuchel for the benefit of his son,
      and 200,000 Units owned by Mr. Meuchel’s spouse of which Mr. Meuchel
      disclaims beneficial ownership.




(4)
            Includes
      37,500 Units which are held by Richardton Investments, LLC, of which Mr.
      Kirschenheiter is a partial owner.




(5)
            Includes
      160,000 Units held jointly with Mr. Aberle’s spouse and 12,920 held
      beneficially in Mr. Aberle’s IRA account. Additionally, 200,000 Units
      are held by Aberle Farms of which Mr. Aberle is a partner and of which Mr.
      Aberle disclaims beneficial
ownership.




(6)
            Includes
      375,000 Units which Mr. Appert owns jointly with his spouse and
      100,000 Units held directly by his son of which Mr. Appert disclaims
      beneficial ownership.  Additionally, 160,000 Units are held by
      Appert Acres, Inc., of which Mr. Appert is a partial owner and of
      which Mr. Appert disclaims beneficial ownership and 160,000 Units are
      held by Appert Farms, Inc., of which Mr. Appert is a partial owner
      and of which Mr. Appert disclaims beneficial
    ownership.




(7)
            Includes
      20,000 Units owned jointly with Mr. Hoff’s
      spouse.  Additionally, 417,241 Units are held by Richardton
      Investments, LLC, of which Mr. Hoff is a partial owner and of which
      Mr. Hoff disclaims beneficial
ownership.




(8)
            Includes
      2,619,500 Units owned by RTSB, LLC of which Mr. Bachmeier is a principal
      owner and of which Mr. Bachmeier disclaims beneficial
      ownership.  As mentioned above, Mr. Bachmeier served as the
      Company’s interim Chief Executive Officer from June 15, 2009 through
      December 31, 2009.




EQUITY COMPENSATION PLAN
INFORMATION




With the
departure of Mr. Miller and Mr. Thomas, the Company’s former plant manager, the
Company no longer has any equity compensation plans in place.




ITEM
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND GOVERNOR INDEPENDENCE




TRANSACTIONS WITH RELATED
PERSONS, PROMOTERS AND CERTAIN CONTROL PERSONS




The Board
has adopted a policy requiring all governors, officers and employees, and their
immediate family members to notify the Board about any transaction, of any size,
with the Company.  Some of our governors, officers and employees and
their immediate family members have sold corn to the Company or purchased
distillers grains from the Company.  These purchases and sales were
made on terms available to all parties that do business with the Company, and
were as follows for the last two fiscal years.




Ron
Aberle, a governor, and a company owned in part by Mr. Aberle, sold corn to
the Company in an amount equal to $537,616 and $677,760 during the years ended
December 31, 2009 and 2008, respectively.




Mike
Appert, a governor, and a company owned in part by Mr. Appert, sold corn to
the Company in an amount equal to $2,116,091 and $2,183,781 during the years
ended December 31, 2009 and 2008, respectively.




Tim
Meuchel, a governor, and a company owned in part by Mr. Meuchel, sold corn
and provided trucking services to the Company in an amount equal to $1,690,775
and $4,637,594 during the years ended December 31, 2009 and 2008,
respectively.




William
Price, a governor, and a company owned in part by him, purchased distillers
grains from the Company in an amount equal to $12,386 and $381,693 during the
years ended December 31, 2009 and 2008, respectively.  Another
company owned in part by Mr. Price sold corn to the Company in an amount
equal to $299,760, $0 during the years ended December 31, 2009 and 2008,
respectively.




ITEM
14. PRINCIPAL ACCOUNTING FEES AND SERVICES




Auditors’
Fees





Boulay,
Heutmaker, Zibell & Co., P.L.L.P. billed the Company the following amounts
for services provided during fiscal 2009 and 2008:





2009
            
            
            2008Audit
      Fees
            
            $
            98,879
            
            
            $
            113,737Audit-Related
      Fees
            
            
            957
            
            
            
            21,274Tax
      Fees
            
            
            0
            
            
            
            0All
      Other Fees
            
            
            25,908
            
            
            
            96Total
      Fees
            
            $
            125,774
            
            
            $
            135,107




•
            Audit Fees. This
      category includes the fees and out-of-pocket expenses for professional
      services rendered by the principal accountant for the audit of the
      Company’s annual financial statements and review of financial statements
      included in the Company’s Form 10-Q or services that are normally provided
      by the accountant in connection with statutory and regulatory filings or
      engagements.




39


•
            Audit-Related Fees.
      Audit related fees relate to assurance and related services by the
      principal accountant that are reasonably related to the performance of the
      audit or review of the Company’s financial statements and are not reported
      under the above item.





•
            Tax Fees. This category
      consists of fees for tax compliance, tax advice and tax
      planning.





•
            All Other Fees. This
      category consists of fees for other non-audit
  services.




The Board
of Governors is required to pre-approve all audit and non-audit services
performed by the Company’s independent auditor to assure that the provision of
such services does not impair the auditor’s independence.  The Board
will not authorize the independent auditor to perform any non-audit service
which independent auditors are prohibited from performing under the rules and
regulations of the Securities and Exchange Commission or the Public Company
Accounting Oversight Board. The Board may delegate its pre-approval authority to
one or more of its governors, but not to management. The governor or governors
to whom such authority is delegated shall report any pre-approval decisions to
the Board at its next scheduled meeting.




PART IV




ITEM 15. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES.




The
following exhibits and financial statements are filed as part of, or are
incorporated by reference into, this report:




(1) Financial
Statements




An
index to the financial statements included in this Report appears at page F-1.
The financial statements appear beginning at page F-3 of this Annual
Report.




(2) Financial Statement
Schedules




All
supplemental schedules are omitted as the required information is inapplicable
or the information is presented in the financial statements or related
notes.




(3) Exhibits


3.1
            
            Articles
      of Organization, as filed with the North Dakota Secretary of State on
      July 16, 2003. Filed as Exhibit 3.1 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.3.2
            
            Amended
      and Restated Operating Agreement of Red Trail Energy, LLC. Filed as
      exhibit 3.1 to our Current Report on Form 8-K on August 6, 2008.
      (000-52033) and incorporated by reference herein.4.1
            
            Membership
      Unit Certificate Specimen. Filed as Exhibit 4.1 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.4.2
            
            Member
      Control Agreement of Red Trail Energy, LLC. Filed as Exhibit 4.2 to our
      Annual Report on Form 10-K for the year ended December 31, 2006.
      (000-52033) and incorporated by reference herein.10.1
            
            The
      Burlington Northern and Santa Fe Railway Company Lease of Land for
      Construction/ Rehabilitation of Track made as of May 12, 2003 by and
      between The Burlington Northern and Santa Fe Railway Company and Red Trail
      Energy, LLC. Filed as Exhibit 10.1 to the registrant’s registration
      statement on Form 10-12G (000-52033) and incorporated by reference
      herein.10.2**
            
            Management
      Agreement made and entered into as of December 17, 2003 by and
      between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as
      Exhibit 10.2 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.10.3
            
            Development
      Services Agreement entered into as of December 17, 2003 by and
      between Red Trail Energy, LLC, and Greenway Consulting, LLC. Filed as
      Exhibit 10.3 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.10.4
            
            The
      Burlington Northern and Santa Fe Railway Company Real Estate Purchase and
      Sale Agreement with Red Trail Energy, LLC, dated January 14, 2004.
      Filed as Exhibit 10.4 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.




40




10.5
            
            Warranty
      Deed made as of January 13, 2005 between Victor Tormaschy and Lucille
      Tormaschy, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as
      Grantee. Filed as Exhibit 10.8 to the registrant’s registration
      statement on Form 10-12G (000-52033) and incorporated by reference
      herein.





10.6
            
            Warranty
      Deed made as of July 11, 2005 between Neal C. Messer and Bonnie M.
      Messer, Husband and Wife, as Grantors, and Red Trail Energy, LLC, as
      Grantee. Filed as Exhibit 10.9 to the registrant’s registration
      statement on Form 10-12G (000-52033) and incorporated by reference
      herein.10.7
            
            Agreement
      for Electric Service made the dated August 18, 2005, by and between West
      Plains Electric Cooperative, Inc. and Red Trail Energy, LLC. Filed as
      Exhibit 10.10 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.10.8+
            
            Lump
      Sum Design-Build Agreement between Red Trail Energy, LLC, and Fagen, Inc.
      dated August 29, 2005. Filed as Exhibit 10.12 to the
      registrant’s registration statement on Form 10-12G/A-3 (000-52033)
      and incorporated by reference herein.10.9
            
            Construction
      Loan Agreement dated as of the December 16, 2005 by and between Red Trail
      Energy, LLC, and First National Bank of Omaha. Filed as Exhibit 10.14
      to the registrant’s registration statement on Form 10-12G (000-52033)
      and incorporated by reference herein.10.10
            
            Construction
      Note for $55,211,740.00 dated December 16, 2005, between Red Trail
      Energy, LLC, as Borrower, and First National Bank of Omaha, as Bank. Filed
      as Exhibit 10.15 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.10.11
            
            International
      Swap Dealers Association, Inc. Master Agreement dated as of
      December 16, 2005, signed by First National Bank of Omaha and Red
      Trial Energy, LLC. Filed as Exhibit 10.18 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.10.12
            
            Security
      Agreement and Deposit Account Control Agreement made December 16,
      2005, by and among First National Bank of Omaha, Red Trail Energy, LLC,
      and Bank of North Dakota. Filed as Exhibit 10.19 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.10.13
            
            Security
      Agreement given as of December 16, 2005, by Red Trail Energy, LLC, to
      First National Bank of Omaha. Filed as Exhibit 10.20 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.10.14
            
            Control
      Agreement Regarding Security Interest in Investment Property, made as of
      December 16, 2005, by and between First National Bank of Omaha, Red
      Trail Energy, LLC, and First National Capital Markets, Inc. Filed as
      Exhibit 10.21 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.10.15
            
            Loan
      Agreement between Greenway Consulting, LLC, and Red Trail Energy, LLC,
      dated February 26, 2006. Filed as Exhibit 10.22 to the
      registrant’s registration statement on Form 10-12G (000-52033) and
      incorporated by reference herein.10.16
            
            Promissory
      Note for $1,525,000.00, dated February 28, 2006, given by Red Trail
      Energy, LLC, to Greenway Consulting, LLC. Filed as Exhibit 10.23 to
      the registrant’s registration statement on Form 10-12G (000-52033) and
      incorporated by reference herein.10.17
            
            Loan
      Agreement between ICM Inc. and Red Trail Energy, LLC, dated
      February 28, 2006. Filed as Exhibit 10.24 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.10.18
            
            Promissory
      Note for $3,000,000.00, dated February 28, 2006, given by Red Trail
      Energy, LLC, to ICM Inc. Filed as Exhibit 10.25 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.10.19
            
            Loan
      Agreement between Fagen, Inc. and Red Trail Energy, LLC, dated
      February 28, 2006. Filed as Exhibit 10.26 to the registrant’s
      registration statement on Form 10-12G (000-52033) and incorporated by
      reference herein.




41




10.20
            
            Promissory
      Note for $1,000,000.00, dated February 28, 2006, given by Red Trail
      Energy, LLC, to Fagen, Inc. Filed as Exhibit 10.27 to the
      registrant’s registration statement on Form 10-12G (000-52033) and
      incorporated by reference herein.10.21
            
            Southwest
      Pipeline Project Raw Water Service Contract, executed by Red Trail Energy,
      LLC, on March 8, 2006, by the Secretary of the North Dakota State
      Water Commission on March 31, 2006, and by the Chairman of the
      Southwest Water Authority on April 2, 2006. Filed as
      Exhibit 10.28 to the registrant’s registration statement on
      Form 10-12G (000-52033) and incorporated by reference
      herein.10.22
            
            Contract
      dated April 26, 2006, by and between the North Dakota Industrial
      Commission and Red Trail Energy, LLC. Filed as Exhibit 10.29 to the
      registrant’s second amended registration statement on Form 10-12G/A
      (000-52033) and incorporated by reference herein.10.23
            
            Subordination
      Agreement, dated May 16, 2006, among the State of North Dakota, by
      and through its Industrial Commission, First National Bank and Red Trail
      Energy, LLC. Filed as Exhibit 10.30 to the registrant’s second
      amended registration statement on Form 10-12G/A (000-52033) and
      incorporated by reference herein.10.24
            
            Firm
      Gas Service Extension Agreement, dated June 7, 2006, by and between
      Montana-Dakota Utilities Co. and Red Trail Energy, LLC. Filed as
      Exhibit 10.31 to the registrant’s second amended registration
      statement on Form 10-12G/A (000-52033) and incorporated by reference
      herein.10.25
            
            First
      Amendment to Construction Loan Agreement dated August 16, 2006 by and
      between Red Trail Energy, LLC and First National Bank of
      Omaha.  Filed as Exhibit 10.32 to the registrant’s Annual Report
      on Form 10-K for the year ended December 31, 2006. (000-52033) and
      incorporated by reference herein.10.26
            
            Security
      Agreement and Deposit Account Control Agreement effective August 16,
      2006 by and among First National Bank of Omaha and Red Trail Energy, LLC.
      Filed as Exhibit 10.34 to our Annual Report on Form 10-K for the year
      ended December 31, 2006. (000-52033) and incorporated by reference
      herein.10.27**
            
            Equity
      Grant Agreement dated September 8, 2006 by and between Red Trail
      Energy, LLC and Mickey Miller. Filed as Exhibit 10.35 to our Annual Report
      on Form 10-K for the year ended December 31, 2006. (000-52033) and
      incorporated by reference herein.10.28
            
            Option
      to Purchase 200,000 Class A Membership Units of Red Trail Energy, LLC
      by Red Trail Energy, LLC from North Dakota Development Fund and Stark
      County dated December 11, 2006. Filed as Exhibit 10.36 to our Annual
      Report on Form 10-K for the year ended December 31, 2006. (000-52033) and
      incorporated by reference herein.10.29
            
            Audit
      Committee Charter adopted April 9, 2007. Filed as Exhibit 10.37 to
      our Annual Report on Form 10-K for the year ended December 31, 2006.
      (000-52033) and incorporated by reference herein.10.30
            
            Senior
      Financial Officer Code of Conduct adopted March 28, 2007. Filed as
      Exhibit 10.38 to our Annual Report on Form 10-K for the year ended
      December 31, 2006. (000-52033) and incorporated by reference
      herein.10.31
            
            Long
      Term Revolving Note for $10,000,000, dated April 16, 2007 between Red
      Trail Energy, LLC, as Borrower, and First National Bank of Omaha, as
      Bank.  Filed as Exhibit 10.1 to our Quarterly Report on Form
      10-Q for the quarter ended March 31, 2007 (000-52033) and incorporated by
      reference herein.10.32
            
            Variable
      Rate Note for $17,065,870, dated April 16, 2007 between Red Trail Energy,
      LLC, as Borrower, and First National Bank of Omaha, as
      Bank.  Filed as Exhibit 10.2 to our Quarterly Report on Form
      10-Q for the quarter ended March 31, 2007 (000-52033).10.33
            
            Fixed
      Rate Note for $27,605,870, dated April 16, 2007 between Red Trail Energy,
      LLC, as Borrower, and First National Bank of Omaha, as
      Bank.  Filed as Exhibit 10.3 to our Quarterly Report on Form
      10-Q for the quarter ended March 31, 2007 (000-52033) and incorporated by
      reference herein.10.34
            
            $3,500,000
      Revolving Promissory Note given by the Company to First National Bank of
      Omaha dated July 18, 2007.  Filed as Exhibit 10.1 to our
      Quarterly Report on Form 10-Q for the quarter ended September 30, 2007
      (000-52033) and incorporated by reference herein.10.35
            
            Second
      Amendment to Construction Loan Agreement by and between the Company and
      First National Bank of Omaha dated July 18, 2007.  Filed as
      Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended
      September 30, 2007 (000-52033) and incorporated by reference
      herein.




42




10.36
            
            Third
      Amendment to Construction Loan Agreement by and between the Company and
      First National Bank of Omaha dated November 15, 2007.  Filed as
      Exhibit 10.38 to our Annual Report on Form 10-K for the year ended
      December 31, 2007 (000-52033) and incorporated by reference
      herein.10.37
            
            Fourth
      Amendment to Construction Loan Agreement by and between the Company and
      First National Bank of Omaha dated December 11, 2007.  Filed as
      Exhibit 10.39 to our Annual Report on Form 10-K for the year ended
      December 31, 2007 (000-52033) and incorporated by reference
      herein.10.38
            
            Interest
      Rate Swap Agreement by and between the Company and First National Bank of
      Omaha dated December 11, 2007.  Filed as Exhibit 10.40 to our
      Annual Report on Form 10-K for the year ended December 31, 2007
      (000-52033) and incorporated by reference herein.10.39
            
            Member
      Ethanol Fuel Marketing agreement by and between Red Trail Energy, LLC and
      RPMG, Inc dated January 1, 2008.  Filed as Exhibit 10.41 to our
      Annual Report on Form 10-K for the year ended December 31, 2007
      (000-52033) and incorporated by reference herein.10.40
            
            Contribution
      Agreement by and between Red Trail Energy, LLC and Renewable Products
      Marketing Group, LLC dated January 1, 2008.  Filed as Exhibit
      10.42 to our Annual Report on Form 10-K for the year ended December 31,
      2007 (000-52033) and incorporated by reference herein.10.41
            
            Coal
      Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal
      Sales Company dated December 5, 2007.  Filed as Exhibit 10.43 to
      our Annual Report on Form 10-K for the year ended December 31, 2007
      (000-52033) and incorporated by reference herein.10.42
            
            Distillers
      Grain Marketing Agreement by and between Red Trail Energy, LLC and CHS,
      Inc dated March 10, 2008.  Filed as Exhibit 10.44 to our Annual
      Report on Form 10-K for the year ended December 31, 2007 (000-52033) and
      incorporated by reference herein.10.43
            
            Assignment
      and Assumption Agreement dated April 1, 2008, by and between Commodity
      Specialist Company and Red Trail Energy, LLC.  Filed as Exhibit
      10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31,
      2008 (000-52033) and incorporated by reference herein.10.44
            
            $3,500,000
      Revolving Promissory Note given by the Company to First National Bank of
      Omaha dated July 19, 2008.  Filed as Exhibit 10.1 to our
      Quarterly Report on Form 10-Q for the quarter ended September 30, 2008
      (000-52033) and incorporated by reference herein.10.45
            
            Fifth
      Amendment to Construction Loan Agreement by and between the Company and
      First National Bank of Omaha dated July 19, 2008.  Filed as
      Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended
      September 30, 2008 (000-52033) and incorporated by reference
      herein.10.46**
            
            Employment
      Agreement dated August 8, 2008 by and between Red Trail Energy, LLC and
      Mark Klimpel.  Filed as exhibit 99.1 to our Current Report on
      Form 8-K filed with the SEC on August 13, 2008 (000-52033) and
      incorporated by reference herein.10.47
            
            Amended
      and Restated Member Control Agreement of Red Trail Energy,
      LLC.  Filed as exhibit 4.2 to our Current Report on Form 8-K
      filed with the SEC on June 1, 2009 (000-52033) and incorporated by
      reference herein.10.48
            
            Sixth
      Amendment to Construction Loan Agreement by and between the Company and
      First National Bank of Omaha effective date April 16,
      2009.  Filed as Exhibit 10.1 to our Current Report on Form 8-K
      filed with the SEC on June 2, 2009 (000-52033) and incorporated by
      reference herein.10.49+
            
            Coal
      Sales Order by and between Red Trail Energy, LLC and Westmoreland Coal
      Sales Company dated November 5, 2009.  Filed as Exhibit 10.1 to
      our Quarterly Report on Form 10-Q for the quarter ended September 30, 2009
      (000-52033) and incorporated by reference herein.10.50**
            
            Amended
      and Restated Management Agreement made and entered into as of September
      10, 2009 by and between Red Trail Energy, LLC, and Greenway Consulting,
      LLC. Filed as Exhibit 10.2 to our Quarterly Report on Form 10-Q for
      the quarter ended September 30, 2009 (000-52033) and incorporated by
      reference herein.




43




10.51*
            
            Seventh
      Amendment to Construction Loan Agreement by and between the Company and
      First National Bank of Omaha dated March 1, 2010.31.1*
            
            Certification
      by Chief Executive Officer pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities
      Exchange Act of 1934).31.2*
            
            Certification
      by Chief Financial Officer pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002 (Rules 13a-14 and 15d-14 of the Securities
      Exchange Act of 1934).32.1*
            
            Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
      Section 906 of the Sarbanes-Oxley Act of 2002.32.2*
            
            Certification
      pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
      Section 906 of the Sarbanes-Oxley Act of
  2002.





+
            Confidential
      treatment has been requested and obtained with respect to certain portions
      of this exhibit. Omitted portions have been
      filed    separately with the Securities and Exchange
      Commission.




*
            Filed
      herewith.




**
            Management
      contract or compensatory plan or
arrangement.




44




SIGNATURES




Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.


/s/
      Calvin DiehlDate:
      March 31, 2010
            
            Calvin
      DiehlChief
      Executive Officer(Principal
      Executive Officer)





Pursuant
to the requirements of the Securities Exchange Act of 1934, the report has been
signed below by the following persons on behalf of the registrant and in the
capacities and dates indicated.




/s/
      Calvin DiehlDate:
      March 31, 2010
            
            Calvin
      DiehlPresident
      and Chief Executive Officer(Principal
      Executive Officer)/s/
      Mark E. KlimpelDate:
      March 31, 2010
            
            Mark
      E. KlimpelChief
      Financial Officer(Principal
      Financial and Accounting Officer)Date:
      March 31, 2010
            
            /s/
      Mike AppertMike
      Appert, Chairman of the BoardDate:
      March 31, 2010
            
            /s/
      William A. PriceWilliam
      A. Price, Secretary and Governor/s/
      Ron AberleDate:
      March 31, 2010
            
            Ron
      Aberle, Governor/s/
      Jody HoffDate:
      March 31, 2010
            
            Jody
      Hoff, Vice Chairman and Governor/s/
      Frank KirschenheiterDate:
      March 31, 2010
            
            Frank
      Kirschenheiter, Treasurer and Governor/s/
      Sid MauchDate:
      March 31, 2010
            
            Sid
      Mauch, Governor




45





Red
Trail Energy, LLC




Financial
Statements




December 31,
2009, 2008 and 2007




C O N T E
N T S


PageReport of Independent Registered
      Public Accounting Firm
              
              
              F-2Financial
      StatementsBalance
      Sheet
              
              
              F-3Statement of
      Operations
              
              
              F-4Statement of Changes in Members’
      Equity
              
              
              F-5Statement of Cash
      Flows
              
              
              F-6Notes to Financial
      Statements
              
              
              F-7
      -20




F-1










REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





Board of
Governors


Red Trail
Energy, LLC


Richardton,
North Dakota





We have
audited the accompanying balance sheets of Red Trail Energy, LLC as of December
31, 2009 and 2008, and the related statements of operations, changes in members’
equity, and cash flows for each of the years in a three-year period ended
December 31, 2009.  These financial statements are the responsibility
of the Company’s management.  Our responsibility is to express an
opinion on these financial statements based on our audits.





We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States).  Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  The Company is not
required to have, nor were we engaged to perform, an audit of its internal
control over financial reporting.  Our audits included consideration
of internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purposes
of expressing an opinion on the effectiveness of the Company’s internal control
over financial reporting.  Accordingly, we express no such
opinion.  An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that
our audits provide a reasonable basis for our opinion.





In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of Red Trail Energy, LLC as of
December 31, 2009 and 2008, and the results of their operations and their cash
flows for each of the years in a three-year period ended December 31, 2009 in
conformity with U.S. generally accepted accounting principles.








/s/
Boulay, Heutmaker, Zibell & Co. PLLP


Certified
Public Accountants





Minneapolis,
Minnesota


March 31,
2010




F-2




Red
Trail Energy, LLC




Balance
Sheet




December
      31,
              
              2009
              
              
              2008ASSETSCurrent
      AssetsCash
      and equivalents
              
              $
              13,214,091
              
              
              $
              4,433,839Restricted
      cash - collateral
              
              
              750,000
              
              
              ―Restricted
      cash - margin account
              
              
              1,467,013
              
              
              
              1,498,791Accounts
      receivable
              
              
              2,635,775
              
              
              
              2,697,695Derivative
      instruments, at fair value
              
              
              129,063
              
              
              ―Inventory
              
              
              6,993,031
              
              
              
              3,353,592Prepayments
      of corn purchases
              
              ―
              
              
              
              4,398,046Prepaid
      expenses
              
              
              195,639
              
              
              
              41,767Total
      current assets
              
              
              25,384,612
              
              
              
              16,423,730Property,
      Plant and EquipmentLand
              
              
              351,280
              
              
              
              351,280Plant
      and equipment
              
              
              79,199,850
              
              
              
              79,898,657Land
      improvements
              
              
              3,970,500
              
              
              
              3,939,294Buildings
              
              
              5,312,995
              
              
              
              5,312,995Construction
      in progress
              
              ―
              
              
              
              33,67988,834,625
              
              
              
              89,535,905Less
      accumulated depreciation
              
              
              17,419,043
              
              
              
              11,525,863Net
      property, plant and equipment
              
              
              71,415,582
              
              
              
              78,010,042Other
      AssetsDebt
      issuance costs, net of amortization
              
              ―
              
              
              
              567,385Investment
      in RPMG
              
              
              605,000
              
              
              
              605,000Patronage
      equity
              
              
              192,207
              
              
              
              116,296Deposits
              
              
              80,000
              
              
              
              80,000Total
      other assets
              
              
              877,207
              
              
              
              1,368,681Total
      Assets
              
              $
              97,677,401
              
              
              $
              95,802,453LIABILITIES
      AND MEMBERS' EQUITYCurrent
      LiabilitiesCurrent
      maturities of long-term debt
              
              $
              6,500,000
              
              
              $
              49,063,201Accounts
      payable
              
              
              7,605,302
              
              
              
              5,720,764Accrued
      expenses
              
              
              2,634,534
              
              
              
              1,845,101Derivative
      instruments, at fair value
              
              
              806,490
              
              
              
              1,051,052Accrued
      loss on firm purchase commitments
              
              
              ―
              
              
              
              1,426,800Interest
      rate swaps, at fair value
              
              
              2,360,686
              
              
              
              2,861,530Total
      current liabilities
              
              
              19,907,012
              
              
              
              61,968,448Other
      LiabilitiesContracts
      payable
              
              
              275,000
              
              
              
              275,000Long-Term
      Debt
              
              
              43,620,025
              
              
              ―Commitments
      and ContingenciesMembers'
      Equity
              
              
              33,875,364
              
              
              
              33,559,005Total
      Liabilities and Members' Equity
              
              $
              97,677,401
              
              
              $
              95,802,453




Notes to
Financial Statements are an integral part of this Statement.




F-3





Red
Trail Energy, LLC


Statement of Operations




Years
      ended December 31,
              
              2009
              
              
              2008
              
              
              2007RevenuesEthanol,
      net of derivative activity
              
              $
              77,700,414
              
              
              $
              111,086,858
              
              
              $
              90,100,581Distillers
      grains
              
              
              16,136,247
              
              
              
              20,816,656
              
              
              
              11,785,388Total
      Revenues
              
              
              93,836,661
              
              
              
              131,903,514
              
              
              
              101,885,969Cost
      of Goods SoldCost
      of goods sold
              
              
              80,376,609
              
              
              
              121,042,965
              
              
              
              81,358,010Loss
      on firm purchase commitments
              
              
              169,000
              
              
              
              3,470,110
              
              
              
              ―Lower
      of cost or market adjusment for inventory on hand
              
              
              1,464,500
              
              
              
              771,200
              
              
              
              ―Depreciation
              
              
              5,840,760
              
              
              
              5,740,963
              
              
              
              5,655,198Total
      Cost of Goods Sold
              
              
              87,850,869
              
              
              
              131,025,238
              
              
              
              87,013,208Gross
      Margin
              
              
              5,985,792
              
              
              
              878,276
              
              
              
              14,872,761General
      and Administrative
              
              
              2,812,891
              
              
              
              2,857,091
              
              
              
              3,214,002Operating
      Income (Loss)
              
              
              3,172,901
              
              
              
              (1,978,815
              )
              
              
              11,658,759Interest
      Expense
              
              
              3,988,916
              
              
              
              6,013,299
              
              
              
              6,268,707Other
      Income, net
              
              
              1,176,675
              
              
              
              2,625,542
              
              
              
              767,276Net
      Income (Loss)
              
              $
              360,660
              
              
              $
              (5,366,572
              )
              
              $
              6,157,328Weighted
      Average Units Outstanding - basic
              
              
              40,191,494
              
              
              
              40,176,974
              
              
              
              40,371,238Weighted
      Average Units Outstanding - diluted
              
              
              40,191,494
              
              
              
              40,176,974
              
              
              
              40,416,238Net
      Income (Loss) Per Unit - basic
              
              $
              0.01
              
              
              $
              (0.13
              )
              
              $
              0.15Net
      Income (Loss) Per Unit - diluted
              
              $
              0.01
              
              
              $
              (0.13
              )
              
              $
              0.15




Notes to
Financial Statements are an integral part of this Statement.




F-4





Red Trail Energy, LLC


Statement of Changes in Members’
Equity






Years
Ended December 31, 2009, 2008 and 2007


Class
      A Member Units
                
                
                Additional
      Paid
                
                
                Accumulated
                
                
                Treasury
      Units
                
                
                Total
      Members'Units
      (a)
                
                
                Amount
                
                
                in
      Capital
                
                
                Deficit
                
                
                Units
                
                
                Amount
                
                
                EquityBalance
      - January 1, 2007
                
                
                40,373,973
                
                
                $
                37,810,408
                
                
                $
                56,825
                
                
                $
                (4,938,145
                )
                
                
                ―
                
                
                $
                ―
                
                
                $
                32,929,088Unit-based
      compensation
                
                
                ―
                
                
                
                ―
                
                
                
                45,000
                
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                45,000Treasury
      units repurchased$1.13
      per unit, December 2007
                
                
                (200,000
                )
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                200,000
                
                
                
                (227,933
                )
                
                
                (227,933
                )Net
      Income
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                6,157,328
                
                
                
                ―
                
                
                
                ―
                
                
                
                6,157,328Balance
      - December 31, 2007
                
                
                40,173,973
                
                
                
                37,810,408
                
                
                
                101,825
                
                
                
                1,219,183
                
                
                
                200,000
                
                
                
                (227,933
                )
                
                
                38,903,483Unit-based
      compensation
                
                
                ―
                
                
                
                ―
                
                
                
                20,000
                
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                20,000Units
      issued under compensationagreement
                
                
                15,000
                
                
                
                ―
                
                
                
                (15,000
                )
                
                
                
                
                
                
                (15,000
                )
                
                
                17,094
                
                
                
                2,094Net
      Loss
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                (5,366,572
                )
                
                
                ―
                
                
                
                ―
                
                
                
                (5,366,572
                )Balance
      - December 31, 2008
                
                
                40,188,973
                
                
                
                37,810,408
                
                
                
                106,825
                
                
                
                (4,147,389
                )
                
                
                185,000
                
                
                
                (210,839
                )
                
                
                33,559,005Unit-based
      compensation
                
                
                ―
                
                
                
                ―
                
                
                
                (55,000
                )
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                (55,000
                )Units
      issued under compensationagreement
                
                
                5,000
                
                
                
                ―
                
                
                
                5,000
                
                
                
                
                
                
                
                (5,000
                )
                
                
                5,699
                
                
                
                10,699Net
      Income
                
                
                ―
                
                
                
                ―
                
                
                
                ―
                
                
                
                360,660
                
                
                
                ―
                
                
                
                ―
                
                
                
                360,660Balance
      - December 31, 2009
                
                
                40,193,973
                
                
                $
                37,810,408
                
                
                $
                56,825
                
                
                $
                (3,786,729
                )
                
                
                180,000
                
                
                $
                (205,140
                )
                
                $
                33,875,364(a) - Amounts
      shown represent member units outstanding. Authorized and issued units
      were 40,373,973 as of the end of each period
  presented




Notes to
Financial Statements are an integral part of this Statement.




F-5





RED
TRAIL ENERGY, LLC


Statements
of Cash Flows




Years
      ended December 31,
                
                2009
                
                
                2008
                
                
                2007Cash
      Flows from Operating ActivitiesNet
      income (loss)
                
                $
                360,660
                
                
                $
                (5,366,572
                )
                
                $
                6,157,328Adjustment
      to reconcile net income (loss) to net cash provided by(used
      in) operating activities:Depreciation
                
                
                5,893,180
                
                
                
                5,796,805
                
                
                
                5,713,042Amortization
      and write-off of debt issuance costs
                
                
                567,385
                
                
                
                201,020
                
                
                
                214,169Change
      in fair value of derivative instruments
                
                
                (373,625
                )
                
                
                1,238,979
                
                
                
                (2,870,449
                )Change
      in fair value of interest rate swap
                
                
                490,619
                
                
                
                2,266,371
                
                
                
                894,256Equity-based
      compensation
                
                
                3,334
                
                
                
                22,094
                
                
                
                20,000Equity-based
      compensation non-cash write-off
                
                
                (52,635
                )
                
                
                ―
                
                
                
                ―Non-cash
      patronage equity
                
                
                (75,911
                )
                
                
                (116,296
                )
                
                
                ―Grant
      income applied to long-term debt
                
                
                ―
                
                
                
                (59,874
                )
                
                
                ―Changes
      in assets and liabilitiesRestricted
      cash - margin account
                
                
                31,778
                
                
                
                1,504,072
                
                
                
                ―Accounts
      receivable
                
                
                61,920
                
                
                
                3,262,346
                
                
                
                (5,960,041
                )Inventory
                
                
                (3,639,439
                )
                
                
                4,943,764
                
                
                
                (4,341,227
                )Prepaid
      expenses
                
                
                4,244,174
                
                
                
                (4,386,402
                )
                
                
                10,371Accounts
      payable
                
                
                2,053,648
                
                
                
                (1,130,676
                )
                
                
                2,603,723Accrued
      expenses
                
                
                789,433
                
                
                
                (657,835
                )
                
                
                204,461Accrued
      loss on firm purchase commitments
                
                
                (1,426,800
                )
                
                
                1,426,800
                
                
                
                ―Net
      settlements on derivative instruments
                
                
                (991,463
                )
                
                
                (449,032
                )
                
                
                39,000Net
      cash provided by operating activities
                
                
                7,936,258
                
                
                
                8,495,564
                
                
                
                2,684,633Cash
      Flows from Investing ActivitiesInvestment
      in RPMG
                
                
                (169,110
                )
                
                
                (435,890
                )
                
                
                ―Refund
      of sales tax on property, plant and equipment
                
                
                763,630
                
                
                
                ―
                
                
                
                ―Capital
      expenditures
                
                
                (62,350
                )
                
                
                (1,864,305
                )
                
                
                (3,974,839
                )Net
      cash provided by (used in) investing activities
                
                
                532,170
                
                
                
                (2,300,195
                )
                
                
                (3,974,839
                )Cash
      Flows from Financing ActivitiesDebt
      repayments
                
                
                (2,516,684
                )
                
                
                (10,153,739
                )
                
                
                (1,813,376
                )Proceeds
      from long-term debt
                
                
                3,573,508
                
                
                
                160,500
                
                
                
                11,141,502Restricted
      cash - collateral
                
                
                (750,000
                )
                
                
                ―
                
                
                
                ―Treasury
      units issued
                
                
                5,000
                
                
                
                ―
                
                
                
                (227,933
                )Net
      cash provided by (used in) financing activities
                
                
                311,824
                
                
                
                (9,993,239
                )
                
                
                9,100,193Net
      Increase (Decrease) in Cash and Equivalents
                
                
                8,780,252
                
                
                
                (3,797,870
                )
                
                
                7,809,987Cash
      and Equivalents - Beginning of Period
                
                
                4,433,839
                
                
                
                8,231,709
                
                
                
                421,722Cash
      and Eqivalents - End of Period
                
                $
                13,214,091
                
                
                $
                4,433,839
                
                
                $
                8,231,709Supplemental
      Disclosure of Cash Flow InformationInterest
      paid net of swap settlements
                
                $
                3,026,980
                
                
                $
                4,404,790
                
                
                $
                4,119,744SUPPLEMENT
      DISCLOSURE OF NON-CASHINVESTING
      AND FINANCING ACTIVITIESInvestments
      included in accounts payable
                
                $
                ―
                
                
                $
                169,110
                
                
                $
                ―




Notes to
Financial Statements are an integral part of this Statement.




F-6




Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007




1. SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES




Nature of
Business




Red Trail
Energy, LLC, a North Dakota limited liability company (the “Company”), owns and
operates a 50 million gallon annual production ethanol plant near Richardton,
North Dakota.  The Plant commenced production on January 1,
2007.  Fuel grade ethanol and distillers grains are the Company’s
primary products.  Both products are marketed and sold primarily
within the continental United States.




Fiscal Reporting
Period




The
Company adopted a fiscal year ending December 31 for reporting financial
operations.




Use of
Estimates




The
preparation of the financial statements, in accordance with generally accepted
principles in the United States of America, requires management to make
estimates and assumptions that affect the amounts reported in the financial
statements and accompanying notes. Significant items subject to such estimates
and assumptions include the useful lives of property, plant and equipment;
valuation of derivatives, inventory, patronage equity and purchase commitments;
analysis of intangibles impairment, the analysis of long-lived assets impairment
and other contingencies. Actual results could differ from those
estimates.




Reclassifications




The
presentation of certain items in the financial statements for the years ended
December 31, 2008 and 2007 have been changed to conform to the classifications
used in 2009.  The reclassifications had no effect on members’ equity,
net income (loss) or operating cash flows as previously reported.




Restricted
Cash




During
June 2009, the Company was required to restrict cash for use as collateral on
two letters of credit issued in relation to its distilled spirits and grain
warehouse bonds.  As of December 31, 2009 and 2008, the total amount
of restricted cash related to these bonds was $750,000 and $0,
respectively.  The Company also had restricted cash to meet its
derivative hedge account requirements.  The total amount of cash
restricted in its hedge account at December 31, 2009 and 2008 was approximately
$1.5 million.




Cash and
Equivalents




The
Company considers all highly liquid debt instruments purchased with a maturity
of three months or less to be cash equivalents. The carrying value of cash and
equivalents approximates the fair value.  The Company has money market
funds in cash equivalents at December 31, 2009 and 2008.




The
Company maintains its accounts at various financial institutions. At times
throughout the year, the Company’s cash and equivalents balances may exceed
amounts insured by the Federal Deposit Insurance Corporation.




Accounts Receivable and
Concentration of Credit Risk




The
Company generates accounts receivable from sales of ethanol and distillers
grains.  The Company has entered into agreements with RPMG, Inc.
(“RPMG”) and CHS, Inc. (“CHS”) for the marketing and distribution of the
Company’s ethanol and dried distillers grains, respectively.  Under
the terms of the marketing agreements, both RPMG and CHS bear the risk of loss
of nonpayment by their customers.  The Company markets its wet
distillers grains internally.




The
Company is substantially dependent upon RPMG for the purchase, marketing and
distribution of the Company’s ethanol. RPMG purchases 100% of the ethanol
produced at the Plant, all of which is marketed and distributed to its
customers. Therefore, the Company is highly dependent on RPMG for the successful
marketing of the Company’s ethanol. In the event that the Company’s relationship
with RPMG is interrupted or terminated for any reason, the Company believes that
another entity to market the ethanol could be located. However, any interruption
or termination of this relationship could temporarily disrupt the sale and
production of ethanol and adversely affect the Company’s business and
operations.  Amounts due from RPMG represent approximately 77% and 61%
of the Company’s outstanding receivable balance as of December 31, 2009 and
2008, respectively.




The
Company is substantially dependent on CHS for the purchase, marketing and
distribution of the Company’s dried distillers grains. CHS purchases 100% of the
dried distillers grains produced at the Plant, all of which are marketed and
distributed to its customers. Therefore, the Company is highly dependent on CHS
for the successful marketing of the Company’s dried distillers grains. In the
event that the Company’s relationship with CHS is interrupted or terminated for
any reason, the Company believes that another entity to market the dried
distillers grains could be located. However, any interruption or termination of
this relationship could temporarily disrupt the sale of dried distillers grains
and adversely affect the Company’s business and operations.




F-7


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


For sales
of wet distillers grains, credit is extended based on evaluation of a customer’s
financial condition and collateral is not required. Accounts receivable are due
30 days from the invoice date.  Accounts outstanding longer than the
contractual payment terms are considered past due.  Internal follow up
procedures are followed accordingly.  Interest is charged on past due
accounts.




All
receivables are stated at amounts due from customers net of any allowance for
doubtful accounts.  The Company determines its allowance by
considering a number of factors, including the length of time trade accounts
receivable are past due, the Company’s previous loss history, the customer’s
perceived current ability to pay its obligation to the Company, and the
condition of the general economy and the industry as a whole. The Company writes
off accounts receivable when they become uncollectible, and payments
subsequently received on such receivables are credited to the allowance for
doubtful accounts. There was no allowance for doubtful accounts at December 31,
2009 or December 31, 2008.




Patronage
Equity




The
Company receives, from certain vendors organized as cooperatives, patronage
dividends, which are based on several criteria, including the vendor’s overall
profitability and the Company’s purchases from the vendor.  Patronage
equity typically represents the Company’s share of the vendor’s undistributed
current earnings which will be paid to the Company at a future
date.  Because these patronage dividends are in return for the
Company’s current purchases, the Company records the value of these future
payments using a discounting approach that incorporates interest and collection
risk factors.




Derivative
Instruments




The
Company enters into derivative transactions to hedge its exposure to commodity
price fluctuations.  The Company is required to record these
derivatives in the balance sheet at fair value.




In order
for a derivative to qualify as a hedge, specific criteria must be met and
appropriate documentation maintained. Gains and losses from derivatives that do
not qualify as hedges, or are undesignated, must be recognized immediately in
earnings. If the derivative does qualify as a hedge, depending on the nature of
the hedge, changes in the fair value of the derivative will be either offset
against the change in fair value of the hedged assets, liabilities, or firm
commitments through earnings or recognized in other comprehensive income until
the hedged item is recognized in earnings. Changes in the fair value of
undesignated derivatives related to corn are recorded in costs of goods
sold.  Changes in the fair value of undesignated derivatives related
to ethanol are recorded in revenue.




Additionally
the Company is required to evaluate its contracts to determine whether the
contracts are derivatives. Certain contracts that literally meet the definition
of a derivative may be exempted as “normal purchases or normal sales.” Normal
purchases and normal sales are contracts that provide for the purchase or sale
of something other than a financial instrument or derivative instrument that
will be delivered in quantities expected to be used or sold over a reasonable
period in the normal course of business. As of December 31, 2009 and 2008
the Company has no derivatives instruments that meet this
criterion.




Firm Purchase
Commitments




The
Company typically enters into fixed price contracts to purchase corn to ensure
an adequate supply of corn to operate its plant.  The Company will
generally seek to use exchange traded futures, options or swaps as an offsetting
position.  The Company closely monitors the number of bushels hedged
using this strategy to avoid an unacceptable level of margin
exposure.




Revenue
Recognition




The
Company generally sells ethanol and related products pursuant to marketing
agreements. Revenues are recognized when the customer has taken title, which
occurs when the product is shipped, has assumed the risks and rewards of
ownership, prices are fixed or determinable and collectability is reasonably
assured.




Revenues
are shown net of any fees incurred under the terms of the Company’s agreements
for the marketing and sale of ethanol and related products.





Long-lived
Assets




Property,
plant, and equipment are stated at cost. Depreciation is provided over estimated
useful lives by use of the straight line method. Maintenance and repairs are
expensed as incurred. Major improvements and betterments are
capitalized.  The present values of capital lease obligations are
classified as long-term debt and the related assets are included in plant and
equipment.  Amortization of equipment under capital leases is included
in depreciation expense.





Long-lived
assets, such as property, plant, and equipment, and purchased intangible assets
subject to amortization, are reviewed for impairment whenever events or changes
in circumstances indicate that the carrying amount of an asset may not be
recoverable. If circumstances require a long-lived asset be tested for possible
impairment, the Company first compares undiscounted cash flows expected to be
generated by an asset to the carrying value of the asset. If the carrying value
of the long-lived asset is not recoverable on an undiscounted cash flow basis,
impairment is recognized to the extent that the carrying value exceeds its fair
value. Fair value is determined through various valuation techniques including,
but not limited to, discounted cash flow models, quoted market values and
third-party independent appraisals.




F-8


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


Indefinite
lived intangible assets are reviewed for impairment at least annually and if
events or changes in circumstances indicate that the carrying amount of the
indefinite lived intangible may not be recoverable.




Debt Issuance
Costs




Debt
issuance costs were amortized over the term of the related debt by use of the
effective interest method. Amortization commenced June 2006 when the
Company began drawing on the related bank loan.  Due to uncertainties
with our loan agreements, the Company wrote off the remaining balance
(approximately $517,000) of its debt issuance costs during the first quarter of
2009.  Amortization and impairment expense totaled $567,000 and
$201,000 for the years ended December 31, 2009 and 2008,
respectively.  These amounts are included in interest
expense.




Fair Value of Financial
Instruments




The fair
value of the Company’s cash and equivalents, accounts receivable, accounts
payable, and derivative instruments approximate their carrying
value.   The Company evaluated the fair value of its long-term
debt at December 31, 2009 and 2008 and the fair value approximated the carrying
value (see Note 6 for additional information).




Grants




The
Company recognizes grant proceeds as other income for reimbursement of expenses
incurred upon complying with the conditions of the grant. For reimbursements of
capital expenditures, the grants are recognized as a reduction of the basis of
the asset upon complying with the conditions of the grant.  In
addition, the Company considers production incentive payments received to be
economic grants and includes such amounts in other income when received, as this
represents the point at which they are fixed and determinable.




Grant
income received for incremental expenses that otherwise would not have been
incurred is netted against the related expenses.




Shipping and
Handling




The cost
of shipping products to customers is included in cost of goods sold. 
Amounts billed to a customer in a sale transaction related to shipping and
handling is classified as revenue.




Income
Taxes




The
Company is treated as a partnership for federal and state income tax purposes
and generally does not incur income taxes. Instead, its earnings and losses are
included in the income tax returns of the members. Therefore, no provision or
liability for federal or state income taxes has been included in these financial
statements.




Differences
between financial statement basis of assets and tax basis of assets is primarily
related to depreciation, interest rate swaps, derivatives, inventory,
compensation and  capitalization and amortization of organization and
start-up costs for tax purposes, whereas these costs are expensed for financial
statement purposes.




The
Company adopted guidance for accounting for uncertainty in income taxes on
January 1, 2007.  As a result of the adoption of this guidance, the
Company has evaluated whether they have any significant tax uncertainties that
would require recognition or disclosure.  Primarily due to its
partnership tax status, the Company does not have any significant tax
uncertainties that would require recognition or disclosure.




Equity-Based
Compensation




The
Company recognizes the related costs under these agreements using the
straight-line attribution method over the grant period and the grant date fair
value unit price.  As of June 30, 2009, the personnel covered by the
Plan had either left employment or given notice that they were going to leave
employment.  Leaving employment resulted in these employees forfeiting
the award and prior recognized equity-based compensation expense related to
these grants were reversed through compensation expense during the three months
ended June 30, 2009.  During June 2009, 5,000 units were issued under
the terms of the Plan.




During
2007, the Company exercised an option to repurchase 200,000 Units in association
with this Plan.  180,000 Units are still held in treasury and will not
be issued under the Plan.  While the Company does not have any other
equity-based compensation plans currently in place, these Units could be used
for that purpose in the future.  Equity-based compensation expense was
$(-53,334) and $22,000 for the years ended December 31, 2009 and 2008,
respectively.  As of December 31, 2009, the total equity-based
compensation expense related to nonvested awards not yet recognized was
$0.




F-9


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007




Earnings (Loss) Per
Unit




Basic
earnings (loss) per unit is calculated by dividing net earnings (loss) by the
weighted average units outstanding during the period.  Fully diluted
earnings per unit is calculated by dividing net earnings by the weighted average
member units and member unit equivalents outstanding during the
period.  For 2009, 2008, and 2007, the Company had 0, 50,000 and
45,000 member unit equivalents, respectively.  For 2008, member unit
equivalents were not included in diluted equivalents outstanding as their effect
is anti-dilutive.




Environmental
Liabilities




The
Company’s operations are subject to environmental laws and regulations adopted
by various governmental entities in the jurisdiction in which it operates. These
laws require the Company to investigate and remediate the effects of the release
or disposal of materials at its location. Accordingly, the Company has adopted
policies, practices and procedures in the areas of pollution control,
occupational health and the production, handling, storage and use of hazardous
materials to prevent material, environmental or other damage, and to limit the
financial liability which could result from such events. Environmental
liabilities, if any, are recorded when the liability is probable and the costs
can reasonably be estimated. No such liabilities have been identified as of
December 31, 2009 and 2008.




Going
Concern and Management’s Plans




Certain
factors existed as of December 31, 2008 that raised substantial doubt about the
Company’s ability to continue as a going concern.  These included poor
market conditions, negative operating cash flows and past and projected
violations of its loan covenants that had not been waived by its
Bank.  Those uncertainties have been removed as of December 31, 2009
as market conditions have improved, the Company has negotiated favorable
amendments to its loan agreements, the Company has regained compliance with its
loan covenants and has received waivers for all past covenant
violations.  In addition, the Company projects that it will be able to
meet its covenants throughout 2010, based on market conditions as of March 2010
along with its assumptions about future market conditions.  Our
projections assume slight improvement in the spread between ethanol and corn
prices during the last six months of 2010 as we anticipate that the current
oversupply situation will be mitigated, in part, by an increase in gasoline
demand through the summer driving season and more discretionary blending due to
the significant favorable spread that currently exists between gasoline and
ethanol prices (when ethanol prices are lower than gasoline prices, blenders
have an incentive to blend more ethanol into gasoline).  Based on this
information, the Company’s long-term debt has been reclassified as a non-current
liability as of December 31, 2009 with only the portion due within one year
shown as current.




2.  CONCENTRATIONS




Coal




Coal is
an important input to our manufacturing process. During the fiscal year ended
December 31, 2009, we used approximately 88,800 tons of coal.  We have
entered into a new two year agreement with Westmoreland Coal Sales Company
(“Westmoreland”) to supply PRB coal through 2011.  Whether the Plant
runs long-term on lignite or PRB coal, there can be no assurance that the coal
we need will always be delivered as we need it, that we will receive the proper
size or quality of coal or that our coal combustor will always work properly
with lignite or PRB coal. Any disruption could either force us to reduce our
operations or shut down the Plant, both of which would reduce our
revenues.




We
believe we could obtain alternative sources of PRB or lignite coal if necessary,
though we could suffer delays in delivery and higher prices that could hurt our
business and reduce our revenues and profits. We believe there is sufficient
supply of coal from the PRB coal regions in Wyoming and Montana to meet our
demand for PRB coal.  We also believe there is sufficient supply of
lignite coal in North Dakota to meet our demand for lignite coal.




If there
is an interruption in the supply or quality of coal for any reason, we may be
required to halt production. If production is halted for an extended period of
time, it may have a material adverse affect on our operations, cash flows and
financial performance.




In
addition to coal, we could use natural gas as a fuel source if our coal supply
is significantly interrupted. There is a natural gas line within three miles of
our Plant and we believe we could contract for the delivery of enough natural
gas to operate our Plant at full capacity. Natural gas tends to be significantly
more expensive than coal and we would also incur significant costs to adapt our
power systems to natural gas. Because we are already operating on coal, we do
not expect to need natural gas unless coal interruptions impact our
operations.




Sales




We are
substantially dependent upon RPMG for the purchase, marketing and distribution
of our ethanol. RPMG purchases 100% of the ethanol produced at our Plant, all of
which is marketed and distributed to its customers. Therefore, we are highly
dependent on RPMG for the successful marketing of our ethanol. In the event that
our relationship with RPMG is interrupted or terminated for any reason, we
believe that we could locate another entity to market the
ethanol.  However, any interruption or termination of this
relationship could temporarily disrupt the sale and production of ethanol and
adversely affect our business and operations and potentially result in a higher
cost to the Company.




We are
substantially dependent on CHS for the purchase, marketing and distribution of
our DDGS. CHS purchases 100% of the DDGS produced at the Plant (approximately
12.5% of our total revenue), all of which are marketed and distributed to its
customers. Therefore, we are highly dependent on CHS for the successful
marketing of our DDGS. In the event that our relationship with CHS is
interrupted or terminated for any reason, we believe that another entity to
market the DDGS could be located. However, any interruption or termination of
this relationship could temporarily disrupt the sale and production of DDGS and
adversely affect our business and operations.




F-10


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


3.
DERIVATIVE INSTRUMENTS




From time
to time the Company enters into derivative transactions to hedge its exposures
to interest rate and commodity price fluctuations. The Company does not enter
into derivative transactions for trading purposes.




The
Company provides qualitative disclosures about objectives and strategies for
using derivatives, quantitative disclosures about fair value amounts of gains
and losses from derivative instruments, and disclosures about
credit-risk-related contingent features in derivative agreements.




As of
December 31, 2009, the Company had entered into interest rate swap agreements
along with corn and ethanol derivative instruments.  The Company
records its derivative financial instruments as either assets or
liabilities at fair value in the statement of financial
position.  Derivatives qualify for treatment as hedges when there is a
high correlation between the change in fair value of the derivative instrument
and the related change in value of the underlying hedged item. Based upon the
exposure being hedged, the Company designates its hedging instruments as a fair
value hedge, a cash flow hedge, a hedge against foreign currency exposure or
leaves them undesignated.  The Company formally documents, designates,
and assesses the effectiveness of transactions that receive hedge accounting
initially and on an on-going basis.  The Company does not currently
have any derivative instruments that are designated as effective hedging
instruments for accounting purposes.




Commodity
Contracts




As part
of its hedging strategy, the Company may enter into ethanol and corn
commodity-based derivatives in order to protect cash flows from fluctuations
caused by volatility in commodity prices and protect gross profit margins from
potentially adverse effects of market and price volatility on ethanol sales and
corn purchase commitments where the prices are set at a future
date.  These derivatives are not designated as effective hedges for
accounting purposes. For derivative instruments that are not accounted for as
hedges, or for the ineffective portions of qualifying hedges, the change in fair
value is recorded through earnings in the period of change. Ethanol derivative
fair market value gains or losses are included in the results of operations and
are classified as revenue and corn derivative changes in fair market value are
included in cost of goods sold.


As
      of:
              
              
              December 31,
      2009
              
              
              
              December
      31, 2008Contract
      Type
              
              
              #
      of Contracts
              
              
              
              Notional
      Amount (Qty)
              
              
              Fair
      Value
              
              
              
              #
      of Contracts
              
              
              
              Notional
      Amount (Qty)
              
              
              Fair
      ValueCorn
      futures
              
              
              82
              
              
              
              410,000
              
              bushels
              
              $
              129,063
              
              
              
              404
              
              
              
              2,021,500
              
              bushels
              
              $
              (1,051,052
              )Ethanol
      swap contracts
              
              
              530
              
              
              
              7,632,000
              
              gallons
              
              
              (806,490
              )
              
              
              ―
              
              
              
              ―
              
              gallons
              
              
              ―Total
      fair value
              
              
              
              
              
              
              
              
              
              
              $
              (677,427
              )
              
              
              
              
              
              
              
              
              
              
              $
              (1,051,052
              )Amounts
      are recorded separately on the balance sheet - negative numbers represent
      liabilties
  None of
the commodity contracts in place at December 31, 2009 and 2008 were designated
as effective hedges for accounting purposes.  As such, the change in
fair value of the commodity contracts in place at December 31, 2009 and 2008
have been recorded in the results of operations and classified as stated
above.




Interest
Rate Contracts




The
Company manages its floating rate debt using interest rate swaps. The Company
has entered into fixed rate swaps to alter its exposure to the impact of
changing interest rates on its results of operations and future cash outflows
for interest. Fixed rate swaps are used to reduce the Company’s risk of the
possibility of increased interest costs. Interest rate swap contracts are
therefore used by the Company to separate interest rate risk management from the
debt funding decision.




At
December 31, 2009 and 2008, the Company had approximately $30.8 million and
$33.8 million, respectively, of notional amount outstanding in swap agreements
that exchange variable interest rates (one-month LIBOR and three-month LIBOR)
for fixed interest rates over the terms of the agreements.  The fair value
of the interest rate swaps is included in current liabilities and totaled
approximately $2.4 million and $2.9 million as of December 31, 2009 and 2008,
respectively.  These agreements are not designated as an effective
hedge for accounting purposes and the change in fair market value and associated
net settlements are recorded in interest expense.  The swaps mature in
April 2012.




Net
settlements on the interest rate swaps are recorded in interest
expense.  Please see Note 5 for detail on the amount of the net
settlements.




F-11


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007
  The
following tables provide details regarding the Company’s derivative financial
instruments at December 31, 2009 and 2008:


Derivatives
      not designated as hedging instruments for accounting
    purposesBalance
      Sheet - as of December 31, 2009
              Asset
              
              LiabilityDerivative
      instruments, at fair value
              
              $
              129,063
              
              
              $
              806,490Interest
      rate swaps, at fair value
              
              
              ―
              
              
              
              2,360,686Total
      derivatives not desingated as hedging instruments for accounting
      purposes
              
              $
              129,063
              
              
              $
              3,167,176Balance
      Sheet - as of December 31, 2008
              Asset
              
              LiabilityDerivative
      instruments, at fair value
              
              $
              ―
              
              
              $
              1,051,052Interest
      rate swaps, at fair value
              
              
              ―
              
              
              
              2,861,530Total
      derivatives not desingated as hedging instruments for accounting
      purposes
              
              $
              ―
              
              
              $
              3,912,582
  Statement
      of Operations
              
              Location
      of gain (loss) recognized in income
              
              Amount
      of gain (loss) recognized in income during the year ended December 31,
      2009
              
              
              Amount
      of gain (loss) recognized in income during the year ended December 31,
      2008Corn
      derivative instruments
              
              Cost
      of Goods Sold
              
              $
              (474,643
              )
              
              $
              6,154,162Ethanol
      derivative instruments
              
              Revenues
              
              
              (1,561,940
              )
              
              
              (2,326,266
              )Interest
      rate swaps
              
              Interest
      Expense
              
              
              500,843
              
              
              
              (1,817,338
              )Total
              
              
              
              $
              (1,535,740
              )
              
              $
              2,010,558




4.
INVENTORY




Inventory
is valued at lower of cost or market.  Inventory values as of December
31, 2009 and 2008 were as follows:




As
      of December 31,
              
              2009
              
              
              2008Raw
      materials, including corn, chemicals and supplies
              
              $
              4,921,532
              
              
              $
              1,636,631Work
      in process
              
              
              642,701
              
              
              
              681,187Finished
      goods, including ethanol and distillers grains
              
              
              1,428,798
              
              
              
              1,035,774Total
      inventory
              
              $
              6,993,031
              
              
              $
              3,353,592




Lower of
cost or market adjustments for the years ended December 31, 2009 and 2008 were
as follows:




For
      the years ended December 31,
              
              2009
              
              
              2008Loss
      on firm purchase commitments
              
              $
              169,000
              
              
              $
              3,470,110Lower
      of cost or market adjustment for inventory on hand
              
              
              1,464,500
              
              
              
              771,200Total
      lower of cost or market adjustments
              
              $
              1,633,500
              
              
              $
              4,241,310




The
Company typically enters into forward corn purchase contracts under which it is
required to take delivery at the contract price.  As of December 31,
2009 and 2008 the Company had accrued losses on these firm purchase commitments
of $0 and $1.4 million, respectively.  The amount of the loss on firm
purchase commitments is determined by applying a methodology similar to that
used in the impairment valuation with respect to inventory.  Given the
uncertainty of future ethanol prices, these losses may not be recovered, and
further losses on the outstanding purchase commitments could be recorded in
future periods.




5.
BANK FINANCING




Long-term
debt consists of the following:




As
      of December 31,
              
              2009
              
              
              2008Notes
      payable under loan agreement to bank, see details below
              
              $
              44,541,350
              
              
              $
              43,436,721Subordinated
      notes payable, see details below
              
              
              5,525,000
              
              
              
              5,525,000Capital
      lease obligations (Note 7)
              
              
              53,675
              
              
              
              101,480Total
      Long-Term Debt
              
              
              50,120,025
              
              
              
              49,063,201Less
      amounts due within one year *
              
              
              6,500,000
              
              
              
              49,063,201Total
      Long-Term Debt Less Amounts Due Within One Year
              
              $
              43,620,025
              
              
              $
              0











F-12


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


The
estimated maturities of long-term debt and capital lease obligations are as
follows:




As
      of December 31,
              
              20092010
              
              $
              6,500,0002011
              
              
              10,940,7212012
              
              
              32,653,1882013
              
              
              24,7502014
              
              
              1,366Thereafter
              
              
              ―Total
              
              $
              50,120,025




We are
subject to a number of covenants and restrictions in connection with our credit
facilities, including:





•
            
            Providing
      the Bank with current and accurate financial
statements;•
            
            Maintaining
      certain financial ratios, minimum net worth, and working
      capital;•
            
            Maintaining
      adequate insurance;•
            
            Not
      making, or allowing to be made, any significant change in our business or
      tax structure; and•
            
            Limiting
      our ability to make distributions to
members.




The
construction loan agreement also contains a number of events of default
(including violation of our loan covenants) which, if any of them were to occur,
would give the Bank certain rights, including but not limited to:





•
            
            declaring
      all the debt owed to the Bank immediately due and payable;
    and•
            
            taking
      possession of all of our assets, including any contract
      rights.




Because
our long-term debt agreements are secured by substantially all of the Company’s
assets, the Bank could then sell all of our assets or business and apply any
proceeds to repay their loans. We would continue to be liable to repay any loan
amounts still outstanding.




Credit
Agreement




In
December 2005, the Company entered into a Credit Agreement with a bank
providing for a total credit facility of approximately $59,712,000 for the
purpose of funding the construction of the Plant. The construction loan
agreement provides for the Company to maintain certain financial ratios and meet
certain non-financial covenants. The loan agreement is secured by substantially
all of the assets of the Company and includes the terms as described
below.




During
2009, the Company entered into the Sixth Amendment to its Loan Agreements
(“Sixth Amendment”) which allowed it to defer two principal payments due during
2009 (April 16 and July 16).  The Sixth Amendment also contained
provisions instituting an interest rate floor of 6% along with a new interest
rate spread of 400 basis points over certain LIBOR rates.  The Company
also entered into the Seventh Amendment to its Loan Agreements (“Seventh
Amendment”) in March of 2010 (effective as of December 31, 2009).  The
Seventh Amendment changed certain definitions and covenant ratios within the
financial covenants that allowed the Company to meet those covenants as of
December 31, 2009 as well as waived all prior covenant
violations.  The Seventh Amendment also calls for an additional
principal payment that approximates an increase in our interest rate spread to
500 basis points over certain LIBOR rates.




F-13


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


Interest
      expense for the year ended December 31,
              
              2009
              
              
              2008
              
              
              2007Interest
      expense on long-term debt
              
              $
              2,930,910
              
              
              $
              3,545,910
              
              
              $
              5,160,282Amortization/write-off
      of deferred financing costs
              
              
              567,386
              
              
              
              201,020
              
              
              
              214,169Change
      in fair value of interest rate swaps
              
              
              (500,843
              )
              
              
              1,817,338
              
              
              
              933,256Net
      settlements on interest rate swaps
              
              
              991,463
              
              
              
              449,031
              
              
              
              (39,000
              )Total
      interest expense
              
              $
              3,988,916
              
              
              $
              6,013,299
              
              
              $
              6,268,707




Construction
Loan




The
Company has four long-term notes (collectively the “Term Notes”) in place as of
December 31, 2009.  Three of the notes were established in conjunction
with the termination of the original construction loan agreement on April 16,
2007.  The fourth note was entered into during December 2007 (the
“December 2007 Fixed Rate Note”) when the Company entered into a second interest
rate swap agreement which effectively fixed the interest rate on an additional
$10 million of debt.  The construction loan agreement requires the
Company to maintain certain financial ratios and meet certain non-financial
covenants.  Each note has specific interest rates and terms as
described below.




Term
      Notes - Construction Loan
  Outstanding
      Balance (Millions)
              
              
              
              Interest
      RateTerm
      Note
              
              
              December
      31, 2009
              
              
              
              December
      31, 2008
              
              
              
              December
      31, 2009
              
              
              
              December
      31, 2008
              
              
              
              Range
      of Estimated Quarterly Principal Payment Amounts
              
              
              
              Estimated
      Final Payment (millions)
              
              
              
              NotesFixed
      Rate Note
              
              $
              23.60
              
              
              $
              24.70
              
              
              
              6.00
              %
              
              
              5.79
              %
              
              $
              540,000
      - $650,000
              
              
              $
              18.30
              
              
              
              1,
      2, 4Variable
      Rate Note
              
              
              2.10
              
              
              
              3.00
              
              
              
              6.00
              %
              
              
              6.04
              %
              
              $
              450,000
      - $460,000
              
              
              
              1.20
              
              
              
              1,
      2, 3, 5Long-Term
      Revolving Note
              
              
              10.00
              
              
              
              6.40
              
              
              
              6.00
              %
              
              
              5.74
              %
              
              $
              277,000
      - $535,000
              
              
              
              7.70
              
              
              
              1,
      2, 6, 72007
      Fixed Rate Note
              
              
              8.80
              
              
              
              9.20
              
              
              
              6.00
              %
              
              
              6.19
              %
              
              $
              200,000
      - $239,000
              
              
              
              6.10
              
              
              
              1,
      2, 5


Notes
 1
      -
                The
      scheduled maturity date is April
2012
 2
      -
                Range
      of estimated quarterly principal payments is based on principal balances
      and interest rates as of December 31,
2009
 3
      -
                  Quarterly
      payments of $634,700 are applied first to interest on the Long-Term
      Revolving Note, next to accrued interest on theVariable
      Rate Note and finally to principal on the Variable Rate
      Note.  Variable Rate Note is estimated to be paid off in April
      2010 asExcess
      Cash Flow payment that is due will be applied to the Variable Rate Note
      and to the Long-Term Revolving
Note.
 4
      -
                  Interest
      rate based on 5.0% over three-month LIBOR with a 6% minimum, reset
      quarterly
 5
      -
                  Interest
      rate based on 5.0% over three-month LIBOR with a 6% minimum, reset
      quarterly
 6
      -
                  Interest
      rate based on 5.0% over one-month LIBOR with a 6% minimum, reset
      monthly
 7
      -
                  Principal
      payments would be made on the Long-Term Revolving Note once the Variable
      Rate Note is paid in
full.




Revolving Line of
Credit




During
July 2008, the Company renewed its $3,500,000 line of credit agreement for a one
year period, subject to certain borrowing base limitations.  The line
of credit was not renewed in July 2009.  The Company has no
outstanding borrowings at December 31, 2009, 2008 and 2007.




Interest Rate Swap
Agreements




In
December 2005, the Company entered into an interest rate swap transaction
that effectively fixed the interest rate at 8.08% on the outstanding principal
of the Fixed Rate Note.  In December 2007, the Company entered into a
second interest rate swap transaction that effectively fixed the interest rate
at 7.695% on the outstanding principal of the December 2007 Fixed Rate
Note.




The
interest rate swaps were not designated as either a cash flow or fair value
hedge. Fair value adjustments and net settlements are shown in interest
expense.




Letters of
Credit




During
2009, the Company issued $750,000 in letters of credit from the Bank in
conjunction with the issuance of two bonds it needs for
operations.  There is no expiration date on the letters of credit and
the Company does not anticipate the Bank having to advance any funds under these
letters of credit.  The letters of credit are subject to a 4%
quarterly commitment fee.  The $137,000 letter of credit that was
outstanding at December 31, 2008 has been allowed to expire.




Subordinated
Debt




As part
of the construction loan agreement, the Company entered into three separate
subordinated debt agreements totaling approximately $5,525,000 and received
funds from these debt agreements during 2006. Interest is charged at a rate of
2.0% over the Variable Rate Note interest rate which totaled 8.0% and 8.04% at
December 31, 2009 and 2008, respectively.  Interest is due and payable
subject to approval by the Bank.  Interest is compounding with any
unpaid interest converted to principal. Amounts will be due and payable in full
in March 2011 subject to approval by the Bank.  The balance
outstanding on these loans was $5,525,000 as of December 31, 2009 and 2008,
respectively




F-14


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


6.
FAIR VALUE





Effective
January 1, 2008, the Company adopted accounting standards related to the
measurement of fair value which outline a framework for measuring fair value,
and details the required disclosures about fair value measurements.




The
standards permit the Company to irrevocably choose to measure certain financial
instruments and other items at fair value. Except for those assets and
liabilities which are required to be recorded at fair value the Company elected
not to record any other assets or liabilities at fair value.




Fair
value is defined as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date in the principal or most advantageous market. The Company
uses a fair value hierarchy that has three levels of inputs, both observable and
unobservable, with use of the lowest possible level of input to determine fair
value. Level 1 inputs include quoted market prices in an active market or the
price of an identical asset or liability. Level 2 inputs are market data, other
than Level 1, that are observable either directly or indirectly. Level 2 inputs
include quoted market prices for similar assets or liabilities, quoted market
prices in an inactive market, and other observable information that can be
corroborated by market data. Level 3 inputs are unobservable and corroborated by
little or no market data. The Company uses valuation techniques in a consistent
manner from year-to-year.





The
following table provides information on those assets and liabilities that are
measured at fair value on a recurring basis as of December 31, 2009 and 2008,
respectively.  Money market funds shown below are included in cash and
equivalents on the balance sheet.




Fair
      Value Measurement UsingCarrying
      Amount as of
              December
      31, 2009
            
            
            Fair
      Value as of December 31, 2009
            
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3AssetsMoney
      market funds
            
            $
            5,010,325
            
            
            $
            5,010,325
            
            
            $
            5,010,325
            
            
            $
            ―
            
            
            $
            ―Derivative
      instruments
            
            
            129,063
            
            
            
            129,063
            
            
            
            129,063
            
            
            
            ―
            
            
            
            ―Total
            
            $
            5,139,388
            
            
            $
            5,139,388
            
            
            $
            5,139,388
            
            
            $
            ―
            
            
            $
            ―LiabilitiesInterest
      rate swaps
            
            $
            2,360,686
            
            
            $
            2,360,686
            
            
            $
            ―
            
            
            $
            2,360,686
            
            
            $
            ―Derivative
      instruments
            
            
            806,490
            
            
            
            806,490
            
            
            
            806,490
            
            
            
            ―
            
            
            
            ―Total
            
            $
            3,167,176
            
            
            $
            3,167,176
            
            
            $
            806,490
            
            
            $
            2,360,686
            
            
            $
            ―




Fair
      Value Measurement UsingCarrying
      Amount as of
                December
      31, 2008
              
              
              Fair
      Value as of December 31, 2008
              
              
              Level
      1
              
              
              Level
      2
              
              
              Level
      3AssetsMoney
      market funds
              
              $
              4,366,121
              
              
              $
              4,366,121
              
              
              $
              4,366,121
              
              
              $
              ―
              
              
              $
              ―Derivative
      instruments
              
              
              ―
              
              
              
              ―
              
              
              
              ―
              
              
              
              ―
              
              
              
              ―Total
              
              $
              4,366,121
              
              
              $
              4,366,121
              
              
              $
              4,366,121
              
              
              $
              ―
              
              
              $
              ―LiabilitiesInterest
      rate swaps
              
              $
              2,861,530
              
              
              $
              2,861,530
              
              
              $
              ―
              
              
              $
              2,861,530
              
              
              $
              ―Derivative
      instruments
              
              
              1,051,052
              
              
              
              1,051,052
              
              
              
              1,051,052
              
              
              
              ―
              
              
              
              ―Total
              
              $
              3,912,582
              
              
              $
              3,912,582
              
              
              $
              1,051,052
              
              
              $
              2,861,530
              
              
              $
              ―





The fair
value of the money market funds and corn and ethanol derivative instruments are
based on quoted market prices in an active market.  The fair value of
the interest rate swap instruments are determined by using widely accepted
valuation techniques including discounting cash flow analysis on the expected
cash flows of each instrument. The analysis of the interest rate swap reflects
the contractual terms of the derivatives, including the period to maturity and
uses observable market-based inputs and uses the market standard methodology of
netting the discounted future fixed cash receipts and the discounted expected
variable cash payments. The variable cash payments are based on an expectation
of future interest rates derived from observable market interest rate
curves.




F-15


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


Financial
Instruments Not Measured at Fair Value




The
estimated fair value of the Company’s long-term debt, including the short-term
portion, at December 31, 2009 approximated the carrying value of approximately
$50 million.  The Company had negotiated an amendment to its loan
agreements during 2009 that set an interest rate floor of 6% which was the
interest rate in effect at December 31, 2009 and was thought to approximate the
market interest rate for this debt.  The estimated fair value of the
Company’s long-term debt, including the short-term portion, at December 31, 2008
approximated its carrying value of $48.8 million.  Fair value was
estimated using estimated market interest rates as of December 31,
2008.  The fair values and carrying values consider the terms of the
related debt and exclude the impacts of debt discounts and derivative/hedging
activity.




7.
LEASES




The
Company leases equipment under operating and capital leases through May 2014.
The Company is generally responsible for maintenance, taxes, and utilities for
leased equipment. Equipment under an operating lease includes a locomotive and
rail cars. Rent expense for operating leases was $506,000, $356,000 and $27,000
for the years ending December 31, 2009, 2008 and 2007, respectively.
Equipment under capital leases consists of office equipment and plant
equipment.




Equipment
under capital leases is as follows at:




As
      of December 31,
              
              2009
              
              
              2008Equipment
              
              $
              219,476
              
              
              $
              216,745Accumulated
      amortization
              
              
              63,248
              
              
              
              45,996Net
      equipment under capital lease
              
              $
              156,228
              
              
              $
              170,749


The Company had the following
minimum commitments, which at inception had non-cancelable terms of more than
one year:




As
      of December 31, 2009
              
              Operating
      Leases
              
              
              Capital
      Leases2010
              
              $
              489,660
              
              
              $
              45,5182011
              
              
              470,305
              
              
              
              3,3542012
              
              
              416,400
              
              
              
              3,3542013
              
              
              34,700
              
              
              
              3,3542014
              
              
              ―
              
              
              
              1,398Total
      minimum lease commitments
              
              $
              1,411,065
              
              
              
              56,978Less
      amount representing interest
              
              
              
              
              
              
              3,303Present
      value of minimum lease commitments included in preceding long-term
      liabilities
              
              
              
              
              
              $
              53,675


8.
MEMBERS’ EQUITY




The
Company has one class of membership units outstanding (Class A) with each unit
representing a pro rata ownership interest in the Company’s capital, profits,
losses and distributions.  During 2009, 5,000 units vested, and were
issued, under an employee equity based compensation agreement.  These
units were issued from treasury units repurchased during
2007.  Treasury units purchased are accounted for using the cost
method.  The equity-based compensation plan is described in more
detail in Note 9.  As of December 31, 2009 and 2008 there 40,193,973
and 40,188,973 units issued and outstanding, respectively.




9.
EQUITY-BASED COMPENSATION




2006 Equity-Based Incentive
Plan




During
2006, the Company implemented an equity-based incentive plan (the “Plan”) which
provided for the issuance of restricted Units to the Company’s key management
personnel, for the purpose of compensating services rendered. As of June 30,
2009, the personnel covered by the Plan had either left employment or given
notice that they were going to leave employment.  Leaving employment
caused the employees to forfeit the award and prior recognized equity-based
compensation expense related to these grants were reversed through compensation
expense during the three months ended June 30, 2009.  During June
2009, 5,000 units were issued under the terms of the Plan.




During
2007, the Company exercised an option to repurchase 200,000 Units in association
with this Plan.  180,000 Units are still held in treasury and will not
be issued under the Plan.  While the Company does not have any other
equity-based compensation plans currently in place, these Units could be used
for that purpose in the future.  Equity-based compensation expense was
approximately $(-53,334) and $22,000 for the years ended December 31 2009 and
2008, respectively.  As of December 31, 2009, the total equity-based
compensation expense related to nonvested awards not yet recognized was
$0.




F-16


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


10.
GRANTS




In 2006,
the Company entered into a contract with the State of North Dakota through the
Industrial Commission for a lignite coal grant not to exceed
$350,000.  The Company received $275,000 from this grant during 2006
and in the process of submitting the final report to the Industrial Commission
at which time repayment of the grant will commence.   Because the
Company has not met the minimum lignite usage requirements specified in the
grant for any year in which the Plant has operated, it expects to repay the
grant at a rate of approximately $35,000 per year.  This repayment
could begin in 2010.




The
Company has entered into an agreement with Job Service North Dakota for a new
jobs training program. This program provides incentives to businesses that are
creating new employment opportunities through business expansion and relocation
to the state. The program provides no-cost funding to help offset the cost of
training. The Company is eligible to receive up to approximately $270,000 over
ten years. The Company received and earned approximately $37,000 and $73,000
fiscal years ended December 31, 2009 and 2008, respectively.




11.
COMMITMENTS AND CONTINGENCIES




Design Build
Contract




The
Company signed a Design-Build Agreement with Fagen, Inc. (“Fagen”) in September
2005 to design and build the ethanol plant at a total contract price of
approximately $77 million.  The total cost of the project, including
the construction of the ethanol plant and start-up expenses was approximately
$99 million at December 31, 2007.  The Company has remaining payments
under this Design-Build Agreement of approximately $3.9 million.  This
payment has been withheld pending satisfactory resolution of a punch list of
items including a major issue with the coal combustor experienced during start
up.  The Plant was originally designed to be able to run on lignite
coal and meet the emissions requirements in the Company’s
permits..  During the first four months of operation, however, the
Plant experienced numerous shut downs related to running on lignite coal and
could not meet emissions requirements.  In April 2007, the Company
switched to using powder river basin coal as its fuel source and has not
experienced a single shut down related to coal quality however it has still not
been able to meet all of its emissions requirements running on PRB coal which is
a cleaner fuel source than lignite.  An amount approximately equal to
the final payment of $3.9 million has been set aside in a separate money market
account. Any amounts remaining in this account after satisfactory resolution of
this issue could be used to pay down the Company’s long-term debt, make
necessary upgrades to its plant or be used for operations pending bank
approval.




Consulting
Contracts




In
December 2003, the Company entered into a Development Services Agreement
(the “DSA”) and a Management Agreement (the “MA”) with Greenway
Consulting.  Under the terms of the DSA, Greenway Consulting provided
project development, construction management and initial plant operations
through start up.  The DSA also called for Greenway Consulting to be
reimbursed for salary and benefit expenses of the General Manager and Plant
Manager retroactive to the date six months prior to successful commissioning of
the plant.  The Company has paid Greenway Consulting $2,075,000 for
services rendered under the DSA and reimbursed Greenway Consulting $135,000 for
salary and benefit expenses.  The Company still owes $152,500 to
Greenway for services rendered under the DSA.  Payment is being
withheld pending satisfactory resolution to a punch list of items to be
completed by Fagen including problems related to the coal
combustor.  The DSA expired upon successful commissioning of the plant
which occurred on January 1, 2007 at which time the MA went into
effect.




During
2009, the Company amended and restated the terms of the MA .  Under
the new terms of the MA, Red Trail assumes responsibility for day to day
operations of the plant, and the Company’s plant manager and CEO are now direct
employees of Red Trail.  Greenway still provides management consulting
services for the Company and, for these services, receives $171,600 per year
plus 4% of the Company’s annual pre-tax net income.  The other terms
of the contract are materially unchanged – including the expiration date of the
contract which is December 31, 2011.  The Company had started
withholding payment from Greenway under the terms of the original MA on January
1, 2009 pending resolution of certain contractual items.  Those items
have been resolved with Greenway agreeing to forgo payment of the monthly
management fee for the first six months of 2009.  For the years ended
December 31, 2009 and 2008, the Company had expensed approximately $175,000 and
$534,000, respectively for management services under the MA and has also
expensed approximately $296,000 and $288,000, respectively, for reimbursement of
salary and benefits.




In
February 2006, the Company entered into a Risk Management Agreement for
grain procurement, pricing, hedging and assistance in risk management as it
pertains to ethanol and co-products with John Stewart & Associates (“JSA”).
JSA will provide services in connection with grain hedging, pricing and
purchasing. The Company will pay $1,200 per month for these services beginning
no sooner than ninety days preceding plant startup. In addition, JSA will serve
as clearing broker for the Company and charge a fee of $15.00 per contract plus
clearing and exchange fees.  As of December 31, 2009, there were no
amounts outstanding.




Utility
Agreements




The
Company entered into a contract with Roughrider Electric Cooperative, Inc. dated
August 2005, for the provision of electric power and energy to the
Company’s plant site. The agreement is effective for five years from
August 2005, and thereafter for additional three year terms until
terminated by either party giving to the other six months’ notice in writing.
The rate the Company will pay for electricity during 2010 is approximately $.05
per kilowatt hour.




F-17


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


In
March 2006, the Company entered into a ten year contract with Southwest
Water Authority to purchase raw water. The contract, which was amended in 2007,
includes a renewal option for successive periods not to exceed ten years. The
actual rate for raw water was $2.54 per one thousand gallons for the year ended
December 31, 2009.  The base rate may be adjusted annually by the
State Water Commission.




In
June 2006, the Company entered into an agreement with Montana-Dakota
Utilities Co. (“MDU”) for the construction and installation of a natural
gas line. The agreement required the Company to pay $3,500 prior to the
commencement of the installation and to maintain an irrevocable letter of credit
in the amount of $137,385 for a period of five years as a preliminary cost
participation requirement.  During 2009, this letter of credit was
allowed to expire and the Company paid approximately $23,000 as its share of the
cost participation requirement based on the volume of natural gas used by the
Company.




Marketing
Agreements




The
Company entered into a marketing agreement on March 10, 2008 with CHS for the
purpose of marketing and selling its DDGS.  The marketing agreement
has a term of six months which is automatically renewed at the end of the
term.  The agreement can be terminated by either party upon written
notice to the other party at least thirty days prior to the end of the term of
the agreement.  Prior to March 2008, the Company had a marketing
agreement with Commodity Specialists Company (“CSC”) which assigned all rights,
title and interest in the agreement to CHS.  The terms of the new
agreement are not materially different from the prior
agreement.  Under the terms of the agreement, the Company pays CHS a
fee for marketing its DDGS.  The fee is 2% of the selling price of the
DDGS subject to a minimum of $1.50 per ton and a maximum of $2.15 per
ton.  Through the marketing of CHS and its relationships with local
farmers, the Company is not dependent upon one or a limited number of customers
for its DDGS sales.




The
Company entered into a new marketing agreement on January 1, 2008 with RPMG for
the purposes of marketing and distributing all of the ethanol produced at the
Plant (the “New Agreement”).  Prior to January 1, 2008 the Company had
a marketing agreement in place with Renewable Products Marketing Group
LLC.  Effective October 1, 2007, that contract was assigned to
RPMG.  The terms of the New Agreement are not materially different
than the prior agreement except as discussed below in relation to the fees paid
to RPMG.  Effective as of January 1, 2008, the Company also purchased
an ownership interest in RPMG.  Currently, the Company owns 8.33% of
the outstanding capital stock of RPMG and anticipates that its ownership
interest will be reduced if other ethanol plants that utilize RPMG’s marketing
services become owners of RPMG.  The Company’s ownership interest in
RPMG entitles it to a seat on its board of directors which is filled by its
Chief Executive Officer (“CEO”).  The New Agreement will be in effect
as long as the Company continues to be a member in RPMG.  From January
– August, 2009, the Company paid RPMG $.01 per gallon for each gallon sold by
RPMG.  Approximately 60% of this marketing fee was allocated to the
Company’s equity purchase which was completed in August.  After the
equity purchase was completed, the marketing fee decreased to approximately
$.004 per gallon.




Coal Purchase
Contract




The
Company entered into a contract in March 2004 with General Industries, Inc.
d/b/a Center Coal Company (“Center Coal”) for the purchase of lignite coal.
The term of the contract was for ten years from the commencement date agreed
upon by the parties.  During the startup period of January – April
2007, the Plant experienced a number of shut-downs as a result of issues related
to lignite coal quality and delivery, as specified in the coal purchase
agreement, along with the performance of the Plant’s coal combustor while
running on lignite coal.  As a result of these issues, the Company
terminated its lignite coal purchase and delivery contract with Center Coal and
switched to PRB coal as an alternative to lignite coal. Since making the change,
the Plant has not experienced a single shut-down due to coal
quality.  The Company entered into a two year agreement with
Westmoreland Coal Sales Company (“Westmoreland”) to supply PRB coal through 2009
which has now been extended through 2011.  The Company is required to
purchase between 90,000 and 115,000 tons of coal per year under this
agreement.




Coal Management
Contract




During
2008, the Company entered in to a contract with M-BAR-D LLC (“MBD”) for the
unloading of coal at the Company’s coal unloading facility along with transport
of the coal from the stockpile to the storage silos at the Plant.  The
contract runs for 2.5 years and is automatically renewed for two year terms
unless terminated in accordance with the terms of the contract.  Under
the terms of the agreement, the Company pays MBD $2.65 per ton for unloading the
coal and $1.30 per ton for transporting the coal subject to a 3% per year
increase.




Chemical Consignment
Purchase Contracts




During
November 2006, the Company entered into two consignment purchases for bulk
chemicals purchased through Genecor International Inc and Univar USA. Genecor
will provide the following enzymes: Alpha-Amylase, Glucoamylease and Protease.
The Univar agreement states that it will provide the following bulk chemicals:
Caustic Soda, Sulfuric Acid, Anhydrous Ammonia and Sodium Bicarbonate. All
Univar chemicals are purchased at market price for a five year
term.  The Genecor agreement was renewed by the Company on July 1,
2009 for a one year term.




Natural Gasoline
Contract




The
Company has entered into various contracts with suppliers for the purchase of
natural gasoline. The term of the most recent contract is May 2009 – March
2010.  The price per gallon is based off the average Conway natural
gas price plus $0.26.  The Company is in the process of working to
secure its supply of denaturant for the rest of 2010.




F-18


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


Firm Purchase Commitments
for Corn




To ensure
an adequate supply of corn to operate the Plant, the Company enters into
contracts to purchase corn from local farmers and elevators.  At
December 31, 2009, the Company had various fixed and basis contracts for
approximately 1.1 million bushels of corn.  Of the 1.1 million bushels
under contract, essentially all had a fixed price as of December 31,
2009.  During 2009, the Company implemented stricter limits on the
number of bushels of corn/how far in advance it would enter into fixed price
contracts.    Using the stated contract price for the fixed
contracts and using market prices, as of December 31, 2009, to price the basis
contracts the Company had commitments of approximately $4.1 million related to
all 1.1 million bushels under contract.




12.  DEFINED BENEFIT
CONTRIBUTION PLAN




The
Company established a simple IRA retirement plan for its employees during 2006.
The Company matches employee contributions to the plan up to 3% of employee’s
gross income. The amount contributed by the Company is vested 100% as soon as
the contribution is made on behalf of the employee. The Company contributed
approximately $48,000 and $56,000 for fiscal years ended December 31, 2009 and
2008, respectively.




13.
RELATED PARTY TRANSACTIONS




The Company has balances and transactions in the
normal course of business with various related parties for the purchase of corn,
sale of DDGs and sale of ethanol.  The related parties include unit
holders, members of the board of governors of the Company, Greenway and
RPMG.  The Company also has a note payable to Greenway, and pays
Greenway for plant management and other consulting fees (recorded in general and
administrative expense).  The Chief Manager of Greenway is a member of
the Company and was, for the period June 2009 – December 31, 2009, the Company’s
CEO.  Significant related party activity affecting consolidated
financial statements are as follows:




As
      of December 31,
              
              2009
              
              
              2008Balance
      SheetAccounts
      receivable
              
              $
              2,155,238
              
              
              $
              2,198,277Accounts
      payable
              
              
              1,164,218
              
              
              
              788,149Notes
      payable
              
              
              1,525,000
              
              
              
              1,525,000Statement
      of OperationsRevenues
              
              $
              82,162,189
              
              
              $
              117,379,764Cost
      of goods sold
              
              
              2,854,692
              
              
              
              2,712,392General
      and administrative expenses
              
              
              470,906
              
              
              
              1,087,552Inventory
      Purchases
              
              $
              6,996,695
              
              
              $
              9,669,953


14.
INCOME TAXES




The
difference between financial statement basis and tax basis of assets are as
follows:




As
      of December 31
              
              2009
              
              
              2008Financial
      Statement Basis of Assets
              
              $
              97,677,401
              
              
              $
              95,802,453Organization
      and start-up costs
              
              
              4,614,644
              
              
              
              5,141,445Inventory
      and compensation
              
              
              65,058
              
              
              
              34,458Net
      book value of property, plant and equipment
              
              
              (27,822,932
              )
              
              
              (19,293,573
              )Book
      to tax derivative difference
              
              
              158,436
              
              
              
              ―Income
      Tax Basis of Assets
              
              $
              74,692,607
              
              
              $
              81,684,783Financial
      Statement Basis of Liabilities
              
              $
              63,802,037
              
              
              $
              62,243,448Loss
      on firm purchase commitment
              
              
              ―
              
              
              
              1,426,800Interest
      rate swap
              
              
              (2,360,686
              )
              
              
              (2,861,529
              )Book
      to tax derivative difference
              
              
              (806,490
              )
              
              
              2,371,800Income
      Tax Basis of Liabilities
              
              $
              60,634,861
              
              
              $
              63,180,519




F-19


Red
Trail Energy, LLC
 Notes to
Financial Statements
 December
31, 2009, 2008 and 2007


The
amounts as of December 31, 2008 have been adjusted to match the balance sheet
presentation.




15.
QUARTERLY FINANCIAL DATA (UNAUDITED)




Summary
quarter results are as follows:




Statement
      of OperationsFor
      the quarters ended,
              
              March
      2009
              
              
              June
      2009
              
              
              September
      2009
              
              
              December
      2009Revenues
              
              $
              20,895,613
              
              
              $
              23,632,831
              
              
              $
              25,247,196
              
              
              $
              24,061,021Cost
      of goods sold
              
              
              20,902,577
              
              
              
              24,027,381
              
              
              
              22,127,122
              
              
              
              20,793,789Gross
      profit
              
              
              (6,964
              )
              
              
              (394,550
              )
              
              
              3,120,074
              
              
              
              3,267,232General
      and administrative expenses
              
              
              781,009
              
              
              
              701,337
              
              
              
              758,489
              
              
              
              572,056Operting
      income (loss)
              
              
              (787,973
              )
              
              
              (1,095,887
              )
              
              
              2,361,585
              
              
              
              2,695,176Interest
      expense
              
              
              1,305,222
              
              
              
              566,216
              
              
              
              1,211,111
              
              
              
              906,367Other
      income (expense)
              
              
              42,221
              
              
              
              402,450
              
              
              
              678,845
              
              
              
              53,159Net
      income (loss)
              
              $
              (2,050,974
              )
              
              $
              (1,259,653
              )
              
              $
              1,829,319
              
              
              $
              1,841,968Weighted
      average units - basic
              
              
              40,188,973
              
              
              
              40,189,028
              
              
              
              40,193,973
              
              
              
              40,193,973Weighted
      average units - diluted
              
              
              40,188,973
              
              
              
              40,189,028
              
              
              
              40,193,973
              
              
              
              40,193,973Net
      income (loss) per unit - basic
              
              $
              (0.05
              )
              
              $
              (0.03
              )
              
              $
              0.05
              
              
              $
              0.05Net
      income (loss) per unit - diluted
              
              $
              (0.05
              )
              
              $
              (0.03
              )
              
              $
              0.05
              
              
              $
              0.05
  For
      the Quarters ended,
              
              March
      2007
              
              
              June
      2008
              
              
              September
      2008
              
              
              December
      2008Revenues
              
              $
              33,420,005
              
              
              $
              35,692,315
              
              
              $
              36,047,461
              
              
              $
              26,743,733Cost
      of goods sold
              
              
              27,667,222
              
              
              
              30,460,525
              
              
              
              38,644,318
              
              
              
              34,253,173Gross
      profit
              
              
              5,752,783
              
              
              
              5,231,790
              
              
              
              (2,596,857
              )
              
              
              (7,509,440
              )General
      and administrative expenses
              
              
              746,596
              
              
              
              919,333
              
              
              
              666,866
              
              
              
              524,296Operting
      income (loss)
              
              
              5,006,187
              
              
              
              4,312,457
              
              
              
              (3,263,723
              )
              
              
              (8,033,736
              )Interest
      Expense
              
              
              2,439,805
              
              
              
              (62,661
              )
              
              
              1,116,343
              
              
              
              2,519,812Other
      income (expense)
              
              
              169,817
              
              
              
              688,926
              
              
              
              835,179
              
              
              
              931,620Net
      income
              
              $
              2,736,199
              
              
              $
              5,064,044
              
              
              $
              (3,544,887
              )
              
              $
              (9,621,928
              )Weighted
      average units - basic
              
              
              40,173,973
              
              
              
              40,173,973
              
              
              
              40,187,995
              
              
              
              40,188,973Weighted
      average units - diluted
              
              
              40,223,973
              
              
              
              40,228,973
              
              
              
              40,187,995
              
              
              
              40,188,973Net
      income (loss) per unit - basic
              
              $
              0.07
              
              
              $
              0.13
              
              
              $
              (0.09
              )
              
              $
              (0.24
              )Net
      income (loss) per unit - diluted
              
              $
              0.07
              
              
              $
              0.13
              
              
              $
              (0.09
              )
              
              $
              (0.24
              )




The above
quarterly financial data is unaudited, but in the opinion of management, all
adjustments necessary for a fair presentation of the selected data for these
periods presented have been included.




F-20