UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
DC 20549




FORM
10-K





x
            ANNUAL
      REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
      1934.FOR
      THE FISCAL YEAR ENDED DECEMBER 31,
2008




o
            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: None




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 x




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




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 x 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 o    Smaller
Reporting Company x




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




The
aggregate market value of the membership units held by non-affiliates of the
registrant as of December 31, 2008 was $43,560,069.  There is no
established public trading market for our membership units.  The
aggregate market value was computed by reference to the average sales price of
our Class A units recently traded on our Qualified Matching
Service.




As
of March 31, 2009 the Company has 40,188,973 Class A Membership Units
outstanding.




DOCUMENTS
INCORPORATED BY REFERENCE:




Portions
of the registrant’s 2009 Proxy Statement are hereby incorporated by reference in
Part III, Items 10, 11, 12, 13, and 14 of this report.












TABLE OF
CONTENTS


PagePART
      I
              
              
              2ITEM
      1. BUSINESS
              
              
              2ITEM
      1A. RISK FACTORS
              
              
              10ITEM
      2. PROPERTIES
              
              
              18ITEM
      3. LEGAL PROCEEDINGS
              
              
              18ITEM
      4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
              
              
              18PART
      II
              
              
              18ITEM
      5. MARKET FOR REGISTRANT’S MEMBER UNITS, RELATED MEMBER MATTERS AND ISSUER
      PURCHASED OF EQUITY SECURITIES
              
              
              18ITEM
      6. SELECTED FINANCIAL DATA
              
              
              19ITEM
      7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
      OF OPERATION
              
              
              20ITEM
      7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
    RISK
              
              
              31ITEM
      8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
              
              
              32ITEM
      9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
      FINANCIAL DISCLOSURE
              
              
              33ITEM
      9A(T). CONTROLS AND PROCEDURES.
              
              
              33ITEM
      9B. OTHER INFORMATION
              
              
              34PART
      III
              
              
              34ITEM
      10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE.
              
              
              34ITEM
      11. EXECUTIVE COMPENSATION
              
              
              34ITEM
      12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
      RELATED STOCKHOLDER MATTERS
              
              
              34ITEM
      13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
      INDEPENDENCE
              
              
              34ITEM
      14. PRINCIPAL ACCOUNTING FEES AND SERVICES
              
              
              34PART
      IV
              
              
              34ITEM
      15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
              
              
              34Signatures





2




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.





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.”





•
            
            Our
      ability to secure a waiver or forbearance agreement for future possible
      defaults on our loan agreements or renegotiate the terms of our loan
      agreements with our lenders;•
            
            Our
      possible future violation of loan covenants under existing loan agreements
      with our lenders;





•
            
            Fluctuations
      in the price and market for ethanol and distillers
  grains;





•
            
            Changes
      in plant production capacity, variations in actual ethanol and distillers
      grains production from expectations or technical difficulties in operating
      the plant;





•
            
            Availability
      and costs of products and raw materials, particularly corn and
      coal;





•
            
            Changes
      in our business strategy, capital improvements or development plans for
      expanding, maintaining or contracting our presence in the market in which
      we operate;





•
            
            Our
      ability to secure an agreement with our supplier for a proposed corn oil
      extraction operation;





•
            
            Costs
      of equipment;





•
            
            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;





•
            
            Our
      ability to distinguish ourselves from our current and future
      competition;





•
            
            Changes
      to infrastructure, including





•
            
            expansion
      of rail capacity,•
            
            possible
      future use of ethanol dedicated pipelines for
    transportation•
            
            increases
      in truck fleets capable of transporting ethanol within localized
      markets,•
            
            additional
      storage facilities for ethanol, expansion of refining and blending
      facilities to handle ethanol,•
            
            growth
      in service stations equipped to handle ethanol fuels,
  and•
            
            growth
      in the fleet of flexible fuel vehicles capable of using E85
      fuel;




1




•
            
            Changes
      in or elimination of governmental laws, tariffs, trade or other controls
      or enforcement practices such as:





•
            
            national,
      state or local energy policy;•
            
            federal
      ethanol tax incentives;•
            
            legislation
      mandating the use of ethanol or other oxygenate
  additives;•
            
            state
      and federal regulation restricting or banning the use of
    MTBE;•
            
            environmental
      laws and regulations that apply to our plant operations and their
      enforcement; or•
            
            reduction
      or elimination of tariffs on foreign
ethanol.





•
            
            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;





•
            
            Anticipated
      trends in our financial condition and results of
    operations;





•
            
            Ongoing
      disputes with our management consultant and design-build
      contractor;





•
            
            The
      availability and adequacy of our cash flow to meet our requirements,
      including the repayment of debt;





•
            
            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.





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.”




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, 2008, the Plant produced
approximately 54.8 million gallons of ethanol and approximately 103,000 tons of
dry distillers grains and 119,000 tons of wet distillers grains from
approximately 19.8 million bushels of corn.




General
Development of Business




During
2008 the Plant had a successful year operationally but suffered financially from
the rapid decline in the overall economy and specifically, the commodities
markets, that occurred during the last six months of 2008 and has continued in
2009.




In terms
of operations, the Plant produced 54.8 million gallons of ethanol –
approximately 110% of nameplate capacity.  Fiscal 2008 was the first
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.  The Plant maintained an excellent safety
record during 2008 with no lost time accidents recorded.




At
various times during 2008, the Plant asked for, and received, coal with slightly
different chemical compositions as we continue to try and meet the emissions
requirements of our air quality permits.  We have applied for a new
designation from the North Dakota Department of Health (“NDDH”) that would
increase the emissions limits relative to our current permits.  As of
March 15, 2009 we are still waiting for a decision from the NDDH on our request
to be reclassified to a different permit limit.  The Company has
maintained very close communication with the NDDH by submitting monthly update
reports explaining various trials with different coal quality to show the
Company’s best efforts to find a solution to meet certain emissions limits
within our air permit.  If we were to receive the new permit, we
believe the Plant would run in compliance with the new permit limits if it can
continue to receive coal with the correct chemical composition.  The
Plant was originally designed to run on lignite coal which is typically higher
in emissions than PRB coal.  Problems were encountered with running
the Plant on lignite during the first three to four months of operation in 2007
when a decision was made to switch to PRB coal.  Compliance with our
air quality permits while running the plant on lignite (higher emission
generating) coal was guaranteed by the general contractor that constructed the
Plant.  The Company withheld $3.9 million from the general contractor
until these issues have been resolved. An amount approximately equal to the
final payment 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.  We have been in contact with the general contractor on an
on-going basis regarding this issue but no progress was made in resolving the
issue during 2008 or as of March 2009.




2




The
Company installed a coal unloading facility adjacent to our Plant
site.  The coal unloading facility became operational in September
2008.  Since that time, the Company has seen a decrease in its coal
cost of approximately $10 per ton.  On an annual basis, this savings
should amount to approximately $900,000 to $1 million.




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 December 2008.  The third party is still in the final processes
of negotiating the financing and has received initial approval subject to
certain conditions.  As part of their financing arrangement,
significant changes were made to the original contract we signed in March
2008.  We are still negotiating certain aspects of the agreement with
the third party.  As of March 15, 2009, we do not know whether we will
be able to reach an agreement on the contract terms nor whether the third party
will be able to meet the conditions necessary for final approval of their
financing.




In an
effort to diversify our revenue stream even further, the Company explored and
continues to explore the possibility of selling the carbon dioxide (CO2)
generated by the ethanol production process.  Due to the collapse in
commodity prices in general and specifically oil prices during the last six
months of 2008, the Company was not successful in entering into an agreement to
sell its CO2.  We will continue to pursue avenues to sell our
CO2.




Financially
the Plant suffered during 2008 due to the collapse of the world economy and
commodities markets that occurred during the last six months of
2008.  In accordance with industry practice and, due to the location
of our Plant, we enter into fixed price contracts for corn to ensure the Plant
has an adequate supply to operate.  The Company reaped the benefits of
this practice during the first six months of 2008 as corn had been purchased
under fixed price contracts whose prices came to be significantly lower than
market prices as corn prices rose to record levels in June 2008.  The
Company continued to follow its practice of entering into fixed price contracts
during this time and, as corn prices declined from July – November, the market
price became significantly lower than the fixed prices on those
contracts.  For the period January 2008 – November 2008, ethanol
prices “tracked” the price of corn.  That is to say, as corn prices
increased or decreased, ethanol prices increased or decreased
accordingly.  Thus, when corn prices increased during the first six
months of 2008 and then declined over the last six months of 2008, ethanol
prices increased accordingly and then decreased accordingly.  As a
result, the Company had net income of approximately $7.8 million during the
first six months of 2008 but incurred net losses of approximately $13.2 million
over the last six months of 2008.  This resulted in a net loss for
2008 of $5.4 million.  Counter to traditional fundamentals, corn
prices rose during the month of December 2008 but ethanol prices did not rise
correspondingly.  This has further exacerbated the Company’s financial
situation as the difference between ethanol and corn prices has narrowed to the
point where the Company cannot operate at a positive cash flow under these
conditions.  Through March 2009 we have seen improvement in the
difference between ethanol and corn prices but still not enough for the plant to
operate at a positive cash flow.




The
losses sustained have put the Company in a difficult financial position and have
resulted in the Company violating certain of its loan covenants as of December
31, 2008.  The Company was notified on March 27, 2009 by its senior
lender, First National Bank of Omaha (“FNBO” or the “Bank”), that it was in
violation of certain loan covenants as of December 31, 2008 and that it has been
granted a waiver of those covenant violations.  Our projections show
that we will be in violation of certain of our loan covenants during
2009.  As a result of these projected covenant violations, which make
it reasonably likely that the Bank will be able to call our long-term debt due
and payable during 2009, we have reclassified all of our long-term debt to a
current liability on the balance sheet.  As part of our ongoing
communication with the Bank we have requested the Bank consider entering into a
forbearance agreement.  A forbearance agreement would typically allow
the Company to forgo principal payments for a period of time in exchange for an
increase in the interest rates on the associated debt along with requirements
for the Company to take certain actions and/or maintain or attain certain
financial milestones.  There is no certainty that we will be able to
reach agreement with the Bank on the terms of a forbearance agreement or that
the Bank will grant us waivers for future projected loan covenant
violations.  Due to the nature of these uncertainties and the current
negative margin structure in the market place, the Company’s ability to continue
as a going concern is uncertain.  As such, the Company may be forced
to cease operations, declare bankruptcy and/or surrender its assets to the
Bank.




The
Company has limited ability to raise new capital through either debt financing
or equity offerings and is currently exploring its options in this area to allow
the Plant to continue to operate.  The Company is also exploring
options to partner with all major stakeholders in an effort to maintain the
long-term viability of the Company.




The
ethanol industry as a whole was hurt by the collapse of the economy and
commodities markets.  As of March 15, 2009, estimates indicate that
approximately 2.2 billion gallons (roughly 20%) of domestic ethanol production
capacity was either shut down or operating at a reduced rate.  The
economic downturn has caused a decrease in demand for gasoline which has, in
turn, decreased demand for ethanol.  As of January 31, 2009, current
demand for ethanol is at an annualized rate of approximately 9.5 billion
gallons.  The amount of ethanol required to be blended for 2009 under
the Federal Renewable Fuels Standard is 10.5 billion gallons.  We
anticipate that, unless market conditions improve, more plants will shut down or
slow down which we believe should eventually lead to higher ethanol
prices.




3




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.




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.  Approximately 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 12.5 billion gallons as of January
2009.  A significant amount of new production capacity came on-line
during 2008 which has had the effect of creating an oversupply of ethanol in the
market place.  Due the economic downturn and resulting lower demand
for gasoline and less favorable blending economics for oil companies, the demand
for ethanol has decreased which has further increased the oversupply of
ethanol.




Revenue
from the sale of ethanol was approximately 84%, 88% and 0% of total revenues for
the years ended December 31, 2008, 2007 and 2006, 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 is approximately 60% DDGS and
40% DMWG.




Revenues
from sale of distillers grains was approximately 16%, 12% and 0% of total
revenues for the years ended December 31, 2008, 2007 and 2006,
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 dried distillers grains. We
market and sell our wet distillers grains internally.




4




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.  Effective as of January 1, 2008, we purchased an ownership
interest in RPMG.  Currently we own 8.33% of the outstanding capital
stock of RPMG and anticipate our ownership interest to be reduced as other
ethanol plants that utilize RPMG’s marketing services may become owners of
RPMG.  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.  We currently pay RPMG $.01 per
gallon for each gallon RPMG sells, per the terms of the
agreement.  This amount is being allocated with approximately 60%
going to pay off our ownership buy-in and 40% going to marketing
fees.  This fee is expected to decrease to approximately $.005 per
gallon once our ownership buy-in is complete, which we expect to occur during
2009.




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.  Through the marketing of CHS and our relationships with local
farmers, we are not dependent upon one or a limited number of customers for our
distillers grains sales.




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




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, 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




In an
effort to improve air quality in regions where carbon monoxide and ozone are a
problem, the Federal Oxygen Program of the Federal Clean Air Act requires the
sale of oxygenated motor fuels during the winter months in certain major
metropolitan areas to reduce carbon monoxide pollution. Gasoline that is blended
with ethanol has a higher oxygen content than gasoline that does not contain
ethanol.  Due to other ethanol use mandates, including the Federal
Renewable Fuels Standard (“RFS”) which requires a certain amount of ethanol be
used each year in the United States, the seasonal effect of the Clean Air Act
oxygenation requirement has been reduced.




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




During
2008, we were able to secure sufficient grain to operate the Plant and do not
anticipate any problems securing enough corn during 2009.  We do
anticipate that, due to poor growing conditions in our region, at least a
portion of the corn we procure will be at a lower quality.  We have
typically been able to procure corn that has been graded #2
Yellow.  During January 2009 we procured corn that was graded #3
Yellow.  Due to the lower starch content of this lower grade corn, we
have seen an approximate 3% decrease in our yield.  We are working
proactively to offset the decrease in yield through various modifications in our
production process.  The cost of lower grade corn can be significantly
cheaper (than #2 Yellow corn) and we believe we may be able to operate the plant
at a break even cash flow level using the offgrade corn.  The amount
of offgrade corn that is available will likely represent only a portion of our
overall corn needs.  While we cannot accurately predict the volume of
offgrade corn we will be able to procure nor the success of this strategy but we
believe that, in general, being able to procure some offgrade corn will have a
positive impact on our cash flow.




In
January 2009, the United States Department of Agriculture’s 2008 Crop
Production Summary listed national corn production at approximately
12.1 billion bushels, which is the second largest corn crop on
record.  North Dakota produced an estimated 285 million bushels
in 2008, which is a record. However, we expect the number of acres of corn
planted in North Dakota to decrease in 2009 primarily due to the higher prices
of other commodities grown in our state, including wheat, sunflowers and
soybeans.  We also expect the demand for corn grown in our area to
increase resulting fromnew ethanol plants in North Dakota that
became operational during 2008.  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.  While our surrounding area
produces a significant amount of corn, our profitability may be negatively
impacted if long-term corn prices remain high or continue to increase without a
corresponding increase in the price of ethanol.




5




Coal




Coal is
also an important input to our manufacturing process. During the fiscal year
ended December 31, 2008, we used approximately 97,600 tons of
coal.  During the startup period of January to April 2007, the Plant
experienced a number of shutdowns as a result of issues related to lignite coal
quality and delivery, as specified in our coal purchase agreement, along with
the performance of our coal combustor while running on lignite
coal.  As a result of these issues, we terminated our lignite coal
purchase and delivery contract and switched to PRB coal as an alternative to
lignite coal.  Since making the change, the Plant has not experienced
any shut-downs due to coal quality or delivery.  We have entered into
a two year agreement with Westmoreland Coal Sales Company (“Westmoreland”) to
supply PRB coal through 2009.  We have withheld $3.9 million from
Fagen, Inc. (“Fagen”), our design-build contractor, pending resolution of this
issue with the coal combustor.  As a long-term solution, we are
working with Fagen and its subcontractors to find ways to modify the coal
combustor so that we can switch back to using lignite coal and meet the
emissions requirements of our air quality permits.  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 12-31-07 and Production for the 12 months ended September 30,
2008 (in millions of tons)





State
            
            Estimated
      Reserves
            
            
            12
      month ProductionWyoming
            
            
            73,300
            
            
            
            465.17Montana
            
            
            12,510
            
            
            
            44.82North
      Dakota
            
            
            12,520
            
            
            
            29.43




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.  As of March 24, 2009, we were notified by
Westmoreland that a work stoppage has occurred at the mine from which we
normally receive coal.  We have enough coal on hand to operate our
Plant for approximately one month.  Westmoreland has more than one
mine from which we can purchase coal and we are actively communicating with them
to ensure we can receive shipments from another location if the work stoppage is
not resolved shortly.




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.




Electricity




The
production of ethanol is a very 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
electric usage has increased 18% for fiscal year 2009 as compared to 2008 and
2007.




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 2009 will be $2.54 per 1,000
gallons.  The rates for fiscal years 2008 and 2007 were $2.49 per
1,000 gallons and $2.45 per 1,000 gallons, respectively.




6




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. The RFS has been
accelerated to 9 billion gallons in 2008 and will increase to
36 billion gallons (15 billion gallons from corn based ethanol) by
2022.  The RFS calls for 10.5 billion gallons of corn based ethanol to
be blended in 2009.  As of January 2009, the ethanol industry in the
United States has an annual production capacity estimated at 12.6 billion
gallons which is greater than the amount needed to meet the 2009 RFS
requirements.  This oversupply has caused many plants to shutdown or
slow down (approximately 20% of production capacity is projected to be off-line
or slowed down) and has also had a negative impact on ethanol
prices.  If the supply continues to outweigh the demand for ethanol we
believe this will have a negative impact on our earningsand
our ability to continue to operate the Plant.




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. We expect the highway trust fund to add approximately $1.4 billion
to the highway trust fund revenue annually. In place of the exemption, the bill
creates a new volumetric ethanol excise tax credit of 5.1 cents per gallon (4.5
cents per gallon starting January 1, 2009) 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 is expected to allow 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.




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.




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 7 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 1,600 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.




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.




7




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.  Recently there have been 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. We believe we compete favorably with other ethanol producers due to our
proximity to coal supplies and multiple modes of transportation. In addition, we
believe our Plant’s location offers an advantage over other ethanol producers in
that it has ready access by rail to growing ethanol markets, which reduces our
cost of sales.




According
to the RFA, as of January 2009, the ethanol industry has grown to 172
production facilities in the United States.  There are 23 new plants
currently under construction along with 4 plant expansions.  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 more than 10.5
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 13 billion
gallons per year.  The largest ethanol producers include Archer Daniels
Midland, Aventine Renewable Energy, Inc., BioFuels Energy Corp, Hawkeye
Renewable, POET, The Andersons, Inc. and VeraSun Energy Corporation each of
which are capable of producing more ethanol than we produce.  However,
VeraSun recently filed for Chapter 11 Bankruptcy which may result in the sale of
some or all of VeraSun’s ethanol production facilities.  One of the other
large ethanol producers or an oil company may be in a position to purchase the
assets of VeraSun which could further consolidate the ethanol
industry.




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.




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.




8




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 27 million tons of distillers grains
were produced by ethanol plants in 2008. The amount of distillers grains
produced is expected to increase significantly 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. We have obtained all of the necessary permits to operate the
Plant.  In December 2007, we submitted an air pollution control Title
V permit application to the NDDH.  The application was deemed complete
by the NDDH in January 2008.  However, a revision to the application
may be required following the United States Environmental Protection Agency
(“EPA”) determination concerning the applicability of the best available control
technology program.  Although we have been successful in obtaining all
of the permits currently required, any retroactive change in environmental
regulations, either at the federal or state level, could require us to obtain
additional or new permits or spend considerable resources on complying with such
regulations.We expect to be subject to ongoing environmental
regulations and testing.




Emissions
compliance testing was performed at our Plant between June 6, 2007 and June 13,
2007, as well as on July 17, 2007. The emissions test results were submitted to
the NDDH on August 20, 2007 and noted that our Plant had not met the conditions
in our air permit for the DDGS Cooling Bag house and Boiler Common Stack for
Volatile Organic Compounds (“VOC”) and Particulate Matter (“PM”),
respectively.




Our Plant
also performed a 30 day emissions test from July 18, 2007 to August 16, 2007,
gathered by our Continuous Emissions Monitoring System (“CEMS”). The 30 day test
results were submitted to the NDDH on September 4, 2007 and noted that our Plant
had not met the conditions in our air permit for the Nitrogen Oxides (“NOx”)
emissions limit.




An Air
Pollution Control Permit To Construct Amendment application was submitted to the
NDDH on November 26, 2007 requesting changes to the air permit allowed under
Title 40 Code of Federal Regulations (“CFR”) Parts 52 and 70.  NDDH is
currently reviewing our submittal.  Upon approval of the conditions
requested in the amendment, we will be in compliance with all requirements of
the air permit.  Additionally, we were required to submit a complete
application for a Renewable Operating Permit per 40 CFR 70 within one year of
start-up of operations.  We fulfilled this requirement with a December
31, 2007 application submittal.  This application was deemed complete
by the NDDH on February 1, 2008.




9




Our Plant
performed emissions compliance testing again on August 13, 2008.  The
emissions test results were submitted to the NDDH on September 16, 2008 and
noted that, based on the emissions compliance test results, our Plant has not
met the conditions in our air permit for the Boiler Common Stack for
PM.  The emissions test results did verify that our Plant is in
compliance with the pending Air Pollution Control Permit to Construct Amendment
application that was submitted to the NDDH on November 26, 2007.




Our Plant
performed a Relative Accuracy Test Audit (“RATA”) on our CEMS between September
30, 2008 and October 31, 2008.  The test results were submitted to the
NDDH on November 11, 2008 and indicated that the CEMS equipment was operating
accurately.




Additionally,
the NDDH performed the annual Compliance Evaluation of our Plant on September
16, 2008.  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
with the current Permit to Operate, with exception of DDGS cooling (S01) VOC,
Boiler (S60) PM (filterable and condensable) and NOx.”  All three of
the exceptions listed in the findings will be in compliance
upon  approval of the pending Air Pollution Control Permit to
Construct Amendment application discussed above.




Additionally,
we worked with our design builders to make modifications and improvements to our
Plant’s emission control devices.  We found that these modifications
had been successful in reducing emissions levels and the final modifications
were installed during our normal maintenance shutdown which took place in April
2008.  With these modifications and the air pollution control permit
to construct amendment that was submitted on November 26, 2007, we expect our
Plant will be in compliance with all requirements in our air
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 result 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”). 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 do not
anticipate any capital expenditures for environment control facilities during
fiscal 2009 or 2010.  This could change if new federal or state
legislation is passed which imposes additional regulation on emissions typical
of our Plant.




Employees




We
presently have 38 full-time employees and two contract employees.  The
two contract employees are for the positions of President and CEO, Mick Miller,
and Plant manager, Edward Thomas, who are contracted to work with us by Greenway
Consulting, LLC, a Minnesota limited liability company (“Greenway”), our
management consultants.




Currently,
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 may continue
to violate the terms of our credit agreements and financial covenants which
could result in our lender demanding immediate repayment of our
loans.  We have been involved in discussions with our primary
lender, FNBO, regarding present and potential future loan covenant violations
that have resulted from current conditions in the ethanol industry and our
financial condition.  On March 27, 2009, we received notice from FNBO that
we were in violation of certain loan covenants as of December 31,
2008.  Also on March 27, 2009, FNBO granted us a waiver of those
covenant violations.  We anticipate that we will be in violation of
certain of our loan covenants during our 2009 fiscal year.  We are in
discussions with FNBO regarding this situation and are pursuing possible
modifications to our loan covenants and/or loan agreements (through a
forbearance agreement).  However, there is nothing in place at this
time and we may not be successful in negotiating revised terms that are
favorable to us.  If we violate the terms of our loan, our primary
lender could deem us in default of our loans and require us to immediately repay
the entire outstanding balance of our loans. If we do not have the funds
available to repay the loans or we cannot find another source of financing, FNBO
could seize our assets without compensation to the Company.




10




Our audit report
contains a going concern qualifier which may impede our access to normal trade
credit from our vendors.  Due to uncertainties disclosed in
Note 3 to our financial statements which are also disclosed in the “General
Development of Business” section above, our Company’s ability to continue as a
going concern may be uncertain.  While we believe that the forbearance
agreement we are currently negotiating with our Bank along with other cost
cutting and revenue enhancing measures we are implementing will allow us to
continue to operate, our vendors may not be willing to extend us normal trade
credit which could further impact our ability to survive as a going
concern.




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, 2008) than we
have, our projections, based on current market conditions, show that, in the
future, we may need additional financing.  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.  This could negatively impact the value of our
units.




Our member
control agreement contains restrictions that make it very difficult to raise
additional equity.  Our member control agreement requires that
we receive written consent from all of our members in order to sell additional
units in the Company unless we sell units in an intrastate
offering.  We have over 900 members which we believe would make it
difficult, if not impossible, to receive written consent from all
members.  This restriction imposes a limitation that makes it
difficult for the Company to sell units to raise needed capital and may
significantly harm the Company and value of your units.  We are
currently evaluating our member control agreement to eliminate this
restriction.




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.  During the period January 2008 through November 2008 the
spread between corn and ethanol prices remained fairly constant as ethanol
prices tended to increase or decrease in tandem with corn
prices.  However, this spread decreased during December 2008 as corn
prices rose by approximately $1 per bushel and ethanol prices did not
increase.  While we have seen some slight improvement in the spread
between corn and ethanol prices during January and February of 2009, the spread
has narrowed to the point where our Plant cannot maintain a positive cash flow
from operations.  Any further reduction in the spread between ethanol
and corn prices, whether as a result of higher corn prices or lower ethanol
prices, would adversely affect our results of operations and financial
condition.




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 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 seek to minimize the risks from fluctuations in the
prices of corn through the use of hedging instruments. The effectiveness of any
future hedging strategies is dependent upon the cost of corn, and our ability to
sell sufficient products to use all of the corn for which we have futures or
options contracts. 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
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. To manage our
ethanol price risk, we have entered into ethanol swaps.  In addition,
RPMG will 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 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 result in costs 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. We may incur such costs and they may be
significant.




11




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, 2009 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,
the coal combustor has not run consistently on lignite coal and we suffered
plant shut-downs during early 2007 as a result.  In addition, 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.  We are working with Fagen and its subcontractors on these
issues; however, there is no assurance that any potentially agreed upon solution
would solve the problems or solve the problems for $3.9 million or less.
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 distiller’s grain would significantly reduce our
revenues. The sales prices of ethanol and distiller’s 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.  Recently, the price of
ethanol and distiller’s grains have trended downward as the prices of corn and
gasoline have fallen.  We are dependant on a favorable spread between the
price we receive for our ethanol and distiller’s grains and the price we pay for
corn, coal and electricity.  Any continued lowering of ethanol and
distiller’s 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.  Based on financial forecasts performed by
our management, we anticipate that due to current ethanol and distiller’s grains
prices compared to the costs of the raw materials required to make them, the
Plant may operate unprofitably during the early part of our 2009 fiscal
year.  As a result, management decided to reduce production at the Plant in
January 2009.  We will use this opportunity to try and enhance Plant
efficiencies.  We anticipate continually evaluating the profitability of
operating the Plant and increasing or decreasing production by the Plant
accordingly.




The
average price we received for our ethanol and co-products, on a per gallon
basis, increased by approximately 16% during our 2008 fiscal year compared to
our 2007 fiscal year, however the price we paid for corn increased by
approximately 40% during the same time periods.  We anticipate the
price of ethanol and distiller’s grains to continue to be volatile during our
2009 fiscal year as a result of the net effect of changes in the price of
gasoline and corn and increased ethanol supply offset by increased ethanol
demand.  Continued declines in the prices we receive for our ethanol and
distiller’s grains will lead to decreased revenues and may result in our
inability to operate the Plant profitably for an extended period of time which
could decrease the value of our units.




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.  Coal prices are considerably
higher than the 10-year average, due to increased economic and industrial
activity in the United States and internationally, most notably China. We assume
that there will be continued volatility in the coal markets. Any ongoing
increases in the price of coal will increase our cost of production and may
negatively impact our future profit margins.




We currently buy
all of our coal from 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.  As of March 24, 2009, we were notified by
Westmoreland that a work stoppage has occurred at the mine from which we
normally receive coal.  We have enough coal on hand to operate our
Plant for approximately one month.  Westmoreland has more than one
mine from which we can purchase coal and we are actively communicating with them
to ensure we can receive shipments from another location if the work stoppage is
not resolved shortly.




12




We have a limited
operating history and our business may not be as successful as we
anticipate. We began our business in 2003 and commenced full production
of ethanol at our Plant in January 2007. Accordingly, we have a limited
operating history from which you can evaluate our business and prospects. Our
operating results could fluctuate significantly in the future as a result of a
variety of factors, including those discussed throughout these risk factors.
Many of these factors are outside our control. As a result of these factors, our
operating results may not be indicative of future operating results and you
should not rely on them as indications of our future performance. In addition,
our prospects must be considered in light of the risks and uncertainties
encountered by an early-stage company and in rapidly evolving markets, such as
the ethanol market, where supply and demand may change significantly in a short
amount of time. Some of these risks relate to our potential inability
to:





•
            
            effectively
      manage our business and operations;•
            
            recruit
      and retain key personnel;•
            
            successfully
      maintain our low-cost structure as we expand the scale of our
      business;•
            
            manage
      rapid growth in personnel and operations;•
            
            develop
      new products that complement our existing business; and•
            
            successfully
      address the other risks described throughout this Annual Report on Form
      10-K.




If we
cannot successfully address these risks, our business, future results of
operations and financial condition may be materially adversely affected, and we
may continue to incur operating losses in the future.




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. 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.




Moreover,
our Plant may not operate as planned or expected. Our Plant has a specified
nameplate capacity, which represents the production capacity specified in the
applicable Design-Build Contract.  During 2008, we successfully
operated our Plant at approximately 110% of nameplate
capacity.  However, in the event our Plant is not capable of operating
at its nameplate levels, our business, results of operations and financial
condition may be materially adversely affected.




Disruptions to
infrastructure, or in the supply of 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.




13




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.




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.




We are running
the Plant using PRB coal instead of lignite coal and may have to repay, at an
accelerated rate,  the lignite grant we received from the State of
North Dakota. We are currently using PRB coal instead of lignite
coal.  In 2006, we entered into a contract with the State of North
Dakota through its Industrial Commission (the “Commission”) for a lignite coal
grant not to exceed $350,000.  For the years ended December 31, 2007
and 2008, we did not meet the minimum lignite usage specified in the grant
contract.  Based on that information, we expect the Commission to
notify us that we will have to repay our grant at an accelerated rate of $35,000
per year for every year we do not meet the specified percentage of lignite use
as outlined in our grant.  This may have a negative impact on our
financial condition.




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, distillers grains and, in the future, corn oil. 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.




We may not be
financially able to install corn oil extraction equipment at our Plant
site.  We entered into a contract during March 2008 to operate
a third party’s corn oil extraction equipment that was to be installed at our
Plant site.  Due to the downturn in the economy and resulting global
economic crisis, the third party was not able to obtain financing for their
project.  Recently, they have entered into a financing arrangement
that is contingent upon completion of certain conditions.  As a result
of this new financing arrangement, the terms of our original contract have been
substantially modified.  We are currently negotiating some of the
terms of the contract with the third party but there is no guarantee they will
agree to the changes we have suggested.  In the event they do not
agree to the changes it is unlikely we would be able to obtain financing to
install the corn oil extraction equipment on our own.  While we
currently do not have any revenue from corn oil extraction, not being able to
install this equipment will hurt our effort to diversify our revenue stream and
may adversely impact the financial viability of our Plant.




We are seeking to
install corn oil equipment at our Plant. If we are successful, demand for the
corn oil produced at our Plant may decrease due to competition from other
extraction technologies or commodities.Due to the high
price of soybean oil, corn oil has recently become a viable alternative for
producing biodiesel.  We cannot be certain that this trend will
continue in the future which may decrease the demand for corn oil we expect
to produce at our Plant.  Other extraction technologies that are
more efficient or provide alternatives to corn oil may also evolve and decrease
the demand for corn oil we expect to produce at our
Plant.




Risks
Related to Conflicts of Interest




Our board of
governors has elected to withhold payment to Greenway for services provided
under the terms of the Management Agreement.  The Management
Agreement (“MA”) that is in place between our Company and Greenway calls for
annual payment of $200,000 plus 4% of the net income of the Plant to be paid on
a quarterly basis.  The MA does not specifically state whether the
payment related to 4% of the net income of the Plant is to be determined on a
quarterly basis or on an annual basis.  During 2008, we paid Greenway
based on our quarterly net income even though we ended the year at a net
loss.  Our governors feel the contract should be interpreted such that
the 4% of net income payment would be based on our annual net income and that we
should not have paid Greenway any funds during the year ended December 31,
2008.  As a result, the board has elected not to pay Greenway the
$200,000 annual payment starting in January 2009.  This could create
conflict between Greenway and our Company that may adversely affect Greenway’s
willingness to continue assisting the Company or could even result in Greenway
taking legal action against the Company to recover these funds.  We
cannot be sure of the result of any such potential lawsuit and if commenced, and
the Company is not successful, a financial award against the Company could have
an adverse material impact on our financial condition.




14




We may have
conflicting interests with Greenway that could cause Greenway to put its
interests ahead of ours. Greenway has and continues to advise our
governors and has been, and is expected to be, involved in substantially all
material aspects of operations. In addition, Mick Miller, our President and CEO,
and Edward Thomas, our Plant Manager, are employees of Greenway. 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 President and
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 President and 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.




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.




15




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 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,
debt retirement and possible Plant expansion or the construction of additional
plants. 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 units were
not valued based on any independent objective criteria, but rather by the amount
of funding required to build our Plant. For our North Dakota intrastate
offering and our initial seed capital round, we determined the offering price
per unit to be $1.00. This determination was based solely on the capitalization
requirements necessary to fund our construction and start-up activities. We did
not rely upon any independent valuation, book value or other valuation
criteria.  We do not place any value on the units.  Any
value is based on our bids received on our Qualified Matching Service,
independent from any determination by us.




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. Excess capacity in the ethanol industry would have an
adverse impact on our results of operations, cash flows and general financial
condition. Excess capacity may also result or intensify from increases in
production capacity coupled with insufficient demand. If the demand for ethanol
does not grow at the same pace as increases in supply, we would expect the price
for ethanol to decline. We believe that the disconnect that occurred between
corn and ethanol prices during December 2008 was due to an oversupply of ethanol
in the market place.  Demand for ethanol decreased during 2008 as
demand for gasoline decreased first, in response to record high oil and gas
prices that were present during 2008 and second, due to the global economic
crisis that started during the third quarter of 2008.  Because of this
oversupply and the resulting negative cash flow margins created by the decrease
in the spread between corn and ethanol prices, many plants have been forced to
shut down or operate at a reduced capacity.  Estimates show that
enough capacity has currently been idled to bring ethanol production capacity
more in line with current ethanol demand.  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.




We expect to
operate in a competitive industry and compete with larger, better-financed
entities, which could impact our ability to operate profitably. There is
significant competition among ethanol producers with numerous producer and
privately-owned ethanol plants planned and operating throughout the United
States. The number of ethanol plants being developed and constructed in the
United States continues to increase at a rapid pace. If the demand for ethanol
does not grow at the same pace as increases in supply, we expect that lower
prices for ethanol will result which may adversely affect our ability to
generate profits and our 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.




16




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.




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.




Negative media
attention associated with the use of corn in the ethanol production process may
lead to decreases in demand for the ethanol we produce which could negatively
affect our profitability.  Recent media attention associated with
the use of corn as the feedstock in ethanol production has been unfavorable to
the ethanol industry.  This negative media attention has focused on the
effect ethanol production has on domestic and foreign food prices.  While
some recent media reports have recognized that food prices have remained high
despite significant decreases in the price of corn following peaks in early
July 2008, some of this negative perception of ethanol production may
persist.  Ethanol production has previously received favorable coverage by
the news media which may have increased demand for ethanol.  This negative
perception of ethanol production may have a negative effect on demand for
ethanol which may decrease the price we receive for our ethanol.  Decreases
in the selling price of ethanol may have a negative effect on our financial
condition.




The expansion of
domestic ethanol production in combination with state bans on MTBE and/or state
renewable fuels standards may place strains on related infrastructure such that
our ethanol cannot be marketed and shipped to blending terminals that would
otherwise provide us the best cost advantages. If the volume of ethanol
shipments continues to increase and blenders switch from MTBE to ethanol, there
may be weaknesses in infrastructure such that our ethanol cannot reach its
target markets. Substantial development of infrastructure by persons and
entities outside our control will be required for our operations, and the
ethanol industry generally, to grow. Areas requiring expansion include, but are
not limited to:





•
            
            additional
      rail capacity to meet the expanding volume of ethanol
      shipments;•
            
            additional
      storage facilities for ethanol;•
            
            increases
      in truck fleets capable of transporting ethanol within localized
      markets;•
            
            expansion
      of and/or improvements to refining and blending facilities to handle
      ethanol instead of MTBE; and•
            
            growth
      in the fleet of flexible fuel vehicles capable of using higher blends of
      ethanol, up to 85% ethanol.




The
expansion of the above infrastructure may not occur on a timely basis, if at
all. Our operations could be adversely affected by infrastructure disruptions.
In addition, lack of or delay in infrastructure expansion may result in an
oversupply of ethanol on the market, which could depress ethanol prices and
negatively impact our financial performance.




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 recently
initiated the development a “low-carbon fuel standard” to reduce the carbon
intensity of transportation fuels used within the state.  Such a
standard is expected to be developed using 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 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.




17




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.




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 10.5 billion gallons of corn based ethanol to be produced
in 2009, 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.




An
important provision of the Energy Policy Act of 2005, that is still in effect,
involves an expansion of the small ethanol producer definition. Historically,
small ethanol producers were allowed a 10-cents per gallon production income tax
credit on up to 15 million gallons of production annually.  Under
the Energy Policy Act of 2005 the size limitation on the production capacity for
small ethanol producers increased from 30 million to 60 million
gallons.




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.




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 2008.




PART II




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




Market
Information




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.  The average price of all trades on the QMS that occurred during
the year ended December 31, 2008 was $1.19 per unit.  The average was
calculated based on a total of 451,000 units that were traded in ten separate
transactions during the year ended December 31, 2008.  During 2008,
the highest trade occurred at $1.30 per unit and the lowest trade occurred at
$1.00 per unit.  The average price of all trades on the QMS that
occurred during the year ended December 31, 2007 was $2.00 per
unit.  The average was calculated based on a total of 21,000 units
that were traded in five separate transactions during the year ended December
31, 2007.  During 2007, the highest trade occurred at $2.25 per unit
and the lowest trade occurred at $1.75 per unit.  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.  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.




18




Unit
Holders




As of
March 15, 2009, we had 40,188,973 Class A Membership Units outstanding and
a total of 947 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.  These units vest and will be issued
over a ten year term as stated in the agreements.  During the year
ended December 31, 2008, 15,000 units vested and were issued pursuant to the
terms of the equity based compensation agreements.




Distributions




We did
not make any distributions to our members for the fiscal years ended
December 31, 2008 or 2007. 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




During
December 2007, we exercised an option to purchase 200,000 units from a member
for use in employee compensation plans.  The only existing plans are
in place for our President and Plant Manager.  These plans provide for
the issuance of membership units pursuant to a 10-year vesting schedule with
full vesting occurring on July 1, 2015 and June 15, 2016,
respectively.




We did
not purchase any equity securities during the year ended December 31,
2008.




Unregistered
Sales of Equity Securities.




We did
not have any unregistered sales of equity securities during the year ended
December 31, 2008.




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.




We have
been involved in discussions with our primary lender, FNBO, regarding present
and future loan covenant violations that have resulted from current conditions
in the ethanol industry and our financial condition.  Due to
uncertainty regarding our ability to meet these covenants in the future, we have
classified this debt as a current liability as of December 31,
2008.  For more information about our financial condition, please see
“Item 7 – Management’s
Discussion and Analysis of Financial Condition and Results of Operation”
and Note 3 to the financial statements that appear elsewhere in this Annual
Report on Form 10-K.




19




Statement
      of Operations




For
      the year Ended December 31,
            
            2008
            
            2007
            
            2006
            
            
            2005
            
            
            2004Revenues,
      net of derivative loss
            
            
            $
            131,903,514
            
            
            $
            101,885,969
            
            
            $
            ―
            
            
            $
            ―
            
            
            $
            ―Cost
      of goods sold
            
            
            
            131,025,238
            
            
            
            87,013,208
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Gross
      margin
            
            
            
            878,276
            
            
            
            14,872,761
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―General
      and administrative expenses
            
            
            
            2,857,091
            
            
            
            3,214,002
            
            
            
            3,747,730
            
            
            
            2,087,808
            
            
            
            433,345Operting
      income (loss)
            
            
            
            (1,978,815
            )
            
            
            11,658,759
            
            
            
            (3,747,730
            )
            
            
            (2,087,808
            )
            
            
            (433,345
            )Interest
      expense
            
            
            
            6,013,299
            
            
            
            6,268,707
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―Other
      income, net
            
            
            
            2,625,542
            
            
            
            767,276
            
            
            
            1,243,667
            
            
            
            360,204
            
            
            
            147,004Net
      income (loss)
            
            
            $
            (5,366,572
            )
            
            $
            6,157,328
            
            
            $
            (2,504,063
            )
            
            $
            (1,727,604
            )
            
            $
            (286,341
            )Weighted
      average units - basic
            
            
            
            40,176,974
            
            
            
            40,371,238
            
            
            
            39,625,843
            
            
            
            24,393,980
            
            
            
            3,591,180Weighted
      average units - fully diluted
            
            
            
            40,226,974
            
            
            
            40,416,238
            
            
            
            39,650,843
            
            
            
            24,401,480
            
            
            
            3,591,180Net
      income (loss) per unit - basic
            
            
            $
            (0.13
            )
            
            $
            0.15
            
            
            $
            (0.06
            )
            
            $
            (0.07
            )
            
            $
            (0.08
            )Net
      income (loss) per unit - fully diluted
            
            
            $
            (0.13
            )
            
            $
            0.15
            
            
            $
            (0.06
            )
            
            $
            (0.07
            )
            
            $
            (0.08
            )




Balance
      Sheet Data
            
            2008
            
            2007
            
            2006Cash
      and equivalents
            
            
            $
            4,433,839
            
            
            $
            8,231,709
            
            
            $
            421,722Total
      current assets
            
            
            
            15,372,678
            
            
            
            25,733,307
            
            
            
            4,761,974Net
      property, plant and equipment
            
            
            
            78,010,042
            
            
            
            81,942,542
            
            
            
            84,039,740Total
      assets
            
            
            
            94,751,401
            
            
            
            108,524,254
            
            
            
            89,864,228Total
      current liabilities
            
            
            
            60,917,396
            
            
            
            16,807,461
            
            
            
            9,781,240Other
      noncurrent liabilities
            
            
            
            275,000
            
            
            
            275,000
            
            
            
            275,000Long-term
      debt
            
            
            
            ―
            
            
            
            52,538,310
            
            
            
            46,878,960Members'
      equity
            
            
            
            33,559,005
            
            
            
            38,903,483
            
            
            
            32,929,088Book
      value per weighted share
            
            
            $
            0.84
            
            
            $
            0.96
            
            
            $
            0.83




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, 2008, we produced
approximately 54.8 million gallons of ethanol (approximately 110% of name-plate
capacity).  We also produced approximately 103,000 tons of DDGS and
119,000 tons of DMWG.




While our
Plant operated consistently throughout the year, our financial performance was
severely impacted by unprecedented volatility in the commodities markets and the
collapse of the world economy and financial markets that started in August
2008.  Our results of operations and how this volatility impacted our
financial results are described in greater detail below.




20




Results
of Operations




Comparison
of Fiscal Years Ended December 31, 2008, 2007 and 2006




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, 2008, 2007 and
2006:






For
      the years ended December 31,
            
            2008
            
            
            2007
            
            
            2006Amount
            
            
            Percent
            
            
            Amount
            
            
            Percent
            
            
            Amount
            
            
            PercentRevenues,
      net of derivative loss
            
            $
            131,903,514
            
            
            
            100.00
            %
            
            $
            101,885,969
            
            
            
            100.00
            %
            
            $
            ―
            
            
            
            ―Cost
      of goods sold
            
            
            131,025,238
            
            
            
            99.33
            %
            
            
            87,013,208
            
            
            
            85.50
            %
            
            
            ―
            
            
            
            ―Gross
      margin
            
            $
            878,276
            
            
            
            0.67
            %
            
            $
            14,872,761
            
            
            
            14.50
            %
            
            $
            ―
            
            
            
            ―General
      and administrative expenses
            
            
            2,857,091
            
            
            
            2.17
            %
            
            
            3,214,002
            
            
            
            3.20
            %
            
            
            3,747,730
            
            
            
            ―Operating
      income (loss)
            
            $
            (1,978,815
            )
            
            
            -1.50
            %
            
            $
            11,658,759
            
            
            
            11.40
            %
            
            $
            (3,747,730
            )
            
            
            ―Interst
      expense
            
            $
            (6,013,299
            )
            
            
            -4.56
            %
            
            $
            (6,268,707
            )
            
            
            -6.20
            %
            
            $
            ―
            
            
            
            ―Other
      income (expense)Grant
      income
            
            
            73,207
            
            
            
            0.06
            %
            
            
            27,750
            
            
            
            0.00
            %
            
            
            ―
            
            
            
            ―Interest
      income
            
            
            426,233
            
            
            
            0.32
            %
            
            
            432,265
            
            
            
            0.40
            %
            
            
            182,277
            
            
            
            ―Other
      income
            
            
            2,126,102
            
            
            
            1.61
            %
            
            
            307,261
            
            
            
            0.30
            %
            
            
            1,061,390
            
            
            
            ―Net
      income (loss)
            
            $
            (5,366,572
            )
            
            
            -4.07
            %
            
            $
            6,157,328
            
            
            
            5.90
            %
            
            $
            (2,504,063
            )
            
            
            ―






Additional
      Data for the year ended December 31,
            
            2008
            
            
            2007Ethanol
      sold (thousands of gallons)
            
            
            55,148
            
            
            
            50,184Ethanol
      average sales price per gallon (net of hedging activity)
            
            $
            2.01
            
            
            $
            1.82Dried
      distillers grains average sales price per gallon of ethanol
      sold
            
            $
            0.25
            
            
            $
            0.24Corn
      costs per gallon of ethanol sold (net of hedging activity)
            
            $
            1.97
            
            
            $
            1.37Corn
      costs per bushel (net of hedging activity)
            
            $
            5.19
            
            
            $
            3.78




Revenues




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/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 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.  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 ranged from $50
      to $75 per ton with our average selling price for the year being
      approximately $56 per ton.  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.  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.




2007
compared to 2006




We began
producing and selling ethanol and distillers grains in January
2007.  We had no sales or revenues for the fiscal year ended
December 31, 2006.




•
            Total
      revenue for 2007 was approximately $101.9 million.  Ethanol and
      distillers grains represented 88% and 12% of revenue,
      respectively.




•
            Ethanol
      – Prices received by us for ethanol during 2007 ranged from $1.57 to $2.04
      per gallon.  Prices peaked in March at $2.04 per gallon and then
      slowly declined until October 2007 when prices dipped to $1.57 per
      gallon.  Prices improved in November and December to $1.76 per
      gallon and $2.01 per gallon,
respectively.




21




•
            Distillers
      grains – Our 2007 distillers grain sales volumes were roughly split 50-50
      between DDGS and DMWG.  Prices received by us for DDGS ranged
      from $80 to $100 per ton during 2007 with our average selling price for
      the year being approximately $87 per ton.  The price steadily
      increased during the last half of 2007 as corn prices started to
      increase.  Prices received by us for DMWG ranged from $35 to $53
      per ton with our average selling price for the year being approximately
      $40 per ton.




•
            During
      the fourth quarter of 2007, we started to use ethanol derivative
      instruments in an effort to lock in a margin on a portion of our
      production relative to corn that we have purchased under
      contract.  We recognize any gains or losses that result from the
      change in value of our ethanol derivative instruments in revenue as the
      changes occur.  During 2007, we recognized a loss of
      approximately $2 million in revenue related to the change in value of our
      ethanol derivative instruments as ethanol prices rose above the prices we
      had locked in with our ethanol
swaps.




Prospective
Information:




•
            Ethanol
      – ethanol prices have remained relatively constant during the January and
      February of 2009.  We anticipate that ethanol prices will
      continue to increase or decrease with the price of corn, gasoline and
      crude oil.  There has been a significant decrease in demand for
      both oil and gas but we believe that production cuts for both of those
      products may increase their respective prices during 2009.  We
      believe this, along with a decrease in supply of ethanol due to plant
      shutdowns and slow downs, will have a positive impact on ethanol prices
      later in 2009 but we cannot be certain of how the price of ethanol will
      change, as it is a market driven
commodity.




•
            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.




•
            Corn
      Oil Extraction – we are currently negotiating the terms of an agreement to
      add corn oil extraction equipment to our facility.  At this time
      we are not certain whether we will be able to reach agreement with the
      counter party to the agreement.  If we do reach an agreement, we
      project that the equipment will be operational during the third quarter of
      2009.




Cost
of Goods Sold and Gross Margin




Our gross margin is very
sensitive to fluctuations in the spread between ethanol and corn
prices.  From January 2008 – November 2008, ethanol prices generally
increased and decreased with the price of corn, maintaining a spread between the
prices of the two commodities that would have allowed our Plant to maintain at
least a positive cash flow if we would have purchased corn and sold ethanol at
the average market prices for those months.  During December 2008,
corn prices increased without a corresponding increase in the price of ethanol
causing the spread between ethanol and corn prices to narrow to the point where
our Plant could not maintain a positive cash flow.  While the spread
has improved slightly during January and February 2009, we are still operating
at a negative cash flow.  If the spread between corn and ethanol
prices does not improve to the point where our Plant can operate at a positive
cash flow, we may be forced to shut down and this may adversely impact our
ability to continue as a going concern.




2008
compared to 2007




Our gross
margin for 2008 was approximately $900,000.  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 the year 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 $3.7 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.




•
            Partially
      offsetting the increase in corn costs were gains recognized from our corn
      hedging activities of approximately $5.9 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.




22




2007
Cost of Goods Sold:




•
            Total
      cost of goods sold for 2007 was approximately $87 million or 85.5% as a
      percentage of sales.  Our gross margin for 2007 was
      approximately $14.9 million.  Purchases of corn represented 78%
      of the total cost of goods sold.




•
            We
      use corn derivative instruments in an effort to lock in a margin on a
      portion of our production relative to ethanol prices.  We
      recognize any gains or losses that result from the change in value of our
      corn derivative instruments in cost of goods sold as the changes
      occur.  During 2007, we recognized a gain of approximately $3
      million that offset our cost of corn in cost of goods sold.  As
      the price of corn fluctuates, the value of our corn derivative instruments
      are impacted, which affects our financial
  performance.




Prospective
Information:




•
            Corn
      –  corn prices have remained fairly constant during January and
      February 2009.  We cannot be certain how the price of corn will
      change as it is a market driven commodity.  At the end of 2008
      we reorganized our corn procurement strategy and are focused on building
      relationships with and purchasing more of our corn needs from local
      farmers.  We believe this will have a positive impact on our
      gross margin as corn purchased from farmers is typically lower priced than
      corn purchased via unit trains.  We anticipate that we will
      continue to contract with local farmers but will not contract as far out
      into the future as we have in the past.  As our working capital
      position allows, we also intend to use corn derivative instruments to
      hedge a portion of our corn needs.




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




•
            Coal
      – we have a contract in place through the end of 2009 for coal
      supply.  We anticipate entering in to a new contract this year
      with similar terms to what we had in the past.  Our current two
      year agreement allowed for a small per ton increase in the second
      year.  We anticipate that our coal costs, including freight and
      unloading costs, will be lower than 2008 due to the successful
      implementation of our coal unloading facility during September
      2008.  During the fourth quarter of 2008, our coal costs
      averaged approximately $10 per ton less than the first three
      quarters.  We expect to maintain this cost savings throughout
      2009.




•
            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 18% in 2009
      compared to 2008 rates.




•
            Chemicals
      – we have contracts in place for our chemical supply needs.  The
      contracts call for competitive market pricing.  We anticipate
      that our chemical costs will be lower than 2008 due to decreasing prices
      for some of our main chemicals as world wide demand has decreased due to
      the global economic slow down.  As we have fine tuned our
      production process we have also lowered our usage of certain chemicals due
      to requesting coal of a certain chemical makeup from our coal supplier in
      addition to other process related changes.  The corresponding
      reduction in chemical usage has decreased our chemical
      costs.  We anticipate our costs to continue to be lower as long
      as our coal supplier is able to provide coal with requisite chemical
      makeup.


•


•
            Labor
      costs – due to our current financial situation, we temporarily suspended
      our employee bonus program during the fourth quarter of
      2008.  We also eliminated management bonuses for the year ended
      December 31, 2008.  If our financial condition does not improve,
      we anticipate that our labor costs will be slightly lower during 2009 as
      our bonus programs will not be reinstated until we see improvement
      financially.




General
and Administrative Expenses




2008
compared to 2007




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




•
            A
      decrease of approximately $594,000 in professional service fees (including
      legal, 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.




•
            An
      increase in accounting fees of approximately $60,000 primarily related to
      additional audit costs associated with our first full year of operation
      along with additional travel costs as we had our audit firm travel to our
      site for our quarterly reviews during
2008.




2007
compared to 2006




General
and administrative expenses decreased approximately $534,000 (14.2%) primarily
due to:




•
            $1.1
      million of start up costs in 2006.  These costs were related to
      the purchase of plant supplies and other start up costs that were
      allocated to general and administrative expense during 2006 because our
      Plant was not yet operational.  Similar expenses may have been
      incurred during 2007 but would have been included in cost of goods
      sold.




23




•
            $550,000
      of pre-production payroll expenses that were charged to general and
      administrative expense in 2006 because the Plant was not yet
      operational.  Similar expenses incurred during 2007 are shown in
      cost of goods sold.




Partially
offsetting the decreases were:




•
            Approximately
      $1.1 million of increased general and administrative expenses related to
      the administration and management of the Plant during its first full year
      of operation.




Prospective
Information:




•
            We
      anticipate our general and administrative expenses for 2009 to be similar
      to 2008.  We are scheduled to have an increase in our real
      estate taxes of approximately $157,000 as we enter the second year of the
      phase out of our tax exemption.  We have requested a full
      exemption of our real estate taxes due to the financial difficulties
      facing our Plant but were turned down. We are planning to continue to
      communicate with local real estate tax commission but cannot be certain of
      the outcome.  We anticipate continuing to decrease our reliance
      on outside consultants as we continue to transition more duties to our
      employees but we cannot be certain that these goals will be met due to our
      changing business climate.




Interest
Expense




Our
interest costs for the fiscal years ended December 31, 2008 and 2007 were
approximately $6.0 million and $6.3 million, respectively.  We
incurred interest costs of approximately $1.5 million during the fiscal year
ended December 31, 2006 which was related to plant construction and capitalized
accordingly.




•
            2008
      interest expense – includes approximately $4.0 million of interest expense
      on our long-term debt, a loss of approximately $1.8 million related to the
      change in market value of our interest rate swaps and approximately
      $200,000 of expense related to amortization of our capitalized financing
      costs.  Interest costs on our long-term debt were lower in 2008
      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 earlier in the year.  The change
      in the market value of our interest rate swaps was higher than 2007 as
      interest rates reached record low levels toward the end of 2008 causing
      the value of our swaps to decline.




•
            2007
      interest expense - includes approximately $5.1 million of interest expense
      on our long-term debt, approximately $933,000 of losses related to the
      change in value of our interest rate swaps and approximately $214,000 of
      expense related to amortization of our capitalized financing
      costs.




•
            2006
      interest expense – we had approximately $1.5 million of interest expense
      on our long-term debt during 2006 all of which was related to plant
      construction and capitalized
accordingly.




Interest
rates trended downward for much of 2008 which caused the value of our interest
rate swaps to decrease.  As interest rates reached record low levels
at the end of 2008 we do not anticipate that they will continue to
decrease.  Rates did increase slightly in January 2009.  We
do not feel we can accurately predict interest rates for the rest of 2009 as it
remains to be seen what impact the government attempts to stimulate the global
economy worldwide will have on interest rates.  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.




Other
Income and Expense




Other
income includes payments from our state ethanol incentive program, interest
income and grant income.  Other income, net was approximately $2.6
million, $800,000, and $1.2 million for the fiscal years ended December 31,
2008, 2007 and 2006, respectively.




During
2008, conditions were met that triggered payments to be made under the state of
North Dakota’s ethanol incentive program.  We received approximately
$2.1 million under this program during 2008.  We did not receive any
payments during the years ended December 31, 2007 or 2006,
respectively.  The program ran out of funds at the end of 2008 and
will not be funded again until June 2009.  We cannot accurately
predict how much we may receive from this program in the future but anticipate
that it will most likely be significantly less than the amount received in 2008
and could ultimately be $0.




Interest
income was approximately $426,000, $432,000 and $182,000 for the fiscal years
ended December 31, 2008, 2007 and 2006, respectively.




•
            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.




24




•
            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.




•
            2006
      interest income – primarily from holding funds raised from members in
      money market accounts.




Approximately
60% of the requested sales and use tax refund was denied by the state of North
Dakota due to improper documentation.  Our general contractor is
working on supplying the appropriate information so the refund can be
processed.  If we were to receive the remaining portion of the refund
we anticipate that our interest income would be similar to the amount received
in 2008.  We cannot accurately predict the amount of the refund and
corresponding interest income that will be received.  We do anticipate
receiving interest income on the cash set aside to pay our general contractor
for the final construction costs but feel the amount will not be
material.




Because
we had not yet started the production and sale of ethanol, gains
(losses) derived from our corn derivative instruments and changes in the
value of our interest rate swap were recorded in the other income and expense
section for years prior to 2007.  Starting in 2007, we recorded gains
(losses) associated with our corn derivative instruments in cost of goods sold,
the gains (losses) associated with our ethanol derivative instruments in revenue
and we recorded the change in the value of our interest rate swap in interest
expense.  For the fiscal year ended December 31, 2006 changes in
the value of our interest rate swap resulted in a gain of approximately
$167,000, and we also recognized a gain from changes in the market value of our
corn derivative instruments of approximately $894,000.




Grant
income was approximately $73,000, $27,750, and $0 for the fiscal years ended
December 31, 2008, 2007 and 2006, respectively.  We do not anticipate
receiving any significant grant income during 2009.




Plant
Operations




Operations
of Ethanol Plant




We
produced approximately 54.8 million gallons in 2008 which is approximately 110%
of name-plate capacity.  At various times during 2009 we have 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
current market conditions, we expect to have negative cash from cash flow
generated by continuing operations.  At this time, we cannot be
certain that we have enough available capital, which consists of current lines
of credit through our revolving promissory note and cash reserves, to cover our
usual operating costs over the next twelve months, which consist primarily of
corn supply, coal supply, water supply, staffing, office, audit, legal,
compliance, working capital costs and debt service obligations.  Our
projections show that we could possibly run out of available capital within the
first two months of 2010.  We are currently in discussions with our
bank regarding our options for obtaining additional capital whether it be
through restructuring our long-term debt, raising capital from our membership,
pursuing a private equity partner or possibly partnering with our corn suppliers
to help the plant cash flow.  Other cost containment measures and
marketing strategies are under evaluation and implementation in an effort to
improve our projected cash flow and profitability.




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




We
account for derivative instruments and hedging activities in accordance with
Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting
for Derivative Instruments and Hedging Activities, as amended (“SFAS No.
133”). SFAS No. 133 requires a company to evaluate its contracts to
determine whether the contracts are derivatives. Certain contracts that
literally meet the definition of a derivative may be exempted from SFAS
No. 133 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. Contracts that meet the requirements of normal are
documented as normal and exempted from accounting and reporting requirements of
SFAS No. 133.




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.
The fair value of the derivatives is continually subject to change due to the
changing market conditions. 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 a hedge. 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.




25




Inventory




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. These assumptions could change in the near term.




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, equipment and investments, 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,
            
            2008
            
            
            2007
            
            
            2006Cash
      flows from (used in) operating activities
            
            $
            8,495,564
            
            
            $
            2,684,633
            
            
            $
            (7,662,308
            )Cash
      flows used in investing activities
            
            
            (2,300,195
            )
            
            
            (3,974,839
            )
            
            
            (66,903,860
            )Cash
      flows from financing activities
            
            
            (9,993,239
            )
            
            
            9,100,193
            
            
            
            55,944,079




Cash
flows




Operating
activities.




Typically
our net income or loss before depreciation, amortization and certain other
noncash charges was 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.




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 (including
      the change in value of derivative instruments) of approximately $15.5
      million.  This change is primarily the result
  of:




•
            A
      net decrease in cash flow from working capital items during 2007 as the
      Plant started operations.  All 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  $10.3
      million.  At December 31, 2008, the change in the balance of our
      working capital items resulted in a positive cash flow of approximately
      $5.2 million - primarily as a result of the
  following:




•
            Our
      receivable balances were lower by approximately $3.2 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
      market value of our derivative instruments was lower by approximately $2.7
      million as our risk management committee had reduced our hedging position
      in response to the uncertain market
conditions.




•
            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.




26




•
            A
      net increase in various non-cash charges of approximately $2 million
      primarily related to an increase in the change in the accrual for losses
      on firm purchase commitments of approximately $1.4 million along with an
      increase in the change in market value of our interest rates swaps of
      approximately $400,000.




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.




2007
Compared to 2006




Cash
flows provided by operating activities in 2007 increased $10.3 million from the
comparable prior period, as a result of:




•
            Increased
      net income of $8.7 million, due to the Plant becoming operational in
      2007;




•
            Increased
      depreciation expense of $5.7 million, due to the Plant becoming
      operational in 2007; and




•
            Increased
      amortization expense and changes in the market value of our interest rate
      swap that added $1.4 million.




Partially
offsetting the increase in cash flows from operating activities
were:




•
            A
      net increase in cash flow use of $5.5 million from changes in working
      capital items related to the Plant becoming operational in
      2007.  Current assets such as inventory, accounts receivable and
      the change in market value of our corn and ethanol derivative instruments
      increased more than our current liabilities during
  2007.




Investing
activities.




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.




Cash
flows used in investing activities in 2007 decreased $62.9 million compared to
the comparable prior period, the result of lower capital expenditures in 2007
due to Plant construction being substantially complete at the end of
2006.




Financing
activities.




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 issued
approximately $9.3 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.




Cash
flows provided by financing activities in 2007 decreased $46.8 million compared
to the comparable prior period, primarily the result of:




•
            A
      decrease in the issuance of long-term debt of $38.6
    million;




•
            A
      decrease in member contributions of $6.7 million due to the closing of the
      equity drive during 2006; and




•
            Higher
      debt repayments of $1.8 million as we commenced debt service in
      2007.




Capital
Expenditures




We
incurred significant capital expenditures in 2006 and 2007 during Plant
construction.  We also had one major capital expenditure project
during 2008 related to the construction of a coal unloading facility on our
site.  The coal unloading facility became operational in September
2008 and thus far, is meeting our cost savings expectations.  Since
the coal unloading facility became operational, our average coal costs have
declined by approximately $10 per ton.  This will yield an approximate
$1 million annual cost savings.  For 2009 we do not have any major
capital expenditures planned due to current market conditions and our limited
ability to raise additional capital and/or borrow additional funds.




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;




27




•
            
            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.




We have
been notified by FNBO that we were in violation of certain of the covenants in
our loan agreements at December 31, 2008.  These include the covenants
requiring a minimum working capital balance, minimum net worth and a minimum
fixed charge coverage ratio.  The Company has been granted a waiver of
these violations by the Bank.  For further information please see the
discussion in Item 1. Business labeled “General Development of
Business”




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.




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.




As of
February 2009, our Plant, and we believe, many other plants in the ethanol
industry, are operating in a negative cash flow environment.  We
anticipate that, if margins do not improve, we may need to raise additional
capital to meet our operating cash flows during 2009.  As of February
2009, we had available capital (cash plus borrowing capacity) of approximately
$9.8 million.  This included $6 million of cash on hand, $1 million of
capacity available under our Long-Term Revolving Note and $3.5 million of
capacity under our Line of Credit.  Our available capital does not
include $4.2 million that has been aside in conjunction with amounts withheld
from Fagen as described earlier in this document.  Under current
market conditions we anticipate that we will have available capital to operate
our business through the end of 2009 but that the level of available capital
that we have left may be insufficient to sustain operations through the first
quarter of 2010.  If we continue to violate our loan covenants, it is
possible that, in the future, the Bank may limit our access to the available
lines of credit mentioned above.  We are evaluating, on an on-going
basis, the capacity at which to operate our Plant, including possibly shutting
down until margins improve.  At this time, we believe that operating
our Plant, even at a reduced rate, is a more favorable option than shutting
down.




We have a
limited capacity to borrow additional funds due to the collateral position of
FNBO.  We also have a limited ability to raise additional capital
through an equity offering due to language in our Member Control Agreement that
limits issuing additional units without the written consent of all
members.  We have been proactively discussing these items with FNBO
and are working with them to find a solution for our Plant.




The
construction loan agreement contains incentive pricing language whereby we are
eligible for lower interest rates if it meets certain financial
criteria.  During July 2008, we did qualify for incentive pricing
which decreased the interest rate on some of our debt (as noted below) by
..15%.  Because we are no longer meeting the necessary financial
criteria, our rates will return to the regular pricing schedule in April
2009.




Short-Term
Debt Sources




We have a
revolving promissory note of up to $3,500,000 with the Bank through July 5,
2009, subject to certain borrowing base limitations.  Interest is
payable quarterly and charged on all borrowings at a rate of 3.4% over the
one-month LIBOR.  The interest rate is subject to an incentive pricing
clause where the Company will be charged a lower rate if it meets certain
financial criteria.  As of July 2008, the Company had qualified for
the incentive pricing.  As such, interest on the Variable Rate Note is
being charged at 3.25% over the one-month LIBOR.  As of February 17,
2009, the rate was 3.70%.  We had no outstanding borrowings on the
revolving promissory note as of December 31, 2008, 2007 and
2006.  Under current market conditions, we anticipate that we will
need to borrow from this facility during 2009 to fund our
operations.




Long-Term
Debt Sources




We have
four long-term notes in place with the Bank (collectively the “Term Notes”) as
of December 31, 2008.  The loan agreements are secured by
substantially all of the Company’s assets.  Three of the Term Notes
were established in conjunction with the termination of the original
construction loan agreement on April 16, 2007.  The fourth Term Note
was entered into during December 2007 (the “December 2007 Fixed Rate Note”) when
we 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 us to maintain certain financial ratios and meet certain
non-financial covenants.  Each Term Note has specific interest rates
and terms as described below.




Fixed
Rate Note – The fixed rate note (the “Fixed Rate Note”) had a balance of
$24.7 million outstanding at December 31, 2008.  Interest payments are
made on a quarterly basis with interest charged at 3.0% over the three-month
LIBOR rate.  The interest rate is reset on a quarterly
basis.  As of January 16, 2009, the rate was
4.0825%.  Principal payments are to be made quarterly according to
repayment terms of the construction loan agreement, generally beginning at
approximately $520,000 and increasing to $653,000 per quarter, from January 2009
to January 2012, with a final principal payment of approximately $17.3 million
at April 2012.




28




Variable
Rate Note – During December 2007, $10
million of the variable rate note (the “Variable Rate Note”) was transferred to
the December 2007 Fixed Rate Note as part of the 4thamendment to
the loan agreement.  The Variable Rate Note had a balance of $3
million at December 31, 2008.  Interest payments are made on a
quarterly basis with interest charged at 3.4% over the three-month LIBOR
rate.  The interest rate is subject to an incentive pricing clause
where the Company will be charged a lower rate if it meets certain financial
criteria.  As of July 2008, the Company had qualified for the
incentive pricing.  As such, interest on the Variable Rate Note is
being charged at 3.25% over the three-month LIBOR.  The interest rate
is reset on a quarterly basis.  As of January 16, 2009, the rate was
4.3325%.  Principal payments are made quarterly according to the terms
of the construction loan agreement as amended by the fourth amendment to the
construction loan agreement.  The amendment calls for quarterly
payments of $634,700 applied first to interest on the long-term revolving note
(the “Long-Term Revolving Note”), next to accrued interest on the Variable Rate
Note and finally to principal on the Variable Rate Note.  Based on the
interest rate noted above we estimate that the remaining Variable Rate Note will
be paid off in April 2010.  We anticipate the principal payments to be
approximately $550,000 per quarter with a final payment of approximately
$320,000 in April 2010.




Long-Term
Revolving Note - The long-term revolving note (the “Long-Term Revolving
Note”) has a capacity of $10 million.  This note had a balance of $6.4
million at December 31, 2008.  During January 2009, we borrowed an
additional $2.5 million on this note which brought the available capacity to
approximately $1 million.  Based on current interest rates and the
anticipated pay off date of the Variable Rate Note, we expect scheduled
principal payments to start being applied to this note in April
2010.  The payments will range from approximately $540,000 to
$576,000.  We anticipate a final payment of approximately $4.9 million
in April 2012.  Interest is charged at 3.4% over the one-month LIBOR
rate with payments due quarterly. The interest rate is subject to an incentive
pricing clause where the Company will be charged a lower rate if it meets
certain financial criteria.  As of July 2008, the Company had
qualified for the incentive pricing.  As such, interest on the
Long-Term Revolving Note is being charged at 3.25% over the one-month
LIBOR.  The interest rate is reset monthly.  As of February
17, 2009, the rate was
3.705%.




December
2007 Fixed Rate Note – The December 2007 Fixed Rate Note was created by
the fourth amendment to the construction loan agreement as noted
above.  This note had a balance of $9.2 million as of December 31,
2008.  Interest payments are made on a quarterly basis with interest
charged at 3.4% over the three-month LIBOR rate.  The interest rate is
reset on a quarterly basis.  As of January 16, 2009, the rate was
4.4825%.  Principal payments are to be made quarterly according to
repayment terms of the construction loan agreement, generally beginning at
approximately $191,000 and increasing to $242,000 per quarter, from January 2009
to January 2012, with a final principal payment of approximately $6,334,000 at
April 2012.




All unpaid amounts on the Term Notes are due and payable in
April 2012.  As previously discussed in this document
(see Item 1. Business – “General Development of Business”) the
interest rates and payment amounts of the Term Notes may be impacted by the
forbearance agreement currently being negotiated with the Bank.




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 as a gain or
loss from non-designated hedging activities in other income and expense during
2006 and are shown in interest expense in 2007 and 2008.




For the
fiscal years ending December 31, 2008, 2007 and 2006 there were settlements
of approximately $449,000, $39,000 and $0, respectively and market value
adjustments resulting in a gains/(losses) of approximately $(1.8 million),
$(933,000) and $167,000, respectively.




Letters
of Credit




The
construction loan agreement provides for up to $1,000,000 in letters of credit
with the Bank to be used for any future line of credit requested by a supplier
to the Plant. All letters of credit are due and payable at April
2012.  The construction loan agreement provides for us to pay a
quarterly commitment fee of 2.25% of all outstanding letters of credit. In
addition, as of December 31, 2008, we have one outstanding letter of credit
for $137,000 for capital expenditures for gas services with Montana-Dakota
Utilities Co.




Subordinated
Debt




As part
of the construction loan agreement, we 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 (a total of 6.3325% at January 16, 2009) and is
due and payable subject to approval by the senior lender, the Bank. Interest is
compounded quarterly. Amounts will be due and payable in full in
April 2012. As of December 31, 2008, the outstanding amounts on these
loans was $5,525,000.




29




Contractual
Obligations and Commercial Commitments




We have
the following contractual obligations as of December 31, 2008:


Contractual
      Obligations
              
              Total
              
              
              Less
      than 1 Yr
              
              
              1-3
      Years
              
              
              3-5
      Years
              
              
              More
      than 5 YrsLong-term
      debt obligations *
              
              $
              61,562,230
              
              
              $
              8,443,950
              
              
              $
              16,706,998
              
              
              $
              36,411,282
              
              
              $
              ―Capital
      leases
              
              
              108,335
              
              
              
              61,701
              
              
              
              46,634
              
              
              
              ―
              
              
              
              ―Operating
      lease obligations
              
              
              1,900,725
              
              
              
              489,660
              
              
              
              959,965
              
              
              
              451,100
              
              
              
              ―Corn
      Purchases **
              
              
              18,871,000
              
              
              
              18,871,000
              
              
              
              ―
              
              
              
              ―
              
              
              
              ―Coal
      purchases
              
              
              1,288,800
              
              
              
              1,288,800
              
              
              
              ―
              
              
              
              ―
              
              
              
              ―Water
      purchases
              
              
              3,187,200
              
              
              
              398,400
              
              
              
              796,800
              
              
              
              796,800
              
              
              
              1,195,200Total
              
              $
              86,918,290
              
              
              $
              29,553,511
              
              
              $
              18,510,397
              
              
              $
              37,659,182
              
              
              $
              1,195,200




* -
Amounts determined assuming current interest rates as disclosed above in the
“Long-Term
Debt Sources” section for the Long-Term Revolving Note and Variable Rate
Note.  Used the rates fixed in the interest rate swap agreements (see
“Interest
Rate Swap Agreements” section above) for the Fixed Rate Note and December
2007 Fixed Rate Note, respectively in order to account for possible net cash
settlements on the interest rate swaps.  Although the outstanding
balance of the Term Notes have been reclassified as current on our balance
sheet, this schedule reflects the scheduled maturities of our
debt.  While we cannot be certain that the Bank will not call our debt
if we continue to violate our loan covenants, we do not currently anticipate
paying all of this debt during the next 12 months.  Also assumed
permanent repayment of $1 million in unscheduled principal payments applied to
the Long-Term Revolving Note as we cannot accurately anticipate when these funds
will be needed although we believe we will need them in the future to fund
operations based on current market conditions.  If we do need to issue
these funds for operations, our long-term debt obligations will increase
accordingly with interest computed at the rates stated above.




** -
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, 2008 for basis contracts that had not yet been fixed.




Due to
the nature of the agreement being negotiated, there are no commitments
associated with our corn oil extraction agreement.




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.  In order
to receive the proceeds, we were required to build a 50 MMGY ethanol plant
located in North Dakota that utilizes clean lignite coal technologies in the
production of ethanol.  We also had to provide the Commission with
specific reports in order to receive the funds including a final report (the
“Final Report”) six months after ethanol production began.  After the
first year of operation, we will be required to repay a portion of the proceeds
in annual payments of $22,000 over ten years.  The payments could
increase based on the amount of lignite coal we are using as a percentage of
primary fuel.  We received $275,000 from this grant in
2006.  During the first quarter of 2007, we experienced issues with
the delivery and quality of lignite coal under the lignite supply agreement as
well as combustion issues with the coal combustor.  We terminated the
contract for lignite coal delivery in April 2007 due to the supplier’s failure
to deliver lignite coal as required by the contract.  At that time, we
entered into short term delivery for PRB coal as an alternative to lignite
coal.  During December 2007, we extended our PRB coal agreement for
two additional years as we continue to try to resolve the issues experienced
while running the Plant on lignite coal.  Due to the temporary nature
of our use of PRB coal, the grant terms remain consistent with that described
above; however, a permanent change to a primary fuel source other than lignite
coal may accelerate or increase the repayment of these amounts.  We
intend to use lignite coal in the future if delivery, pricing, quality and
performance issues can be resolved favorably.  Because we have been
temporarily using PRB coal, we made a formal request to extend the Final Report
deadline from June 30, 2007 to August 31, 2007.  We received the
extension but have not yet returned to using lignite coal nor filed the Final
Report.  In place of the Final Report, we filed a memo with the
Commission updating them on the status of using lignite coal at our Plant for
2007.  This included supplying information on what percentage lignite
coal was of our total coal usage (on a BTU basis).  For 2007 and 2008,
we did not meet the minimum lignite usage specified in the grant
contract.  Based on that information, we expect the Commission to
notify us that we will have to repay our grant at an accelerated rate of $35,000
per year for every year we do not meet the specified percentage of lignite use
as outlined in our grant.  We have remained in contact with the
Commission about the current state of the Plant as well as future intentions to
run on lignite coal.




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, 2008, 2007 and 2006 we received $73,000,
$0 and $0, respectively.  We anticipate receiving approximately
$40,000 from this grant for the year ended December 31, 2009.




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 $2.1 million from this program during
2008.  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 is only
funded once every two years.  Currently, there are no funds available
for this program and it will not be funded again until June 2009.  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.




30




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.




Tax
Credit for Investors




In
addition, our investors are eligible for a tax credit against North Dakota state
income tax liability. On May 3, 2004, we were approved for the North Dakota
Seed Capital Investment Tax Credit. In 2005, North Dakota revised its tax
incentive programs and adopted the Agricultural Commodity Processing Facility
Investment Tax Credit. We were grandfathered into the new program and do not
need to meet the new conditions to qualify for the tax credit. The amount of
credit for which a taxpayer may be eligible is 30% of the amount invested by the
taxpayer in a qualified business during the taxable year.




The
maximum annual credit a taxpayer may receive is $50,000 and no taxpayer may
obtain more than $250,000 in credits over any combination of taxable years. In
addition, a taxpayer may claim no more than 50% of the credit in a single year
and the amount of the credit allowed for any taxable year may not exceed 50% of
the tax liability, as otherwise determined. Credits may carry forward for up to
five years after the taxable year in which the investment was made.




Off-Balance
Sheet Arrangements




We do not
have any off-balance sheet arrangements.




ITEM 7A QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK.




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 $15 million of our
outstanding long-term debt is at a variable rate as of December 31,
2008.  We anticipate that a hypothetical 1% change in interest rates,
from those in effect on December 31, 2008, would change our interest expense by
approximately $150,000 on an annual basis.  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 contracts that effectively
fix the interest rate at 8.08% on approximately $27.6 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. Market value adjustments and net settlements were
recorded as a gain or loss from non-designated hedging activities in other
income and expense for 2006 and are recorded in interest expense in 2007 and
2008. For the fiscal years ending December 31, 2008, 2007 and 2006, the net
settlement amounts were $449,000, $38,650 and $0, respectively.  The
market value adjustments resulted in gains/(losses) of approximately of $(1.8
million), $(933,000) and $167,000, respectively.  We anticipate that a
hypothetical 1% change in interest rates, from those in effect on December 31,
2008, would change the fair value of our interest rate swaps by approximately
$700,000.




31




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.  A
trend has developed where ethanol and corn prices appear to be “linked,” meaning
that as corn prices move up or down, ethanol prices also move up or down
accordingly.  Over the last 18 months, corn and ethanol prices have
generally maintained a spread that has been large enough to allow plants to
operate at a positive cash flow level.  This changed during the month
of December 2008 when corn prices increased approximately $1 per bushel but
ethanol prices did not increase accordingly.  This “delinking” of corn
and ethanol prices had the effect of decreasing the spread between corn and
ethanol prices to the point where, we believe, many plants are operating at a
negative cash flow level.  Since that time, corn and ethanol prices
have again become “linked” and are moving in tandem.  We have come to
believe that, as long as ethanol prices are following corn prices, our exposure
to price changes in corn and ethanol is greatest when we have locked in a price
for these commodities through fixed price contracts.  Accordingly, we
changed our hedging strategy in late 2008 in reaction to this
trend.  If this trend changes, it may warrant another change in our
current hedging strategy.  Through the experience gained while the
commodity markets crashed during the last six months of 2008, we now feel we
have a better understanding of how and when to adjust our hedging
strategy.  This does not mean our strategy will always work but we
feel we will be able to make more timely adjustments to our strategy in response
to changes in the markets.




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 likely will not qualify for hedge accounting, which would
match the gain or loss on our hedge positions to the specific commodity purchase
being hedged.  We intend to 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.




As of
December 31, 2008 we had approximately 1.7 million bushels of corn under fixed
price contracts.  We had accrued a loss on firm purchase commitments
of approximately $1.4 million related to these bushels as average fixed price of
these contracts was approximately $.80 above market value.  We would
expect a $0.10 change in the price of corn to have an approximate $170,000
impact on our net income.  We also had approximately 642,000 gallons
(equivalent of approximately 238,000 bushels of corn) of ethanol in inventory
that was not priced.  As described above, we had entered in to various
hedging instruments to protect the bushels under fixed price contracts and
equivalent bushels that had been converted to ethanol but were not yet priced,
from fluctuations in the market price of corn.  As of December 31,
2008, our net hedge position was short the equivalent of 404 futures contracts
or approximately 2 million bushels of corn.  We would generally expect
that a $0.10 change in the price of corn would produce a $200,000 margin excess
or deficiency.




While we
have previously used ethanol swap contracts to lock in a price for a small
portion of our ethanol production, we do not anticipate using these types of
contracts during 2009 but may use them, if we believe it will produce positive
results for the Plant.  It is the 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.




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. As of December 31, 2008 and 2007, we had
investments of $447,000 and $3.1 million in corn and ethanol derivative
instruments, respectively.  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.




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 - 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.




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.




32





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) 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, 2008,
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, 2008. 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, 2008.




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, 2008, 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.




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.




33




ITEM 9B. OTHER
INFORMATION




None.




PART
III




ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE




The
information required by Item 10 is incorporated by reference to the sections
labeled “Election of Two Members to the Board of Governors,” “Governors,”
“Corporate Governance,” “Information about Officers,” “Code of Ethics,” and
“Section 16(a) Beneficial Ownership Reporting Compliance,” all of which appear
in our definitive proxy statement to be filed with the SEC within 120 days after
the close of the fiscal year covered by this Annual Report (December 31,
2008).for our 2009Annual Meeting.




ITEM
11. EXECUTIVE COMPENSATION




The
information required by Item 11 is incorporated herein by reference to the
sections entitled “Executive Officer Compensation” and “Governors’
Compensation,” all of which appear in our definitive proxy statement for our
2009 Annual Meeting.




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




The
information required by Item 12 is incorporated herein by reference to the
sections entitled “Security Ownership of Certain Beneficial Owners and
Management and Related Member Matters,” and “Equity Compensation Plan
Information” which appear in our definitive proxy statement for our 2009 Annual
Meeting.




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




The
information required by Item 13 is incorporated herein by reference to the
sections entitled “Governor Independence” and “Transactions with Related
Persons, Promotors and Certain Control Persons,” which appear in our definitive
proxy statement for our 2009 Annual Meeting.




ITEM
14. PRINCIPAL ACCOUNTING FEES AND SERVICES




The
information required by Item 14 is incorporated herein by reference to the
section entitled “Auditors’ Fees,” which appears in our definitive proxy
statement for our 2009 Annual 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.




34




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.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.




35




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.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.




36




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.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.




37




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 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.




38




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.


Date:
      March 31, 2009
            
            /s/
      Mick J. MillerMick
      J. MillerPresident
      and Chief 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.


Date:
      March 31, 2009
            
            /s/
      Mick J. MillerMick
      J. MillerPresident
      and Chief Executive Officer(Principal
      Executive Officer)Date:
      March 31, 2009
            
            /s/
      Mark E. KlimpelMark
      E. KlimpelChief
      Financial Officer(Principal
      Financial and Accounting Officer)Date:
      March 31, 2009
            
            /s/
      Mike AppertMike
      Appert, Chairman of the BoardDate:
      March 31, 2009
            
            /s/
      William A. PriceWilliam
      A. Price, Secretary and GovernorDate:
      March 31, 2009
            
            /s/
      Ron AberleRon
      Aberle, GovernorDate:
      March 31, 2009
            
            /s/
      Jody HoffJody
      Hoff, Vice Chairman and GovernorDate:
      March 31, 2009
            
            /s/
      Frank KirschenheiterFrank
      Kirschenheiter, Treasurer and GovernorDate:
      March 31, 2009
            
            /s/
      Tim MeuchelTim
      Meuchel, Governor





39




Red
Trail Energy, LLC




Financial
Statements




December 31, 2008,
2007 and
2006




CONTENTS


PageReport
      of Independent Registered Public Accounting Firm
              
              
              F-2Financial
      StatementsBalance
      Sheet
              
              
              F-3Statement
      of Operations
              
              
              F-4Statement
      of Changes in Members’ Equity
              
              
              F-5Statement
      in Cash Flows
              
              
              F-6Notes
      to Financial Statements
              
              
              F-7
      -22
  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, 2008 and 2007, 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, 2008.  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, 2008 and 2007, and the results of their operations and their cash
flows for each of the years in a three-year period ended December 31, 2008 in
conformity with U.S. generally accepted accounting principles.




The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern.  As discussed in Notes 1 and 3 to
the financial statements, the Company is in default on certain covenants of its
loan agreements as of December 31, 2008, primarily as a result of a net loss of
$5,366,572 incurred in 2008.  The lenders can demand repayment of the
loans.  No such demand has been made.  Negotiations are
presently under way to obtain revised loan agreements.  The Company
cannot predict what the outcome of negotiations will be.  These
conditions raise substantial doubt about the Company’s ability to continue as a
going concern.  The financials statements do not include any
adjustments that might result from the outcome of this uncertainty.




/s/ Boulay,
      Heutmaker, Zibell & Co. PLLPCertified
      Public Accountants




Minneapolis,
Minnesota


March 31,
2009




F-2




Red Trail Energy, LLC




Balance
Sheet




December
      31,
            
            2008
            
            
            2007ASSETSCurrent
      AssetsCash
      and equivalents
            
            $
            4,433,839
            
            
            $
            8,231,709Accounts
      receivable
            
            
            2,697,695
            
            
            
            5,960,041Corn
      and ethanol derivative instruments, at market
            
            
            447,739
            
            
            
            3,190,790Inventory
            
            
            3,353,592
            
            
            
            8,297,356Prepayments
      of corn purchases
            
            
            4,398,046
            
            
            ─Prepaid
      expenses
            
            
            41,767
            
            
            
            53,411Total
      current assets
            
            
            15,372,678
            
            
            
            25,733,307Property,
      Plant and EquipmentLand
            
            
            351,280
            
            
            
            300,602Plant
      and equipment
            
            
            79,898,657
            
            
            
            78,139,237Land
      improvements
            
            
            3,939,294
            
            
            
            3,918,766Buildings
            
            
            5,312,995
            
            
            
            5,312,995Construction
      in progress
            
            
            33,679
            
            
            ─89,535,905
            
            
            
            87,671,600Less
      accumulated depreciation
            
            
            11,525,863
            
            
            
            5,729,058Net
      property, plant and equipment
            
            
            78,010,042
            
            
            
            81,942,542Other
      AssetsDebt
      issuance costs, net of amortization
            
            
            567,385
            
            
            
            768,405Investment
      in RPMG
            
            
            605,000
            
            
            ─Patronage
      equity
            
            
            116,296
            
            
            ─Deposits
            
            
            80,000
            
            
            
            80,000Total
      other assets
            
            
            1,368,681
            
            
            
            848,405Total
      Assets
            
            $
            94,751,401
            
            
            $
            108,524,254LIABILITIES
      AND MEMBERS' EQUITYCurrent
      LiabilitiesCurrent
      maturities of long-term debt
            
            $
            49,063,201
            
            
            $
            6,578,004Accounts
      payable
            
            
            5,720,764
            
            
            
            6,682,330Accrued
      expenses
            
            
            1,845,101
            
            
            
            2,502,936Accrued
      loss on firm purchase commitments
            
            
            1,426,800
            
            
            ─Interest
      rate swap, at market
            
            
            2,861,530
            
            
            
            1,044,191Total
      current liabilities
            
            
            60,917,396
            
            
            
            16,807,461Other
      LiabilitiesContracts
      payable
            
            
            275,000
            
            
            
            275,000Long-Term
      Debt
            
            ─
            
            
            
            52,538,310Commitments
      and ContingenciesMembers'
      Equity
            
            
            33,559,005
            
            
            
            38,903,483Total
      Liabilities and Members' Equity
            
            $
            94,751,401
            
            
            $
            108,524,254




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




F-3





Red
Trail Energy, LLC


Statement of Operations




Years
      ended December 31,
              
              2008
              
              
              2007
              
              
              2006RevenuesEthanol,
      net of loss on derivative instruments
              
              $
              111,086,858
              
              
              $
              90,100,581
              
              
              $
              ―Distillers
      grains
              
              
              20,816,656
              
              
              
              11,785,388
              
              
              
              ―Total
      Revenue
              
              
              131,903,514
              
              
              
              101,885,969
              
              
              
              ―Cost
      of Goods SoldCost
      of goods sold
              
              
              121,042,965
              
              
              
              81,358,010
              
              
              
              ―Loss
      on firm purchase commitments
              
              
              3,470,110
              
              
              
              ―
              
              
              
              ―Lower
      of cost or market adjusment for inventory on hand
              
              
              771,200
              
              
              
              ―
              
              
              
              ―Depreciation
              
              
              5,740,963
              
              
              
              5,655,198
              
              
              
              ―Total
      Cost of Goods Sold
              
              
              131,025,238
              
              
              
              87,013,208
              
              
              
              ―Gross
      Margin
              
              
              878,276
              
              
              
              14,872,761
              
              
              
              ―General
      and Administrative
              
              
              2,857,091
              
              
              
              3,214,002
              
              
              
              3,747,730Operating
      Income (Loss)
              
              
              (1,978,815
              )
              
              
              11,658,759
              
              
              
              (3,747,730
              )Interest
      Expense
              
              
              6,013,299
              
              
              
              6,268,707
              
              
              
              ―Other
      Income, net
              
              
              2,625,542
              
              
              
              767,276
              
              
              
              1,243,667Net
      Income (Loss)
              
              $
              (5,366,572
              )
              
              $
              6,157,328
              
              
              $
              (2,504,063
              )Weighted
      Average Units Outstanding - basic
              
              
              40,176,974
              
              
              
              40,371,238
              
              
              
              39,625,843Weighted
      Average Units Outstanding - fully diluted
              
              
              40,176,974
              
              
              
              40,416,238
              
              
              
              39,625,843Net
      Income (Loss) Per Unit - basic
              
              $
              (0.13
              )
              
              $
              0.15
              
              
              $
              (0.06
              )Net
      Income (Loss) Per Unit - fully diluted
              
              $
              (0.13
              )
              
              $
              0.15
              
              
              $
              (0.06
              )




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




F-4





Red Trail Energy, LLC


Statement of Changes in Members’
Equity




Class
      A Member Units
            
            
            Additional
      Paid
            
            
            Retained
            
            
            Treasury
      Units
            
            
            Total
      Members'Years
      Ended December 31, 2008, 2007 and 2006
            
            Units
      (a)
            
            
            Amount
            
            
            in
      Capital
            
            
            Earnings
            
            
            Units
            
            
            Amount
            
            
            EquityBalance
      - December 31, 2005
            
            
            33,598,266
            
            
            
            31,090,951
            
            
            
            56,825
            
            
            
            (2,434,082
            )
            
            
            ―
            
            
            
            ―
            
            
            
            28,713,694Capital
      contributions - $1 per unit,January
      1 - March 31
            
            
            6,713,207
            
            
            
            6,713,207
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            6,713,207Units
      issued under option exercised -62,500
      units, $0.10 per unit
            
            
            62,500
            
            
            
            6,250
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            6,250Net
      Loss
            
            
            ―
            
            
            
            ―
            
            
            
            ―
            
            
            
            (2,504,063
            )
            
            
            ―
            
            
            
            ―
            
            
            
            (2,504,063
            )Balance
      - December 31, 2006
            
            
            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 compensation -agreement
            
            
            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
            )
            
            $
            33,559,005




(a)
      -
              Amounts
      shown represent member units outstanding.  Authorized and issued
      units were 33,598,266, 40,373,973, 40,373973 and 40,373,973 as ofDecember
      31, 2005, December 31, 2006, December 31, 2007 and December 31, 2008,
      respectively.




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,
              
              2008
              
              
              2007
              
              
              2006Cash
      Flows from Operating ActivitiesNet
      income (loss)
              
              $
              (5,366,572
              )
              
              $
              6,157,328
              
              
              $
              (2,504,063
              )Adjustment
      to reconcile net income (loss) to net cash provided by(used
      in) operating activities:Depreciation
              
              
              5,796,805
              
              
              
              5,713,042
              
              
              
              16,016Amortization
      of debt financing costs
              
              
              201,020
              
              
              
              214,169
              
              
              
              ―Change
      in market value of derivative instruments
              
              
              2,743,051
              
              
              
              (2,870,449
              )
              
              
              (320,341
              )Change
      in market value of interest rate swap
              
              
              1,368,307
              
              
              
              894,256
              
              
              
              (167,017
              )Non-cash
      patronage equity
              
              
              (116,296
              )
              
              
              ―
              
              
              
              ―Grant
      income applied to long-term debt
              
              
              (59,874
              )
              
              
              ―
              
              
              
              ―Unrealized
      loss on firm purchase commitments
              
              
              1,426,800
              
              
              
              ―
              
              
              
              ―Changes
      in assets and liabilitiesEquity-based
      compensation
              
              
              22,094
              
              
              
              20,000
              
              
              
              25,000Accounts
      receivable
              
              
              3,262,346
              
              
              
              (5,960,041
              )
              
              
              ―Inventory
              
              
              4,943,764
              
              
              
              (4,341,227
              )
              
              
              (3,956,129
              )Prepaid
      expenses
              
              
              (4,386,402
              )
              
              
              10,371
              
              
              
              (38,437
              )Other
      assets
              
              
              ―
              
              
              
              ―
              
              
              
              (80,000
              )Accounts
      payable
              
              
              (1,130,676
              )
              
              
              2,603,723
              
              
              
              (1,423,115
              )Accrued
      expenses
              
              
              (657,835
              )
              
              
              204,461
              
              
              
              510,778Other
      liabilities
              
              
              ―
              
              
              
              ―
              
              
              
              275,000Net
      settlements on derivative instruments
              
              
              449,032
              
              
              
              39,000
              
              
              
              ―Net
      cash provided by (used in) operating activities
              
              
              8,495,564
              
              
              
              2,684,633
              
              
              
              (7,662,308
              )Cash
      Flows from Investing ActivitiesInvestment
      in RPMG
              
              
              (435,890
              )
              
              
              ―
              
              
              
              ―Capital
      expenditures
              
              
              (1,864,305
              )
              
              
              (3,974,839
              )
              
              
              (66,903,860
              )Net
      cash used in investing activities
              
              
              (2,300,195
              )
              
              
              (3,974,839
              )
              
              
              (66,903,860
              )Cash
      Flows from Financing ActivitiesPayments
      for debt issuance costs
              
              
              ―
              
              
              
              ―
              
              
              
              (563,566
              )Debt
      repayments
              
              
              (10,153,739
              )
              
              
              (1,813,376
              )
              
              
              ―Proceeds
      from long-term debt
              
              
              160,500
              
              
              
              11,141,502
              
              
              
              49,788,188Member
      contributions
              
              
              ―
              
              
              
              ―
              
              
              
              6,719,457Treasury
      units repurchased
              
              
              ―
              
              
              
              (227,933
              )
              
              
              ―Net
      cash provided by (used in) financing activities
              
              
              (9,993,239
              )
              
              
              9,100,193
              
              
              
              55,944,079Net
      Increase (Decrease) in Cash and Equivalents
              
              
              (3,797,870
              )
              
              
              7,809,987
              
              
              
              (18,622,089
              )Cash
      and Equivalents - Beginning of Period
              
              
              8,231,709
              
              
              
              421,722
              
              
              
              19,043,811Cash
      and Eqivalents - End of Period
              
              $
              4,433,839
              
              
              $
              8,231,709
              
              
              $
              421,722Supplemental
      Disclosure of Cash Flow InformationInterest
      paid net of swap settlements
              
              $
              4,404,790
              
              
              $
              4,119,744
              
              
              $
              ―Interest
      paid and capitalized in construction in process
              
              $
              ―
              
              
              $
              ―
              
              
              $
              1,474,638SUPPLEMENT
      DISCLOSURE OF NON-CASHINVESTING
      AND FINANCING ACTIVITIESDebt
      issuance costs included in accounts payable
              
              $
              ―
              
              
              $
              ―
              
              
              $
              799Capital
      expenditures included in accounts payable
              
              $
              ―
              
              
              $
              ―
              
              
              $
              4,297,665Investments
      included in accounts payable
              
              $
              169,110
              
              
              $
              ―
              
              
              $
              ―Capital
      expenditures included in accrued liabilities
              
              $
              ―
              
              
              $
              ―
              
              
              $
              1,778,201Amortization
      of deferred financing costs capitalized inconstruction
      in process
              
              $
              ―
              
              
              $
              ―
              
              
              $
              52,291


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




F-6




Red
Trail Energy, LLC




Notes to
Financial Statements




December
31, 2008, 2007 and 2006




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.  Prior to January 1, 2007, the
Company was considered a development stage company.




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 and equity-based compensation; analysis of
intangibles impairment, the analysis of long-lived assets impairment and other
contingencies. Actual results could differ from those estimates.




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, 2008 and 2007.




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 61% and 80%
of the Company’s outstanding receivable balance as of December 31, 2008 and
2007, 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.




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,
2008 or December 31, 2007.




F-7


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


Derivative
Instruments




The
Company accounts for derivative instruments in accordance with Statement of
Financial Accounting Standards (SFAS) No. 133, “Accounting for
Derivative Instruments and Hedging Activities” (“SFAS
No. 133”).  SFAS No. 133 requires the recognition of derivatives
in the balance sheet and the measurement of these instruments 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 recorded in revenue.




Additionally,
SFAS No. 133 requires a company 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,
2008 and 2007 the Company has no derivatives instruments that meet this
criterion.




Firm Purchase
Commitments




Beginning
in December 2008, in connection with the execution of forward purchase
commitments, the Company has elected to create a hedging relationship by selling
exchanged traded futures or options as an offsetting position.  In
this situation, the forward purchase contract is designated to be valued at
market price until delivery was made against the contract.  On an
on-going basis we intend to closely monitor the number of bushels we have 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.





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 will be 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. Amortization expense for the
years ended December 31, 2008 and 2007 was $201,000 and $214,000,
respectively.  These amounts are included in interest
expense.




Fair Value of Financial
Instruments




The fair
value of the Company’s cash and cash equivalents, accounts receivable, accounts
payable, and derivative instruments approximate their carrying value. It is not
currently practicable to estimate the fair value of the Company’s long-term debt
and contracts payable since these agreements contain unique terms, conditions,
and restrictions, which were negotiated at arm’s length. As such, there are no
readily determinable similar instruments on which to base an estimate of fair
value of each item.




F-8


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


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.




In
June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income
Taxes – an interpretation of FASB Statement No. 109 (FIN 48). FIN 48
clarifies the requirements of SFAS 109, Accounting for Income Taxes,
relating to the recognition of income tax benefits. FIN 48 provides a two-step
approach to recognizing and measuring tax benefits when realization of the
benefits is uncertain. The first step is to determine whether the benefit meets
the more-likely-than-not condition for recognition and the second step is to
determine the amount to be recognized based on the cumulative probability that
exceeds 50%. Primarily due to the Company’s tax status as a limited liability
company, the adoption of FIN 48 on January 1, 2007, had no material effect on
the Company’s financial condition or results of operations.




Organizational and Start Up
Costs




The
Company expensed all organizational and start up costs as incurred.




Advertising




The
Company expenses advertising costs as they are incurred. Advertising costs
totaled approximately $5,700 and $10,000 for the years ended December 31, 2008
and 2007, respectively.




Equity-Based
Compensation




On
January 1, 2006, the Company adopted SFAS No. 123 (revised 2004)
(“SFAS No. 123R”), Share-Based Payment, which addresses the accounting for
stock-based payment transactions in which an enterprise receives employee
services in exchange for (a) equity instruments of the enterprise or (b)
liabilities that are based on the fair value of the enterprise’s equity
instruments or that may be settled by the issuance of such equity instruments.
In January 2005, the SEC issued SAB No. 107, which provides supplement
implementation guidance for SFAS No. 123R. SFAS No. 123R eliminates
the ability to account for stock-based compensation transaction using the
intrinsic value method under Accounting Principles Board (“APB”) Opinion
No. 25, Accounting for Stock Issued to Employees, and instead generally
requires that such transaction be accounted for using a fair-value-based method.
The Company adopted the provisions of SFAS No. 123R using the straight-line
attribution method. Under this method, the Company recognizes compensation cost
related to service-based awards ratably over a single requisite service
period.




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. Equity-based compensation expense for the years ended
December 31, 2008 and 2007 totaled approximately $22,000 and $20,000,
respectively.




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 2008, 2007 and 2006, the Company had 50,000, 45,000 and
25,000 member unit equivalents.  For 2008 and 2006, member unit
equivalents were not included in diluted equivalents outstanding as their effect
is anti-dilutive.




F-9


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


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, 2008 and 2007.




Recent Accounting
Pronouncements




In March
2008, the FASB issued Statement of Financial Accounting Standard No. 161 (“SFAS
161”), “Disclosures about
Derivative Instruments and Hedging Activities”, an amendment of Statement
of Financial Accounting Standard No. 133 (“SFAS 133”).  SFAS 161
applies to all derivative instruments and nonderivative instruments that are
designated and qualify as hedging instruments pursuant to paragraphs 37 and 42
of SFAS 133 and related hedged items accounted for under SFAS 133. SFAS 161
requires entities to provide greater transparency through additional disclosures
about how and why an entity uses derivative instruments, how derivative
instruments and related hedged items are accounted for under SFAS 133 and its
related interpretations, and how derivative instruments and related hedged items
affect an entity’s financial position, results of operations, and cash flows.
SFAS 161 is effective as of the beginning of an entity’s first fiscal year, or
interim period, that begins after November 15, 2008. No determination has yet
been made regarding the potential impact of this standard on the Company’s
financial statements.




Going
Concern and Management’s Plans




The
accompanying financial statements have been prepared assuming that the Company
will continue as a going concern which contemplates the realization of assets
and the satisfaction of liabilities in the normal course of
business.  The Company has incurred operating loses and negative
operating cash flow since August 2008.  The Company anticipates
continuing to incur losses and negative cash flow, based on current market
conditions in the ethanol industry.  As of March 27, 2009, the Bank
gave notice that we were in violation of certain of the covenants in our loan
agreements at December 31, 2008.  Also on March 27, 2009, the Bank
granted us a waiver of those covenant violations.  We are currently
projecting that we will be in violation of certain of our loan covenants during
2009.  Due to the projected covenant violations, it is likely the Bank
will have the ability to call our debt due and payable during 2009 which has
resulted in the reclassification of our long-term debt to a current
liability.




These
factors raise substantial doubt about the Company’s ability to continue as a
going concern.  Realization of assets is dependent upon continued
operations of the Company, which in turn is dependent upon management’s plans to
meet its financing requirements and the success of its future
operations.  The ability of the Company to continue as a going concern
is dependent on improving the Company’s profitability and cash flow, possibly
securing additional financing or raising additional equity, and working with the
Bank to avoid being declared in default on its loans. While the Company
believes in the viability of its strategies to return to a positive cash flow
and, ultimately, profitability, there can be no assurances to that
effect. These financial statements do not include any adjustments related
to the recoverability and classification of asset amounts or the amounts and
classification of liabilities that might be necessary if the Company is unable
to continue as a going concern.




Please
see Note 3 for further detail on these items along with management’s plans to
mitigate the effect of these items.




2.  CONCENTRATIONS




Coal




Coal is
also an important input to our manufacturing process. During the fiscal year
ended December 31, 2008, we used approximately 97,600 tons of
coal.  We have entered into a two year agreement with Westmoreland
Coal Sales Company (“Westmoreland”) to supply PRB coal through
2009.  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.  As of March 24, 2009, we were notified by
Westmoreland that a work stoppage has occurred at the mine from which we
normally receive coal.  We have enough coal on hand to operate our
Plant for approximately one month.  Westmoreland has more than one
mine from which we can purchase coal and we are actively communicating with them
to ensure we can receive shipments from another location if the work stoppage is
not resolved shortly.




F-10


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


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.




3.  NATURE
OF CURRENT OPERATIONS




Both the
corn and ethanol markets experienced significant decreases in price during the
last six months of 2008 as compared to the first six months of
2008.  The decreases have occurred in conjunction with the decline in
most other major commodities and world financial markets in response to the
current global economic crisis.  This decrease has had a significant
negative impact on the Company.  As part of its corn procurement
strategy, the Company enters into contracts with local farmers and elevators in
advance to ensure an adequate supply.  The Company had approximately
1.7 million bushels under fixed price contracts as of December 31, 2008 at an
average price that was significantly higher than market prices.  From
January through November 2008, ethanol prices have tracked very closely with
changes in corn prices.  As corn prices moved up or down, ethanol
prices moved up or down accordingly.  As such, the Company benefited
greatly during the first part of the year from having fixed price contracts for
corn purchases that were under the market value at the time of
delivery.  As the price of corn rose to record levels during the first
six months, ethanol prices also increased, with the result being higher gross
margins for the Company during that time period.  During the last six
months of 2008, the drop in corn prices has had the opposite effect on gross
margins.  Prices dropped very quickly in a short period of time and,
at December 31, 2008, the Company’s average price for corn under fixed contracts
was approximately $0.85 per bushel above the market value.  Because
these contracts are considered firm purchase commitments of inventory and
inventory is valued at the lower of cost or market, the Company had to record a
loss during the third quarter of 2008 of approximately $0.90 per bushel for
fixed price corn contracts in place at September 30, 2008 that were not hedged
by fixed price ethanol sales.  The amount of this loss was
approximately $3.1 million.  Our total loss on firm purchase
commitments for 2008 was approximately $3.5 million and is shown as a loss on
firm purchase commitments on the statement of operations.




During
the fourth quarter of 2008, corn and ethanol prices continued to decrease while
we continued to process through the corn we had under fixed price
contracts.  During the fourth quarter of 2008, we took delivery of
approximately 2.8 million bushels of the corn that was under contract at
September 30, 2008.  We have continued to enter into fixed price
contracts but, at this time, they are much closer to market prices.




Through
the experience of the last six months of 2008 we have come to believe that the
Company’s greatest exposure to changes in the price of corn and ethanol comes
when it has fixed price contracts for the purchase of corn and/or the sale of
ethanol.  As such, the Company’s risk management committee has
adjusted its hedging strategy in an effort to protect the Company when it does
enter into fixed price contracts.  As long as ethanol prices are
generally following changes in corn price, the Company’s strategy is to maintain
an approximate even corn position.  For example, the Company had
approximately 1.7 million bushels under fixed price contracts as of December 31,
2008.  In order to mitigate the risk associated with these fixed price
contracts, the Company used various hedging instruments (puts, calls and
futures) to short this position.  As of December 31, 2008, the Company
had a short hedge position equal to 404 futures contracts, or approximately 2
million bushels of corn.  As corn is purchased or processed, this
short position will be periodically adjusted so the Company stays at a net even
position.




As of
February 2009, our Plant, and, we believe, many other plants in the ethanol
industry, are operating in a negative cash flow environment.  We
anticipate that, if margins do not improve, we may need to raise additional
capital to meet our operating cash flows during 2009.  As of February
2009, we had available capital (cash plus borrowing capacity) of approximately
$9.8 million.  This included $6 million of cash on hand, $1 million of
capacity available under our Long-Term Revolving Note and $3.5 million of
capacity under our Line of Credit.  Our available capital does not
include $4.2 million that has been aside in conjunction with amounts withheld
from Fagen, Inc as described in Note 12.  Under current market
conditions we anticipate that we will have available capital to operate our
business through the end of 2009 but that the level of available capital that we
have left may be insufficient to sustain operations through the first quarter of
2010.  If we continue to violate our loan covenants, the Bank may
limit the amounts we can borrow under our lines of credit.  We are
evaluating, on an on-going basis, the capacity at which to operate our Plant,
including possibly shutting down until margins improve.  At this time,
we believe that operating our Plant, even at a reduced rate, is a more favorable
option that shutting down.




We have a
limited capacity to borrow additional funds due to the collateral position of
First National Bank of Omaha (“FNBO” or the “Bank”).  We also have a
limited ability to raise additional capital through an equity offering due to
language in our Member Control Agreement that limits issuing additional units
without written consent of all members.  We have been proactively
discussing these items with FNBO and are working with them to find a solution
for our Plant.




The
Company’s loan agreements, as described in Note 6, require the Company to
maintain certain financial ratios and meet certain non-financial
covenants.  The Company was notified on March 27, 2009 by its senior
lender, First National Bank of Omaha (“FNBO” or the “Bank”), that it was in
violation of certain loan covenants as of December 31, 2008 and that it has been
granted a waiver of those covenant violations.  Our projections show
that we will be in violation of certain of our loan covenants during
2009.  As a result of these projected covenant violations, which make
it reasonably likely that the Bank will be able to call our long-term debt due
and payable during 2009, we have reclassified all of our long-term debt to a
current liability on the balance sheet.  As part of our ongoing
communication with the Bank we have requested the Bank consider entering into a
forbearance agreement.  A forbearance agreement would typically allow
the Company to forgo principal payments for a period of time in exchange for an
increase in the interest rates on the associated debt along with requirements
for the Company to take certain actions and/or maintain or attain certain
financial milestones.  There is no certainty that we will be able to
reach agreement with the Bank on the terms of a forbearance agreement or that
the Bank will grant us waivers for future projected loan covenant
violations.  Due to the nature of these uncertainties and the current
negative margin structure in the market place, the Company’s ability to continue
as a going concern is uncertain.  As such, the Company may be forced
to cease operations, declare bankruptcy and/or surrender its assets to the
Bank.




F-11


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


To offset
the current poor market conditions, the Company has taken a number of steps
including:




1.
            Temporarily
      suspending employee bonuses and eliminating management bonuses for the
      year ended December 31, 2008.




2.
            The
      Company’s Chief Executive Office and Chief Financial Officer took
      voluntary pay cuts totaling $45,000
annually.




3.
            The
      Company’s board of governors has opted out of the compensation they
      receive for attending board and committee
  meetings.




4.
            The
      Company has reduced its production rate to approximately 80% of
      capacity.  The rate is being monitored on an on-going basis in
      conjunction with industry margins to determine the best rate at which to
      operate the Plant.




5.
            The
      Company has adjusted its hedging strategy, as mentioned
    above.




6.
            The
      Company has undertaken various measures to improve efficiency in the Plant
      in an effort to get the most ethanol out of each bushel of
      corn.  This is an on-going
process.




7.
            The
      Company has reorganized its corn procurement practices in an effort to
      procure more corn from North Dakota farmers and less via rail, resulting
      in lower transportation costs.




8.
            The
      Company is also evaluating other potential cost cutting
      measures.




4.
DERIVATIVE INSTRUMENTS




The
Company has derivative instruments in the form of futures, call options, put
options and swaps related to the purchase of corn and the sale of
ethanol.  The fair market value of the asset recorded for these
derivative instruments totaled approximately $448,000 and $3.2 million as of
December 31, 2008 and 2007, respectively.  These derivative
instruments are not designated as a cash flow or fair value hedge. Gains and
losses based on the fair value change in derivative instruments related to corn
are recorded in cost of goods sold.  During the years ended December
31, 2008 and 2007, the Company recognized gains of approximately $6.2 million
and $3.1 million, respectively.  Gains and losses based on the fair
value change in derivative instruments related to ethanol are recorded in
revenue.  During the years ended December 31, 2008 and 2007, the
Company recognized losses on ethanol related derivatives of approximately $2.3
million and $2 million, respectively.  The Company has derivative
instruments in the form of interest rate swaps in an agreement associated with
bank financing that is not designated as a cash flow hedge.  Fair
market value related to the interest rate swap liabilities totaled approximately
$2.9 million and $1 million as of December 31, 2008 and 2007,
respectively.  Market value adjustments and net settlements related to
these agreements are recorded as a gain or loss from non-designated hedging
derivatives in interest expense.  The amount charged to interest
expense related to the interest rate swaps was $1.8 million and $933,000 during
2008 and 2007, respectively.  In addition, the Company recorded net
settlements, in interest expense, related to the interest rate swaps of $449,000
and $39,000 for 2008 and 2007, respectively.




5.
INVENTORY




Inventory
is valued at lower of cost or market.  At December 31, 2008, the
Company recorded an adjustment of $212,000 to its corn inventory and $559,000 to
its ethanol inventory to record it at the lower of cost or market
value.  As of December 31, 2008, the Company had paid for, but not yet
received, two unit trains of corn.  As such, approximately $4.4
million is included in prepaid inventory because the Company had not yet taken
possession of the corn as of December 31, 2008.  The bushels were not
taken into account in the lower of cost or market calculation related to
inventory on hand but were taken into account in the calculation of the accrued
loss on firm purchase commitments.  Inventory values as of December
31, 2008 and 2007 were as follows:




As
      of December 31,
              
              2008
              
              
              2007Raw
      materials, including corn, chemicals and supplies
              
              $
              1,636,631
              
              
              $
              5,576,077Work
      in process
              
              
              681,187
              
              
              
              902,560Finished
      goods, including ethanol and distillers grains
              
              
              1,035,774
              
              
              
              1,818,719Total
      inventory
              
              $
              3,353,592
              
              
              $
              8,297,356
  F-12


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


Lower of
cost or market adjustments for the years ended December 31, 2008 and 2007 were
as follows:




For
      the years ended December 31,
              
              2008
              
              
              2007Loss
      on firm purchase commitments
              
              $
              3,470,110
              
              
              $
              ―Lower
      of cost or market adjustment for inventory on hand
              
              
              771,200
              
              
              
              ―Total
      lower of cost or market adjustments
              
              $
              4,241,310
              
              
              $
              ―


The
Company has entered into forward corn purchase contracts under which it is
required to take delivery at the contract price.  Currently, some of
these contract prices are above current market prices for corn.  Given
the declining ethanol price, upon taking delivery under these contracts, the
Company would incur a loss.  Accordingly the Company recorded a loss
on these purchase commitments of approximately $3.5 million for the year ended
December 31, 2008.  The loss was recorded in “Loss on firm purchase
commitments” on the statement of operations.  The amount of the loss
was determined by applying a methodology similar to that used in the impairment
valuation with respect to inventory.  Given the uncertainty of future
ethanol prices, this loss may not be recovered, and further losses on the
outstanding purchase commitments could be recorded in future
periods.




As of
December 31, 2008, we recorded an inventory valuation impairment of $771,000
attributable primarily to decreases in market prices of corn and
ethanol.  The inventory valuation impairment was recorded in “Lower of
cost or market adjustment related to inventory on hand” on the statement of
operations.




6.
BANK FINANCING




Long-term
debt consists of the following:




As
      of December 31,
              
              2008
              
              
              2007Notes
      under loan agreement payable to bank, see details below
              
              $
              43,436,721
              
              
              $
              53,437,367Subordinated
      notes payable, see details below
              
              
              5,525,000
              
              
              
              5,525,000Capital
      lease obligations (Note 5)
              
              
              101,480
              
              
              
              153,947Total
      Long-Term Debt
              
              
              49,063,201
              
              
              
              59,116,314Less
      amounts due within one year *
              
              
              49,063,201
              
              
              
              6,578,004Total
      Long-Term Debt Less Amounts Due Within One Year
              
              $
              0
              
              
              $
              52,538,310


* - The
Company has projected that it will not meet compliance with certain of its loan
covenants throughout 2009 and it has not been able to secure a waiver from the
bank for current or projected violations.  Because of this, the
Company is required to show all of its debt subject to those covenant violations
as a current liability.  In accord with the covenant waiver received
for violations at December 31, 2008, the Bank has not called the debt due and
payable.  The Company has shown the scheduled debt maturities below
under the assumption that it will continue to make its scheduled note payments
under the original terms of the agreement.




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




As
      of December 31,
              
              20082009
              
              $
              5,226,1472010
              
              
              5,413,1752011
              
              
              5,715,1982012
              
              
              32,696,2212013
              
              
              12,460Thereafter
              
              
              ―Total
              
              $
              49,063,201


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.
  F-13
 Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


We have
been notified by FNBO that we were in violation of certain of the covenants in
our loan agreements at December 31, 2008 and that we were granted a waiver of
those violations.  These include the covenants requiring a minimum
working capital balance, minimum net worth and a minimum fixed charge coverage
ratio.  Please see Note 3 for further discussion of the covenant
violations, future projected waiver requests and forbearance agreement
negotiations.  If we are successful in negotiating a forbearance
agreement, the terms of the agreement may impact the interest rates and payment
amounts of the company’s outstanding long-term debt (see “Term Notes”
below).




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.


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.  The Company incurred interest expense on these loans of
approximately $4.2 million and $5.1 million for the years ended December 31,
2008 and 2007, respectively.




Construction
Loan




The
Company has four long-term notes (collectively the “Term Notes”) in place as of
December 31, 2008.  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.




Fixed Rate
Note




The Fixed
Rate Note had an outstanding balance of $24.7 million and $26.6 million at
December 31, 2008 and 2007, respectively.  Interest payments are made
on a quarterly basis with interest charged at 3.0% over the three-month LIBOR
rate.  The interest rate is reset on a quarterly basis.  As
of December 31, 2008 and 2007, the rate was 7.635% and 8.22375%,
respectively.  Principal payments are to be made quarterly according
to repayment terms of the construction loan agreement, generally beginning at
approximately $520,000 and increasing to $653,000 per quarter, from January 2009
to January 2012, with a final principal payment of approximately $17.3 million
at  April 2012.




Variable Rate
Note




During
December 2007, $10 million of the Variable Rate Note was transferred to the
December 2007 Fixed Rate Note as part of the 4th
amendment to the loan agreement.  The Variable Rate Note had an
outstanding balance of $3 million and $6.8 million at December 31, 2008 and
2007, respectively.  Interest payments are made on a quarterly basis
with interest charged at 3.4% over the three-month LIBOR rate.  The
interest rate is subject to an incentive pricing clause where the Company will
be charged a lower rate if it meets certain financial criteria.  As of
July 2008, the Company had qualified for the incentive pricing.  As
such, interest on the Variable Rate Note is being charged at 3.25% over the
three-month LIBOR.  The interest rate is reset on a quarterly
basis.  As of December 31, 2008 and 2007, the rate was 7.885% and
8.62375%, respectively.  Principal payments are made quarterly
according to the terms of the construction loan agreement as amended by the
fourth amendment to the construction loan agreement.  The amendment
calls for quarterly payments of $634,700 applied first to interest on the
Long-Term Revolving Note, next to accrued interest on the Variable Rate Note and
finally to principal on the Variable Rate Note.  Based on the interest
rate noted above, the Company estimates that the remaining Variable Rate Note
will be paid off in April 2010.  The Company anticipates the principal
payments to be approximately $550,000 per quarter with a final payment of
approximately $320,000 in April 2010.




Long-Term Revolving
Note




The
Long-Term Revolving Note had an outstanding balance of $6.4 million and $10
million at December 31, 2008 and 2007, respectively.  The Company did
borrow an additional $2.5 million of the available capacity on the Long-Term
Revolving Note during January 2009.  Taking this borrowing into
account and, based on current interest rates and the anticipated pay off date of
the Variable Rate Note, we expect scheduled principal payments to start being
applied to this note in April 2010.  The payments will range from
approximately $540,000 to $576,000.  We anticipate a final payment of
approximately $4.9 million in April 2012.  Interest is charged at 3.4%
over the one-month LIBOR rate with payments due quarterly.  The
interest rate is subject to an incentive pricing clause where the Company will
be charged a lower rate if it meets certain financial criteria.  As of
July 2008, the Company had qualified for the incentive pricing.  As
such, interest on the Long-Term Revolving Note is being charged at 3.25% over
the three-month LIBOR.  The interest rate is reset
monthly.  As of December 31, 2008 and 2007, the rate was 4.29% and
8.4275%, respectively.  The maturity date of this note is April
2012.




F-14


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


December 2007 Fixed Rate
Note




The
December 2007 Fixed Rate Note was created by the fourth amendment to the
construction loan agreement as noted above.  The balance on this note
at December 31, 2008 and 2007 was $9.2 million and $10 million,
respectively.  Interest payments are made on a quarterly basis with
interest charged at 3.4% over the three-month LIBOR rate.  The
interest rate is reset on a quarterly basis.  As of December 31, 2008
and 2007, the rate was 8.035% and 8.22375%, respectively.  Principal
payments are to be made quarterly according to repayment terms of the
construction loan agreement, generally beginning at approximately $192,000 and
increasing to $242,000 per quarter, from January 2009 to January 2012, with a
final principal payment of approximately $6.3 million at
April 2012.  All unpaid amounts on the three term notes are due
and payable in April 2012.




Revolving Line of
Credit




The
Company entered into a $3,500,000 line of credit agreement with its bank,
subject to certain borrowing base limitations, through July 5, 2008.
Interest is payable quarterly and charged on all borrowings at a rate of 3.4%
over one-month LIBOR.  The interest rate is subject to an incentive
pricing clause where the Company will be charged a lower rate if it meets
certain financial criteria.  As of July 2008, the Company had
qualified for the incentive pricing.  As such, interest on the
Revolving Line of Credit is being charged at 3.25% over the three-month
LIBOR.  The interest rate is reset on a quarterly
basis.   As of December 31, 2008 and 2007, the rate was 4.29% and
8.22375%, respectively. The Company has no outstanding borrowings at
December 31, 2008, 2007 and 2006.




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. Market value adjustments and net settlements were recorded as a gain or
loss from non-designated hedging activities in other income and expense during
2006 and are shown in interest expense in 2007 and 2008.




For the
fiscal years ending December 31, 2008, 2007 and 2006 there were settlements
of approximately $449,000, $39,000, and $0, respectively and market value
adjustments resulting in a gains/(losses) of approximately $(1.8 million),
$(933,000) and $167,000, respectively.




Letters of
Credit




The
construction loan agreement provides for up to $1,000,000 in letters of credit
with the bank to be used for any future line of credit requested by a supplier
to the Plant. All letters of credit are due and payable at April
2012.  The construction loan agreement provides for the Company to pay
a quarterly commitment fee of 2.25% of all outstanding letters of credit. In
addition, the Company has one outstanding letter of credit for capital
expenditures for gas services with Montana-Dakota Utilities Co.  The
balance outstanding on this letter of credit was $137,000 as of December 31,
2008 and 2007, respectively.




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 (a total of 9.885% at December
31, 2008) and 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 April 2012.  The balance outstanding on
these loans was $5,525,000 as of December 31, 2008 and 2007,
respectively





7.
FAIR VALUE





Effective
January 1, 2008, the Company, adopted Statement of Financial Accounting Standard
No. 157, Fair Value
Measurements (SFAS 157), and Statement of Financial Accounting Standard
No. 159, The Fair Value Option
for Financial Assets and Financial Liabilities (SFAS
159).  SFAS 157’s requirements for certain nonfinancial assets and
liabilities recognized or disclosed at fair value on a nonrecurring basis are
deferred until fiscal years beginning after November 15, 2008 in accordance with
FASB Staff Position 157-2 (“FSP 157-2”).




SFAS 157
defines fair value, outlines a framework for measuring fair value, and details
the required disclosures about fair value measurements. The adoption of SFAS 157
did not have a material effect on the Company’s financial position, results of
operations, or cash flows for 2008.




F-15


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


SFAS 159
permits 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, as permitted by
SFAS 159.




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.





December
      31, 2008Fair
      Value Carrying Amount in the Balance
            
            
            Fair
      Value Measurement UsingSheet
            
            
            Level
      1
            
            
            Level
      2
            
            
            Level
      3AssetsMoney
      market funds (included in cash equivalents)
            
            $
            4,366,121
            
            
            $
            4,366,121
            
            
            $
            ―
            
            
            $
            ―Corn
      and ethanol related derivative instruments
            
            
            447,739
            
            
            
            447,739
            
            
            
            ―
            
            
            
            ―Total
            
            $
            4,813,860
            
            
            $
            4,813,860
            
            
            $
            ―
            
            
            $
            ―LiabilitiesInterest
      rate swap
            
            $
            2,861,530
            
            
            $
            ―
            
            
            $
            2,861,530
            
            
            $
            ―Total
            
            $
            2,861,530
            
            
            $
            ―
            
            
            $
            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.




8.
LEASES




The
Company leases equipment under operating and capital leases through 2011. 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 $356,000, $27,000 and $11,000
for the years ending December 31, 2008, 2007 and 2006, respectively.
Equipment under capital leases consists of office equipment and plant
equipment.




Equipment
under capital leases is as follows at:




As
      of December 31,
              
              2008
              
              
              2007Equipment
              
              $
              216,745
              
              
              $
              216,745Accumulated
      amortization
              
              
              45,996
              
              
              
              23,296Net
      equipment under capital lease
              
              $
              170,749
              
              
              $
              193,449
  F-16
 Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


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




As
      of December 31, 2008
              
              Operating
      Leases
              
              
              Capital
      Leases2009
              
              $
              489,660
              
              
              $
              61,7012010
              
              
              489,660
              
              
              
              46,6342011
              
              
              470,305
              
              
              
              ―2012
              
              
              416,400
              
              
              
              ―2013
              
              
              34,700
              
              
              
              ―Total
      minimum lease commitments
              
              $
              1,900,725
              
              
              
              108,335Less
      amount representing interest
              
              
              
              
              
              
              6,855Present
      value of minimum lease commitments included in preceding long-term
      liabilities
              
              
              
              
              
              $
              101,480


9.
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 2008, 15,000 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 10.  As of December 31, 2008 and 2007 there 40,188,973
and 40,173,973 units issued and outstanding, respectively.




10.
EQUITY-BASED COMPENSATION




2006 Equity-Based Incentive
Plan




During
2006, the Company implemented an equity-based incentive plan (the “Plan”) which
provides for the issuance of restricted Class A Membership Units to the
Company’s key management personnel, for the purpose of compensating services
rendered. These units have vesting terms established by the Company at the time
of each grant. Vesting terms of outstanding awards begin after one to three
years of service and are fully vested after ten years of service which is the
contractual term of the awards. During 2007, the Company exercised the option to
repurchase 200,000 units in association with this Plan.  The units
will be held in treasury until the vesting requirements of the Plan have been
met.  For the years ended December 31, 2008 and 2007, equity based
compensation expense was approximately $22,000 and $20,000,
respectively.  As of December 31, 2008, the total equity-based
compensation expense related to nonvested awards not yet recognized was
$135,000, which is expected to be recognized over a weighted average period of
7.5 years.




11.
GRANTS




In 2006,
the Company entered into a contract with the State of North Dakota through its
Industrial Commission (the “Commission”) for a lignite coal grant not to exceed
$350,000.  In order to receive the proceeds, the Company was required
to build a 50 MMGY ethanol plant located in North Dakota that utilizes clean
lignite coal technologies in the production of ethanol.  The Company
also had to provide the Commission with specific reports in order to receive the
funds including a final report (the “Final Report”) six months after ethanol
production began.  After the first year of operation, the Company will
be required to repay a portion of the proceeds in annual payments of $22,000
over ten years.  The payments could increase based on the amount of
lignite coal the Company is using as a percentage of primary
fuel.  The Company received $275,000 from this grant in
2006.  During the first quarter of 2007, the Company experienced
issues with the delivery and quality of lignite coal under the lignite supply
agreement as well as combustion issues with the coal combustor.  The
Company terminated the contract for lignite coal delivery in April 2007 due to
the supplier’s failure to deliver lignite coal as required by the
contract.  At that time, the Company entered into short term delivery
for powder river basin (“PRB”) coal as an alternative to lignite
coal.  During December 2007, The Company extended its PRB coal
agreement for two additional years as the Company continues to try to resolve
the issues experienced while running the Plant on lignite coal.  Due
to the temporary nature of the Company’s use of PRB coal, the grant terms remain
consistent with that described above; however, a permanent change to a primary
fuel source other than lignite coal may accelerate or increase the repayment of
these amounts.  The Company intends to use lignite coal in the future
if delivery, pricing, quality and performance issues can be resolved
favorably.  Because the Company has been temporarily using PRB coal,
it made a formal request to extend the Final Report deadline from June 30, 2007
to August 31, 2007.  The Company received the extension but has not
yet returned to using lignite coal nor filed the Final Report.  In
place of the Final Report, the Company filed a memo with the Commission updating
them on the status of using lignite coal at its Plant for 2007.  This
included supplying information on what percentage lignite coal was of the
Company’s total coal usage (on a BTU basis) for 2007 and 2008.  For
2007 and 2008, the Company did not meet the minimum lignite usage specified in
the grant contract.  Based on that information, the Company expects
the Commission to notify it that the Company will have to repay the grant at an
accelerated rate of $35,000 per year for every year the Company does not meet
the specified percentage of lignite use as outlined in the grant.  The
Company has remained in contact with the Commission about the current state of
the Plant as well as future intentions to run on lignite coal.




F-17


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


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 $73,000 and $0 for the
fiscal years ended December 31, 2008 and 2007, respectively.




In
additional to the Job Services North Dakota training program, the Company
entered into a contract on October 2, 2006 with Job Service North Dakota
for the Workforce 20/20 program. The program assists North Dakota employers in
training and upgrading workers’ skills. Under this program, the Company received
and earned $27,750 in 2007 and $0 in 2008.




12.
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.  During the first four months of operation, however, the Plant
experienced numerous shut downs related to running on lignite
coal.  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.  The Company continues to work with Fagen to find a
solution to these issues. 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.




Under the
terms of the MA, Greenway provides management of day to day plant operations.
For these services the Company will pay 4% of the Company’s pre-tax net income
plus $200,000 per year once the Plant is in reasonable compliance with the
engineer’s performance standard.  In addition, the Company will
reimburse Greenway Consulting for the salary and benefits of the General Manager
and Plant Manager.   The agreement has a five year term which
expires December 31, 2011 unless either party terminates this agreement upon a
default of the other after thirty days written notice.   As of
January 1, 2009, the Company began withholding payment of amounts owed to
Greenway under the MA until resolution to certain contractual items is
resolved.  For the years ended December 31, 2008 and 2007, the Company
had expensed approximately $534,000 and $552,000, respectively for management
services under the MA and has also expensed approximately $288,000 and $326,000,
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 $2,500 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, 2008, 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 agreement calls for a facility charge of $400 per month and an energy charge
of $0.038 per kWh for the first 400,000 kWh and $0.028 per kWh thereafter. In
addition, there is an $8.00 per kW monthly demand charge based on the highest
recorded fifteen minute demand.




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 $2.49 per one thousand gallons for the year ended
December 31, 2008.  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 requires 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. If the volume of natural gas used by the Company
exceeds volume projections, the Company will earn a refund of the preliminary
cost participation requirement and interest at 12% annually.




F-18


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


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.  The Company
currently pays RPMG $.01 per gallon for each gallon RPMG sells, per the terms of
the agreement.  This fee will decrease to approximately $.005 per
gallon once the Company’s ownership buy-in is complete, which it expects to
occur during 2009.




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.  Under the terms of the agreement, the price of coal is set at
$14.32 per ton for 2008 and $14.75 per ton for 2009.  The Company has
withheld $3.9 million from the general contractor pending resolution of this
issue with the coal combustor.  While PRB coal is more expensive than
lignite coal, the Company believes running on PRB coal may actually be the same
cost or slightly lower cost than running on lignite coal when the Company
factors in the additional operating costs associated with running on lignite
coal.  As a long-term solution, the Company is working with its
contractors to find ways to modify the coal combustor so that the Plant can
continue using lignite coal. If the Company cannot modify the coal combustor to
use lignite coal, it 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 the Company needs will always be
delivered as the Company needs it, that the Company will receive the proper size
or quality of coal or that the Plant’s coal combustor will always work properly
with lignite coal. Any disruption could either force the Company to reduce its
operations or shut down the Plant, both of which would reduce the Company’s
revenues.




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 accord 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.




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,
2008 for a one year term.




F-19


Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


Natural Gasoline
Contract




The
Company has entered into various contracts with Quadra Energy Trading Inc. for
the purchase of natural gasoline. The term of the most recent contract is
January 2009 through April 2009.  The price is based off the average
Conway natural gas price plus $0.35.




Leases




As part
of entering into the new distillers grain marketing agreement described above,
the Company entered into an assignment and assumption agreement with CSC in
April 2008 to assume a rail car lease that CSC entered into with Trinity
Industries Leasing Company.  The rail cars are used for the transport
of DDGs.  Five quadruple covered hopper cars are leased at a rate of
$691 per car, per month through November 5, 2011.  Fifty quadruple
covered hopper cars are leased at a rate of $694 per car, per month through
January 31, 2013.




The
Company entered into an operating lease in July 2006 for the lease of a
locomotive. The term of the contract is for a period of five years commencing
upon delivery. The monthly rental amount is $2,650.




In
September 2006, the Company entered into an agreement for office equipment
under a long-term capital lease agreement valued at $10,245. The contract
requires monthly payments of approximately $200 over a period of five
years.




The
Company entered into an agreement for a 2004 CAT Loader with Merchants Capital
under a long-term capital lease agreement valued at $112,500. The contract
requires monthly payments of approximately $2,730 over a period of four
years.




The
Company entered into an agreement for a telescopic handler with Butler Machinery
under a long-term capital lease agreement valued at $94,000. The contract
requires monthly payments of approximately $2,195 over a period of four years
starting on October 15, 2006.




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, 2008, the Company had various fixed and basis contracts for
approximately 4.1 million bushels of corn.  Of the 4.1 million bushels
under contract, approximately 1.7 million bushels had a fixed price as of
December 31, 2008.  We anticipate taking delivery of the corn under
fixed price contracts under the following time frame: approximately 65% in
January 2009 and approximately 35% spread throughout the rest of 2009,
respectively.  Using the stated contract price for the fixed contracts
and using market prices, as of December 31, 2008, to price the basis contracts
the Company had commitments of approximately $18.9 million related to all 4.1
million bushels under contract.




13.  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 $56,000 and $59,000 for fiscal years ended December 31, 2008 and
2007, respectively.




14.
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.  RPMG has been considered a related party since January 1, 2008
when the Company became a partial owner in RPMG.  As such, the amounts
below as of December 31, 2007 have been restated to include transactions with
RPMG.  The amounts previously reported, excluding RPMG, as of December
31, 2007 for accounts receivable and accounts payable were $293,468 and
$1,471,479, respectively.  Revenue and cost of goods sold, as
previously reported, for year ending December 31, 2007, were $2,323,263 and
$2,673,605, respectively.  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.  Significant related party
activity affecting consolidated financial statements are as
follows:




As
      of December 31,
                      
                      2008
                      
                      
                      2007Balance
      SheetAccounts
      receivable
                      
                      $
                      2,198,277
                      
                      
                      $
                      2,757,476Accounts
      payable
                      
                      
                      788,149
                      
                      
                      
                      2,088,561Notes
      payable
                      
                      
                      1,525,000
                      
                      
                      
                      1,525,000Statement
      of OperationsRevenues
                      
                      $
                      117,379,764
                      
                      
                      $
                      94,411,004Cost
      of goods sold
                      
                      
                      2,712,392
                      
                      
                      
                      3,166,836General
      and administrative expenses
                      
                      
                      1,087,552
                      
                      
                      
                      878,021Inventory
      Purchases
                      
                      $
                      9,669,953
                      
                      
                      $
                      6,476,508
  F-20
 Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006


15.
INCOME TAXES




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




As
      of December 31
              
              2008
              
              
              2007Financial
      Statement Basis of Assets
              
              $
              94,751,401
              
              
              $
              108,524,254Organization
      and start-up costs
              
              
              5,141,445
              
              
              
              5,668,245Inventory
      and compensation
              
              
              34,458
              
              
              
              195,235Book
      to tax depreciation
              
              
              (19,293,573
              )
              
              
              (5,543,566
              )Book
      to tax derivative difference
              
              
              (2,371,800
              )
              
              
              (262,715
              )Income
      Tax Basis of Assets
              
              $
              78,261,931
              
              
              $
              108,581,453Financial
      Statement Basis of Liabilities
              
              $
              61,192,396
              
              
              $
              69,620,771Loss
      on firm purchase commitment
              
              
              1,426,800
              
              
              
              ―Interest
      rate swap
              
              
              (2,861,529
              )
              
              
              (933,256
              )Income
      Tax Basis of Liabilities
              
              $
              59,757,667
              
              
              $
              68,687,515


16.
QUARTERLY FINANCIAL DATA (UNAUDITED)




Summary
quarter results are as follows:




Statement
      of Operations
                For
      the quarters ended,
              
              March
      2008
              
              
              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 (loss)
              
              $
              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 - fully 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 - fully diluted
              
              $
              0.07
              
              
              $
              0.13
              
              
              $
              (0.09
              )
              
              $
              (0.24
              )
  For
      the Quarters ended,
              
              March
      2007
              
              
              June
      2007
              
              
              September
      2007
              
              
              December
      2007Revenues
              
              $
              18,934,975
              
              
              $
              30,247,829
              
              
              $
              27,329,379
              
              
              $
              25,373,786Cost
      of goods sold
              
              
              15,118,165
              
              
              
              25,877,011
              
              
              
              24,703,796
              
              
              
              21,314,236Gross
      profit
              
              
              3,816,810
              
              
              
              4,370,818
              
              
              
              2,625,583
              
              
              
              4,059,550General
      and administrative expenses
              
              
              847,796
              
              
              
              881,109
              
              
              
              568,223
              
              
              
              916,874Operting
      income (loss)
              
              
              2,969,014
              
              
              
              3,489,709
              
              
              
              2,057,360
              
              
              
              3,142,676Interest
      Expense
              
              
              1,149,528
              
              
              
              969,088
              
              
              
              2,087,460
              
              
              
              2,062,632Other
      income (expense)
              
              
              (46,178
              )
              
              
              82,059
              
              
              
              262,979
              
              
              
              468,417Net
      income
              
              $
              1,773,308
              
              
              $
              2,602,680
              
              
              $
              232,879
              
              
              $
              1,548,461Weighted
      average units - basic
              
              
              40,373,973
              
              
              
              40,373,973
              
              
              
              40,373,973
              
              
              
              40,373,973Weighted
      average units - fully diluted
              
              
              40,403,973
              
              
              
              40,408,973
              
              
              
              40,413,973
              
              
              
              40,418,973Net
      income (loss) per unit - basic
              
              $
              0.04
              
              
              $
              0.06
              
              
              $
              0.01
              
              
              $
              0.04Net
      income (loss) per unit - fully diluted
              
              $
              0.04
              
              
              $
              0.06
              
              
              $
              0.01
              
              
              $
              0.04


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-21
 Red
Trail Energy, LLC
  Notes to
Financial Statements
  December
31, 2008, 2007 and 2006
  17.
SUBSEQUENT EVENTS




·
            In
      an effort to diversify its revenue stream, the Company entered into an
      agreement in March 2008 to operate third party corn oil extraction
      equipment that will be added to its facility.  The agreement has
      a term of 10 years commencing from the date when the equipment
      installation is complete.  As of March 15, 2009, corn oil
      extraction equipment had not yet been installed at the Company’s
      facility.  The third party that the Company contracted with ran
      into financing issues.  Late in 2008 they received approval for
      their financing package contingent on certain conditions being
      met.  As part of the financing arrangement, the terms of the
      original contract entered in to in March 2008 were changed
      significantly.  The Company is currently in negotiations with
      the third party related to several of the terms that
      changed.  We currently do not have a time frame for when the
      corn oil extraction equipment may be installed at our facility.




·
            We
      have been notified by FNBO that we were in violation of certain of the
      covenants in our loan agreements at December 31, 2008 and that we were
      granted a waiver of these covenant violations.  These include
      the covenants requiring a minimum working capital balance, minimum net
      worth and a minimum fixed charge coverage ratio.  See Note 3 for
      further discussion.




F-22