U.S. SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549  FORM 10-KSB  Annual Report Under the Securities Exchange Act of 1934  For Fiscal Year Ended: December 31, 2006  Commission File Number: 000-51564  NORTHERN ETHANOL, INC (Exact name of small business issuer as specified in its charter)  Delaware (State or other jurisdiction of incorporation)  34-2033194 (IRS Employer ID No.)  193 King Street East Suite 300 Toronto, Ontario, M5A 1J5, Canada (Address of principal executive offices)  (416) 366-5511 (Issuers Telephone Number)  Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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 ____.  The number of shares of the registrants only class of common stock issued and outstanding as of April 17, 2007, was 104,096,500 shares.  Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) ____ YesxNo  Documents Incorporated by Reference: Portions of the Companys Definitive Proxy Statement for the Annual Meeting of Shareholders to be held June 6, 2007, are incorporated by reference in certain sections of Part III.       TABLE OF CONTENTS  PAGEPART IItem 1.

Description of Business

3Item 2.

Description of Properties

18Item 3.

Legal Proceedings

18Item 4.

Submission of Matters to a Vote of Security Holders

18PART IIItem 5.

Market For Common Equity and Related Stockholder Matters

19Item 6.

Managements Discussion and Analysis of Financial Condition

and Results of Operations

19Item 7.

Financial Statements

44Item 8.

Changes In and Disagreements With Accountants on Accounting andFinancial Disclosure

70Item 8A.

Controls and Procedures

70Item 8B.

Other Information

71PART IIIItem 9.

Directors and Executive Officers

72Item 10.

Executive Compensation

72Item 11.

Security Ownership of Certain Beneficial Owners and Management andRelated Stockholder Matters

72Item 12.

Certain Relationships and Related Transactions

72Item 13.

Exhibits

72Item 14.

Principal Accountant Fees and Services

73Signatures

74           2       PART I  ITEM 1.
DESCRIPTION OF BUSINESS  Northern Ethanol, Inc. (we, us, our or the Company) was incorporated as Beaconsfield I, Inc. in the State of Delaware on November 29, 2004 as a blank check company for the purpose of engaging in the potential future merger or acquisition of an unidentified target business. In April 2006 our then Board of Directors elected to change our business plan to the development and operation of ethanol plants in Canada, with the goal of becoming a leading, low cost supplier of ethanol to the Central Canada and Eastern United States fuel market.  On December 15, 2004, we issued 150,000 shares of our Common Stock for a total of $15 in cash. Additionally on that date, we issued 10,000,000 shares (pre-forward split) of our Common Stock, for a total of $50,000 in cash.  In April 2006, in conjunction with the adoption of our new business plan, we retained new management, including Mr. Gordon Laschinger, our Chief Executive Officer, President and Chairman of the Board of Directors. In July 2006, Mr. Steven Reader agreed to become our Chief Operating Officerand in November 2006, Mr. Richard Smith became our Chief Financial Officer. From inception we have been engaged in organizational efforts and obtaining financing. During the period from April through September 2006, we also reconstructed our Board of Directors, adding five persons to our Board and accepting the resignation of one of our former directors. As a result, our current Board of Directors consists of six members, including four who are considered outside directors.SeePART III, ITEM 9, DIRECTORS AND
EXECUTIVE OFFICERS.  In July 2006, we engaged in a forward split of our Common Stock whereby we issued ten (10) shares of our Common Stock for every one (1) share then issued and outstanding. All references in this Report to our issued and outstanding Common Stock are provided on a post forward split basis, unless otherwise indicated. Also in July 2006, the holders of a majority of our then issued and outstanding Common Stock approved an amendment to our Certificate of Incorporation wherein we did change our name to Northern Ethanol, Inc. to better reflect our current business plan.  In July 2006, we commenced a private offering of our Common Stock. This offering was successfully closed in September 2006. We sold an aggregate of 4,096,500 shares of our Common Stock to 48 accredited investors (as that term is defined in both the Canadian and U.S. securities laws) at a price of $1.00 per share and received aggregate net proceeds of $3,846,500 therefrom. Two of these investors are residents of the United States, with the balance residents of Canada. The proceeds derived from this offering have been utilized to fund the planning efforts relating to development of two ethanol plants to be located in Ontario, Canada, as well as for working capitalto the date of this Report.We will require additional funds in order to implement our business plan described herein.SeePART II, ITEM
6, MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RISK FACTORS.  On October 12, 2006, we filed a registration statement on Form SB-2 with the US Securities and Exchange Commission (the SEC) wherein we are attempting to register all of the shares of our Common Stock issued in the aforesaid private offering. We anticipate filing our Amendment No. 2 to our registration statement shortly following the filing of this Report. Upon effectiveness of this registration statement, we will attempt to have our Common Stock listed for trading on the OTC Bulletin Board operated by the NASD. There are no assurances that our Common Stock will be approved for trading.  3      SeePART II, ITEM 5, MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS and PART II, ITEM 6, MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RISK FACTORS.  As of the date of this Report, we have two wholly-owned subsidiaries, Northern Ethanol, LLC, a New York limited liability company (NELLC), and Northern Ethanol (Canada) Inc., a Canadian corporation, which has three wholly-owned subsidiaries, Northern Ethanol (Barrie) Inc., Northern Ethanol (Sarnia) Inc. and Northern Ethanol Investments Inc., (NEI) each of which is also a Canadian corporation. All references to our Company in this Report include our subsidiaries, unless otherwise indicated. NELLC and NEI are currently dormant companies.  We are a development stage company and are devoting substantially all of our efforts to establishing a business of manufacturing fuel ethanol for sale to oil refiners and other users. We have secured or are in the advanced stages of securing sites to build ethanol processing facilities at two locations in Ontario, Canada, for total planned production capacity of 216 million US gallons per annum. Each of these locations will be the site for a state-of-the-art corn based ethanol processing facility.  We are implementing a strategy to grow by:  
Building state of the art processing plants;  
Negotiating stable long term contracts with key suppliers;  
Securing long term sales agreements;  
Pursuing acquisitions of existing ethanol producers  
Pursuing acquisitions and/or strategic alliances with ethanol technology companies  We are committed to investing in the latest technology to ensure that the processing costs are as low as possible, and the outputs are of the highest quality. The initial locations have been chosen due to proximity to supply of corn, natural gas, and water, and are well located for the transportation of inputs and products.  Effective July 24, 2006, we entered into a five-year Project Development Agreement (the Delta-Barrie Agreement) with Delta-T Corporation, Williamsburg, Virginia (Delta), wherein Delta shall provide us professional advice, business and technical information, design and engineering and related services in order to assist us in assembling all of the information, permits, agreements and resources necessary for construction of an ethanol plant having the capacity to produce 108 million gallons per year in Barrie, Ontario, Canada. We paid Delta the non-refundable sum of $100,000 in advance for all such services.  In September 2006, we entered into a similar five-year agreement with Delta relating to our proposed Sarnia ethanol plant (the Delta-Sarnia Agreement) and paid Delta an initial non-refundable amount of $70,000 for such services, with the balance of $30,000 due upon issuance of an air permit by the Province of Ontario. References to the Delta-Barrie Agreement and Delta-Sarnia Agreement are hereinafter jointly referred to as the Delta Agreements, unless otherwise indicated.  The Delta Agreements provide for Delta to assist us in the development and analysis of the operating costs, plant specifications, compliance with environmental issues, product marketing, industry  4      economics, technical and other assistance. Deltas sole remedy in the event that we breach theDelta Agreements is limited to the non-refundable fees of $100,000 paid under each of the agreements. The relationship between Delta and us is deemed exclusive during the five-year term of the Delta Agreements whereby we agreed to use our best efforts to enter into an EPC contract or a technology agreement with Delta at these locations and if we fail to do so, to give them a first right of refusal for 60 days to assume any agreements made with other ethanol plant technology vendors.  On March 9, 2007, we executed a term sheet with Aker Kvaerner Songer Canada Ltd. (AKSC) for the development of an engineering, procurement and construction (EPC) contract for the Barrie site. We are obligated to pay a non-refundable fee of $500,000 to AKSC for executing the term sheet and we will pay AKSC a further non-refundable fee of $500,000 in June 2007 on receipt of the fixed EPC contract price for our Barrie plant. Providing the EPC contract price is acceptable and financing is obtained, we expect to execute the EPC contractwithin 60 days of receiving the fixed EPC contract price and commence construction at the Barrie site immediately thereafter.  We also expect to enter into a similar arrangement with AKSC for the Sarnia location during 2007. We have not received a term sheet from AKSC regarding the Sarnia facility at this time. AKSC is a multinational EPC firm with extensive experience erecting and constructing facilities in Canada. Deltas primary role in the projects will be to provide the process technology and engineering. This will include all of the prime processes in the receiving and milling of the corn, the cook process, fermentation process, distillation process, molecular sieve and centrifuge process, chemical storage area, fuel and ethanol storage and load-out as well as DDGS drying, storage and load-out. AKSC will erect the Delta process components as well as engineer, procure and construct the balance of plant equipment for such items as the boiler house, cooling towers, all utility tie-ins, plant fire water system, and any
water treatment systems. Under the EPC contract, AKSC will be responsible for all labor supply and project completion risk (i.e. project completed on schedule, at the contract price, meeting design specifications). The EPC contract will be guaranteed by AKSCs parent company, Aker Kvaerner ASA of Baerum, Norway, a leading global provider of engineering and construction services, technology products and integrated solutions with NOK14 billion (approximately $2.3 billion) in annual revenue. The Delta plant design that we have selected is based on plant designs and components currently being utilized by other Delta customers. Any differences in our plant designs from the standard Delta design will be to provide for higher reliability and performance. Not all current projects undertaken by Delta appear on their website due to client preferences with regards to confidentiality.  In August 2006, we retained the services of the engineering firm of Charles G. Turner & Associates for an initial term to December 31, 2006, to monitor the design, equipment selection, construction and commissioning phases of the projects on an hourly fee basis. As of the date of this Report, this agreement is continuing on a month-to-month basis.  Also in August 2006, we contracted with Parrish & Heimbecker Ltd. (P&H) to provide corn procurement and co-product merchandizing services for our proposed Barrie and Sarnia ethanol plants upon the opening of such plants. P&H is a privately held grain merchant corporation that owns and operates grain elevators and has extensive domestic and international experience in international grain origination and co-product merchandizing. We engaged them to source all of the corn required for the operation of the Barrie and Sarnia ethanol facilities at competitive prices. We expect they will assist us in negotiations with major corn suppliers to guarantee supply and price by committing to long-term purchase agreements or opportunistic purchases on the spot market when this can be done at favorable rates. We will pay P&H C$1.00 (all references to Canadian dollars herein are designated
as C$) per metric ton of corn procured for our Barrie and Sarnia operations. P&H will manage the sale of our dried distiller grain by-product. We will pay P&H C$1.00 per metric ton of DDGS sold for marketing the sale of our product.  5       We are currently in the process of finalizing contracts covering the Barrie and Sarnia facilities with ECO Energy Inc., a privately held Tennessee corporation that provides ethanol marketing capability across North America (ECO). ECO is a fully integrated marketing company supported by an experienced sales force, a knowledgeable logistics and scheduling department, customer service, and an online computer system that we will be able to access to streamline all necessary correspondence for daily shipments and transportation transactions. We expect to engage this marketing company to handle the sales and transportation logistics of our ethanol production.  In addition, we will also sell a portion of the CO2 co-produced, with the balance either vented, or recovered for disposal.  We will be engaged in the business of producing ethanol in Ontario and selling it in Central Canada and the Eastern United States. While no assurances can be provided, we anticipate that the long-term growth in demand for ethanol will ensure a strong market for all of the output of our facilities.  Barrie, Ontario, Canada  In April 2006, we executed a 25-year lease, with two ten-year renewal options, on a 35 acre site located in Barrie, Canada. This location is a former beer brewery operated by Molson Canada that was decommissioned in 2000. The Barrie location is well suited for ethanol production due to its close proximity to Torontos gasoline markets, has excellent rail and road transportation access, is within close driving distance of a Great Lakes terminal and has readily available water, electricity and natural gas. The lease allows us to utilize all existing site infrastructure and to demolish or modify existing structures to optimize plant operations.  Sarnia, Ontario, Canada  In July 2006, we executed a non-binding Letter of Intent to acquire a 99 year lease on an industrial site in Sarnia, Canada to host a 108 million gallon ethanol production facility. The site comprises approximately 30 acres and is part of an existing site of a multinational chemical company. We also expect to enter into an agreement with a local provider of steam for use in the production of ethanol at this site on terms that are expected to be materially favorable compared to the costs of generating the steam from our own equipment. The site is located on a major rail line, has access to a waterway dock, has excellent highway access and is fully zoned and serviced with existing utility connections. From this location, we believe we will be in a strong position to serve the ethanol markets of Michigan, Ontario, Ohio, New York and other Northeastern U.S. metro areas.  Each of these locations will be the site for a dry mill processing facility, using corn as the feedstock. The construction period for each is expected to be approximately 20 months. We will begin construction at each location as soon as we are able to secure all the necessary financing to complete construction of each facility. We expect this financing to take the form of both debt and equity. However, it is our intention to use leverage to the greatest extent feasible as is typical with larger energy infrastructure projects.  Effective December 13, 2006, we executed an engagement letter and indicative term sheets with West LB AG (WestLB) whereby WestLB has conditionally agreed to solicit and arrangesenior debt and subordinate debt financing (to a maximum of approximately $365 million) for up to 75% of the construction costs of our Barrie and Sarnia facilities on a best efforts basis. The term best efforts means that West LB believes that they can syndicate the debt financing we require but that there is no guarantee that they will be successful or that the terms will be as indicated in their term sheets until they  6      market the transaction and receive firm commitments from a syndicate of lenders for the funds required on acceptable terms to the Company. Among other things, the provision of 75% financing in accordance with the terms of the engagement letter and indicative term sheets is conditional on our obtaining subordinate debt or equity investment for the remaining 25% of construction costs. The WestLB indicative term sheets offer first priority senior secured construction and term financing for up to 60% of the total capital requirements of plant construction and for working capital for a total term of up to 7.5 years and subordinated secured construction and term financing for up to 15% of the total capital requirements of plant construction for a total term of up to eight years. Following conversion of the senior construction loan to a senior term loan, the loan amount is to be repaid in equal quarterly installments over six
years. Surplus cash as defined by debt service covenant is to be swept to accelerate the repayment of the senior term loan and to repay the subordinated term loan. We paid a non-refundable retainer deposit of $200,000 to WestLB on execution of the engagement letter and indicative term sheets. In the event that we chose to terminate the WestLB engagement and we enter into a similar debt financing with another lender within 12 months of terminating WestLB, we will pay WestLB a termination fee of $5,000,000 if termination occurs within 60 days from December 13, 2006, and $10,000,000 thereafter. If the financing contemplated in the engagement letter and indicative term sheets is finalized with WestLB, we will pay to WestLB a structuring and arrangement fee of the greater of $5,000,000 or 2% of the principal amount of the senior financing and $5,000,000 or 2% of the principal amount of the subordinated financing. In addition, we will pay a fee to market the senior and subordinate loans of 1% of the
principal amount of each. The interest rate on the senior financing will be at LIBOR plus an anticipated spread of 325 to 350 basis points. Until the senior loan has been fully drawn, we shall pay a commitment fee of 0.50% on the undrawn portion. The interest rate on the subordinate financing will be at LIBOR plus an anticipated spread of 1000 basis points. As the subordinate financing will be fully drawn on closing there will be no commitment fees applicable on that facility. We expect other covenants, representations and warranties will form part of the final documentation on closing of the loan agreement. We have had discussions with investment bankers, financial institutions and private investors about obtaining this 25% subordinate debt or equity investment but as of the date of this Report we have received no binding commitments. We may not be able to obtain sufficient funding from one or more investors or other financial institutions, or if such funding is obtained, that it will be on terms
that we have anticipated or that are otherwise acceptable to us. If we are unable to secure adequate financing, or financing on acceptable terms is unavailable for any reason, we may be forced to abandon our construction of one or more, or even all, of our planned ethanol production facilities.  In order to allow us to continue to implement our business plan, on March 30, 2007, we entered into a Line of Credit Agreement with Union Capital Trust, Nassau, Bahamas (Union) wherein Union has agreed to provide us with a $6 million unsecured line of credit. Interest accrues at the rate of twelve percent (12% per annum) and is payable monthly. Principal and unpaid interest is due on or before March 30, 2008. As of the date of this Report, we have drawn down an aggregate of $469,000 on this line of credit. We have not finalized the balance of the required financing and there are no assurances that we will obtain this financing. Failure to obtain the necessary financing will have a significant negative impact on our proposed operations. (SeePART II, ITEM 6, MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS RISK FACTORS.)  Upon our successful construction of multiple manufacturing facilities in Canada, we expect to realize significant cost savings in raw materials purchasing, transportation, engineering and operations that will provide a profitability advantage vis-à-vis other smaller and single-site ethanol producers because of the opportunity to centralize key functions including risk management, procurement and executive management. Also we expect that these multiple sites will provide us with greater influence in plant design and new technologies, as well as access to capital markets. However, there can be no assurances that our expectations will be met and we will, in fact, realize these benefits.   7       The manner in which we will develop future sites beyond the initial aforementioned locations will depend upon the nature of the opportunity, the respective needs of the parties involved, and our then corporate objectives. We have set up a separate wholly owned subsidiary to own each ethanol plant. We may purchase ethanol producing facilities outright, acquire an ownership interest in companies controlling existing ethanol producing facilities, issue shares in a subsidiary company that controls the site to outside parties who control ethanol producing facilities, or some other unidentified transactional structure.  We are also actively exploring opportunities to make strategic acquisitions of existing or pending ethanol production facilities where our management determines that the acquisition represents an opportunity to accelerate our expansion goals. On March 27, 2007, we entered into a non-binding letter of intent with Quad County Corn Processors Cooperative, Galva, Iowa (Quad), wherein we have agreed in principle to acquire most of the assets and liabilities of Quad, including its existing ethanol plant (current annual ethanol production of 28 million gallons) for the purchase price of $105 million. The purchased assets shall exclude Quads cash on hand and on deposit and all insurance policies pertaining to the business. The liabilities exclude Quads long-term indebtedness and the current portion of long-term indebtedness. The exact form of the proposed acquisition has not yet been
determined, as it may be an asset acquisition, merger or some other form. We are currently discussing this issue with Quads management. The structure of this acquisition will depend upon the most favorable tax consequences to both Quad and us. The proposed purchase price shall be payable by our delivery of a certified check or other good funds in the amount of $78,750,000, representing 75% of the proposed purchase price, plus the issuance by us of a 5.5% Convertible Subordinated Debenture (the Debenture) in the principal amount of $26,250,000. The Debenture shall mature two (2) years from the Closing Date, unless converted by Quad, in whole or in part. Quads right to convert shall commence six (6) months from the Closing Date and terminate upon payment in full of the Debenture. The Debenture may be converted into shares of our Common Stock at a conversion price (subject to adjustment for stock splits or other recapitalization after the date hereof) equal to the greater of $1.00
per share or a Formula Price per share (as defined in the letter of intent). Interest shall be due and payable semi-annually. The first payment shall be due on the six-month anniversary of the Closing Date. No prepayment penalty provision shall be included in the Debenture. At Quads option, it may elect to increase the amount of the Debenture to $42,000,000 (40% of the purchase price) with the cash payment due at the Closing Date reduced by like amount, provided that Quad shall make such election prior to May 15, 2007. We have the right to redeem the Debenture, upon 30 days prior written notice to Quad, on or after March 31, 2008. We have agreed to register the Common Stock issuable under the Debenture with the Securities and Exchange Commission on or before the 180th day following the Closing Date. The holder(s) of the Debenture shall also have the right to convert and participate in any underwritten public offering of our Common Stock occurring anytime after the Closing Date;
provided, however, if the managing underwriter advises us that the inclusion of the converted Common Stock would interfere with the successful marketing (including pricing) of all such securities to be included in such registration, then the number of shares of Common Stock included in such offering, including the converted shares of Common Stock, shall be reduced pro rata. This proposed transaction is subject to due diligence, which is expected to take 60 days from the date of the letter of intent. We have been granted exclusivity on this project until completion of our due diligence and final closing of a definitive agreement between the parties. It is likely that we will finance our participation in this Quad opportunity and other business opportunities through the issuance of Common Stock or other securities and through the issuance of senior debt secured against the assets of each operating location.  In the case of an acquisition, the transaction may be accomplished upon the sole determination of management without any vote or approval by stockholders. In the case of a statutory merger or consolidation directly involving us, it will likely be necessary to obtain the approval of the holders of a majority of the outstanding shares. The necessity to obtain such stockholder approval may result in delay  8      and additional expense in the consummation of any proposed transaction and will also give rise to certain appraisal rights to dissenting stockholders.  We are continuously evaluating new technologies for reducing costs, providing greater manufacturing yields and improved energy balance. We are evaluating new technologies enabling the conversion of cellulose, predominantly from wood waste and agricultural waste, into ethanol that would reduce or eliminate our dependency on corn as a primary feedstock and help ensure a low cost production structure in the long-term. We regularly review and analyze developments and investment opportunities in cellulosic technology.  SALES AND MARKETING  Ethanol  According to the Renewable Fuels Association (http://www.ethanolRFA.org/industry/statistics/), between 90% and 95% of the ethanol in the U.S. is sold pursuant to six to twelve month contracts, negotiated between the ethanol producer and the oil refiner or gasoline blender. As such, we believe that we will not be able to rely on long-term (over one year) contracts for the sale of our product. Entering in to a long-term contract would require us to give the buyer a significant discount to current market prices. We believe that if and when we commence operations, it will be more profitable for us to sell into the spot market and through a mixture of short-term (less than one year) contracts. The Chicago Board of Trade launched an ethanol futures contract in March 2005. As of the date of this Report, there has been limited trading activity in ethanol futures.  We are currently in the process of finalizing contracts covering the Barrie and Sarnia facilities with ECO Energy Inc., a privately held Tennessee corporation that provides ethanol marketing capability across North America (ECO). ECO is a fully-integrated marketing company supported by an experienced sales force, a knowledgeable logistics and scheduling department, customer service, and an online computer system that we will be able to access to streamline all necessary correspondence for daily shipments and transportation transactions. We expect to engage this marketing company to handle the sales and transportation logistics of all our ethanol production. The selling price under these non-exclusive ECO agreements is expected to be relative to the local fuel wholesale (rack) unleaded gasoline daily spot market. By selling on a non-exclusive basis, we expect to benefit from being able to
sell into the market with the highest spot price at the time. Currently, forward contracting of ethanol sales is not a well-developed market.  Dried Distillers Grains and Solubles (DDGS)  According to the Renewable Fuels Association: Ethanol Industry Outlook 2006, the volume of North American DDGS output has tripled since 2001 to 9 million metric tons in 2005 with the growth in ethanol production. Data received from Agri-Link and Farm Market News at the University of Guelph, Ontario, shows that the price of DDGS per metric tonne in the Southern Ontario market since 2001 has ranged from a high of C$169 in January 2004 to a low of C$77 in September 2006. As at February 28, 2007, the price was C$143 per metric tonne in the Southern Ontario market.  DDGS are a protein ingredient in animal feed and as such, DDGS prices track very closely to the price of soybean meal, which is the most widely used protein source in livestock feed. Our biggest competition in this market comes from other nearby ethanol plants, as we hope to sell a portion of our DDGS in the local feed market. We plan on selling the balance of our DDGS to developed feed markets in the United States and Europe. It is expected that the price of DDGS will fluctuate relative to the market price of soybean meal, which is an actively traded commodity.  9       We have entered into a non-exclusive merchandizing agreement with Parrish & Heimbecker for all of our anticipated production volume for at least three (3) years. The selling price under this agreement is expected to be at the local and international spot market. By entering in to a non-exclusive agreement for the sale of DDGS, we will benefit from being able to sell into the market with the highest price at the time. In addition, this will allow us to sell to markets in both North America and Europe, depending on which is more profitable at the time of sale. We will pay Parrish & Heimbecker C$1.00 per metric ton of DDGS sold for marketing the sale of our product.  Carbon Dioxide (CO2)  We have entered into discussions with major local users ofCO2for the sale of ourCO2by-product. Carbon dioxide is sold principally to the food and beverages markets, and also to the industrial market. The CO2 market is very concentrated, with a large share of the supply coming from a few large players. To effectively compete in the CO2 market, producers must be located within a reasonable distance of the end user because transportation costs usually represent about 50% of the delivered price of CO2. The selling price under these agreements is expected to be at the local spot market. We expect a portion of theCO2production to be sold, with the balance either vented, or recovered for disposal.  INDUSTRY OVERVIEW  In 1908, Henry Ford commenced building the Model T and it had the ability to run on ethanol as well as gasoline.He had a vision of affordable fuel for North American drivers, which was to be produced by farmers and therefore would be a shot in the arm to rural economies.  Ethanol cuts the emissions of unburned hydrocarbons and carbon monoxide. There is a net reduction in harmful ozone forming emissions and greenhouse gases with the use of ethanol blended gasoline since growing corn removes carbon dioxide from the air and in the manufacturing process, carbon dioxide is extracted and commercially utilized. Ethanol use is approved by all vehicle manufacturers and is used across Canada and the United States.  Producing ethanol increases the supply of high protein animal feed ingredients through the distillation process; this creates new agricultural business opportunities centered on the plant, and helps offset imports of soybean meal and other animal feeds.  Fuel ethanol benefits the economy as well as the environment. Production of fuel ethanol in Canada (and around the world) has produced a new market for agricultural products, improving financial stability and security for farmers, in addition to direct and indirect employment opportunities from farming to transportation and manufacturing.  Brazil is a world leader in the use of fuel ethanol with nearly half of its cars operating on pure ethanol. In response to the oil crisis of the mid 1970s, the Brazilian government in cooperation with private industry created a national program to produce alcohol from sugar cane and to build ethanol compatible engines. Today, many countries around the world are testing oxygenated and (near 100%) alcohol fuels. In some parts of the U.S., projects are underway to test the viability of replacing diesel fuel with ethanol.  North American governments have been engaged in creating programs to encourage the use of ethanol to reduce dependence on oil, to achieve higher environmental standards and to stimulate rural economies and as a result, ethanol production has been growing steadily in recent years. The health of the  10      ethanol industry remains closely tied to government programs that provide tax incentives, tariff exemptions and regulatory mandates that favor ethanols use as a fuel additive.  Effective January 1, 2007, the Ontario Government has mandated a minimum average of 5% ethanol in gasoline as a way to support agriculture, improve air quality, and reduce dependence on petroleum. On December 20, 2006, the Canadian Federal government announced a regulation that will require all gasoline sold in Canada to have 5% renewable content by 2010. This legislation will create a substantially larger market than at present for fuel ethanol in Canada since ethanol is the primary renewal fuel option available  As illustrated in the following chart, ethanol fuel consumption in Canada grew substantially from approximately 50 million litres (13 million gallons) in 1997 to approximately 275 million litres (72 million gallons) in 2003. According to BBI International Media, as of November 2006, ethanol production capacity in Canada was approximately 162 million gallons, of which 108 million gallons was located in Ontario (http://www.ethanolproducer.com/plant-list.jsp?view=&country=Canada). The following chart shows publicly available data on Canadian ethanol production and consumption from 1996 to 2003.    1)
Economic, Financial, Social Analysis and Public Policies for Fuel Ethanol - Phase 1; Natural Resources Canada, November 2004 (http://www.greenfuels.org/ethanol/pdf/OConnor-Report-Ethanol-2004.pdf)  According to Statistics Canada (http://www.statcan.ca/Daily/English/060608/d060608e.htm), gasoline consumption in Canada in 2005 was 39.8 billion litres (10.5 billion gallons), of which 15.6 billion litres (4 billion gallons) was consumed in Ontario. Based on this, management estimates that ethanol demand in Ontario will reach approximately 780 million litres (200 million gallons) in 2007 due to the requirements of a 5% average Ontario ethanol blend. We believe that this will lead to an excess of demand over domestic supply in Ontario in 2007.  According to the Renewable Fuels Association (RFA) (http://www.ethanolrfa.org/industry/statistics/), the United States ethanol industry has experienced significant production growth in recent years from 1.3 billion gallons produced in 1996 to 3.9 billion gallons in 2005. Total U.S. demand for ethanol in 2005 was approximately 4.1 billion gallons. The  11      following chart has been developed by the Company from data obtained from the RFA and illustrates the growth in U.S. ethanol production from 1996 to 2005. US ethanol consumption data was only available from 2002 onward.    Ethanol is typically blended at 5% to 10% by volume in the United States, but is also blended at up to 85% (known as E-85) by volume for vehicles designed to operate on 85% ethanol. Compared to gasoline, ethanol is generally considered to be less expensive and cleaner burning. Ethanol is widely marketed across the United States as a high quality octane enhancer and oxygenate capable of reducing air pollution and improving automobile performance. In spark ignition engines, ethanol emits significantly less carbon monoxide and air toxic pollution than gasoline therefore reducing the amount of harmful emissions released into the atmosphere. We anticipate that the increasing demand for transportation fuels coupled with limited opportunities for gasoline refinery expansions and the growing importance of reducingCO2emissions through the use of
renewable fuels will generate additional growth in the ethanol market.  Regulation of the ethanol industry in Canada is not materially different from that of the United States. Canadian taxation law currently provides for a $0.10 per litre excise tax exemption on the ethanol portion of ethanol blended gasoline. The Canadian Federal Government Budget, tabled in the House of Commons on March 19, 2007, proposed to repeal this exemption for renewable fuels effective April 1, 2008, but allocated a C$1.5 billion operating incentive over seven years to producers of renewable alternatives to gasoline, such as ethanol. Incentive rates will be up to $0.10 per litre for renewable alternatives to gasoline, for the first three years, then decline thereafter. In order to ensure companies do not earn excessive profits, government support will not be provided when rates of return exceed 20 per cent, determined annually. Support under the program to individual companies
will be capped to ensure that benefits are provided to a wide range of participants in the sector  not just the largest oil-producing companies. It is expected that this Budget will receive majority support in the House of Commons and become law by June 2007. We will monitor this process and will pursue this incentive funding for our Barrie and Sarnia plants once further information is available. In Ontario, there is also a 14.7 cent per litre ($CDN) Provincial Fuel Tax exemption on the ethanol portion of blended gasoline until 2010.  In Ontario, grain elevator licensing for ethanol plants falls under provincial jurisdiction. We will need to obtain grain elevator licenses for Barrie and Sarnia from Agricorp, a provincial government agency. In Sarnia, we will also need to obtain a marine terminal license from the Canadian Grain Commission due to the fact that the site has a dock facility. Parrish & Heimbecker has offered their  12      assistance in obtaining these licenses, which they have said are quite simple to acquire. The annual cost of a Grain Elevator License is C$1,200. These licenses will require us to post security in an amount to be determined by Agricorp and the Canadian Grain Commission. The purpose of this security is to ensure that the licensee has the financial capability to fulfill its purchases from Canadian grain suppliers.  The Canadian Wheat Board has no jurisdiction over Canadian corn based ethanol producers. Under the North American Free Trade Agreement (NAFTA), ethanol produced in Canada is allowed to enter the U.S. duty-free. The same is true for ethanol produced in the U.S. entering Canada. In Canada, ethanol may also be sold inter-provincially without duties or other restrictions. According to the Canadian Renewable Fuels Association, there are no restrictions on Canadian ethanol entering Europe.  The fuel ethanol business benefits significantly from tax incentive policies and environmental regulations that favor the use of ethanol in motor fuel blends in the United States. Currently, a gasoline marketer that sells gasoline without ethanol must pay a federal tax of $0.18 per gallon compared to $0.13 per gallon for gasoline that is blended with 10% ethanol. Smaller credits are available for gasoline blended with lesser percentages of ethanol. The repeal or substantial modification of excise tax exemptions for ethanol-blended gasoline or, to a lesser extent, other federal, state or provincial policies and regulations that encourage the use of ethanol could have a detrimental effect on the ethanol production and marketing industry and materially and adversely affect our sales and profitability.  In August 2005, President George W. Bush signed into the law the Renewable Fuels Standard that mandated the use of 4.0 billion gallons of renewable fuels by oil refiners in 2006, increasing to 7.5 billion gallons in 2012. The vast majority of this renewable fuel will be ethanol. In his January 23, 2007 State of the Union Address, President Bush proposed increasing the supply of alternative fuels by setting a mandatory fuels standard to require 35 billion gallons of renewable and other alternative fuels in 2017  nearly five times the current target.  The U.S. Clean Air Act Amendments of 1990 (CAAA90) established special standards effective January 1, 1995, for the most polluted ozone non-attainment areas: Los Angeles Basin, Baltimore, Chicago Area, Houston Area, Milwaukee Area, New York-New Jersey, Hartford Region, Philadelphia Area and San Diego, with provisions to add other areas in the future if conditions warrant. Californias Central Valley was added in 2002. At the outset of the program there were a total of 96 Metropolitan and Micropolitan Statistical Areas (MSAs) not in compliance with clean air standards for ozone, which currently represents approximately 60% of the national market.  The legislation requires a minimum of 2.0% oxygen by weight in reformulated gasoline as a means of reducing carbon monoxide pollution and replacing octane lost by reducing aromatics that are high-octane portions of refined oil. The Reformulated Gasoline Program (RFG) also includes a provision that allows individual states to opt into the federal program by request of the governor, to adopt standards promulgated by California that are stricter than federal standards, or to offer alternative programs designed to reduce ozone levels. Nearly the entire Northeast and middle Atlantic areas from Washington, D.C. to Boston not under the federal mandate have opted into the federal standards.  Gasoline is oxygenated because the oxygen makes gasoline burn cleaner thereby reducing ozone forming compounds and carbon monoxide. The two available oxygenates to meet both oxy-fuel and RFG requirements have been MTBE (methyl tertiary butyl ether) and ethanol. MTBE is an ether made from methanol produced from natural gas and, until recently, has been the most widely used oxygenate to meet CAAA90 requirements.  Because of its favorable handling qualities and the fact that it is a petroleum product, MTBE has been the preferred oxygenate for the petroleum industry. However, MTBE has shown significant adverse  13      environmental and health safety characteristics that have led to the decision by several key States to ban its use. Specifically, MTBE is highly persistent (i.e. it has a very long half-life) and has been identified as a potential carcinogen. MTBE has been detected in drinking water supplies in almost all areas where it is used. Reflecting these issues, California, New York, Connecticut, New Jersey and more than twenty other States have banned the use of MTBE.  COMPETITION  The ethanol production industry is becoming increasingly competitive. We believe that our ability to successfully compete depends on many factors including but not limited to the economics of feedstock supply, proximity to major customers and extent of transportation infrastructure. Organizations that we deem our principal competition are currently producing ethanol or are currently constructing ethanol production capacity on a significant scale within our local target markets of Ontario, New York, Michigan and Ohio.  We believe our principal competition in these markets is as follows:  Company



Location



Feedstock



Current Capacity (mgy)



Under Construction/ Expansion (mgy)GreenField Ethanol



Varennes, QC, Canada



Corn



32GreenField Ethanol



Chatham, ON, Canada



Corn



49GreenField Ethanol



Tiverton, ON, Canada



Corn



7GreenField Ethanol



Johnstown, ON, Canada



Corn







53GreenField Ethanol



Hensall, ON, Canada



Corn







53Suncor Energy Products



Sarnia, ON, Canada



Corn



53Tembec



Temiscaming, QC, Canada



Forest Waste



4Canada total



145



106The Andersons Clymers Ethanol, LLC



Clymers, IN



Corn







110Cardinal Ethanol



Harrisville, IN



Corn







100ASAlliances Biofuels, LLC



Linden, IN



Corn







100Central Indiana Ethanol, LLC



Marion, IN



Corn







40Premier Ethanol



Portland, IN



Corn







60Iroquois Bio-Energy Company, LLC



Rensselaer, IN



Corn



40New Energy Corp.



South Bend, IN



Corn



102The Andersons Albion Ethanol LLC



Albion, MI



Corn



55Michigan Ethanol, LLC



Caro, MI



Corn



50Marysville Ethanol, LLC



Marysville, MI



Corn







50Global Ethanol/Midwest Grain Processors



Riga, MI



Corn







57US BioEnergy Corp.



Woodbury, MI



CornWestern New York Energy, LLC



Shelby, NY



Corn







50Northeast Biofuels



Volney, NY



Corn







114ASAlliances Biofuels, LLC



Bloomingburg, OH



Corn







100Coshoctan Ethanol, OH



Coshoctan, OH



Corn







60The Andersons Marathon Ethanol, LLC



Greenville, OH



Corn







110Summit Ethanol



Leipsic, OH



Corn







60   14        Greater Ohio Ethanol, LLC



Lima, OH



Corn







54Liquid Resources of Ohio



Medina, OH



Waste Beverage



3US total



250



1065Combined



395



1,171  Our most significant competitor is expected to beGreenField Ethanol.It hascurrent production and capacity under construction of 109 million gallons in Ontario, or 28% of the total capacity in the above table. If we are successful in constructing our two initial production facilities in Ontario, we expect to compete directly with GreenField Ethanol for the sale of our ethanol and co-products in Ontario. Even though Suncor Energy also has ethanol production in Ontario, we expect that we will not compete directly with them, as we believe they are currently producing ethanol primarily for distribution to their own network of retail gasoline stations.  There can be no assurances that we will be successful in developing our proposed ethanol plants, or if so developed, that we will become a competitive force in the industry.  GOVERNMENT REGULATIONS  Our existing and proposed business operations are subject to extensive and frequently changing federal, state, provincial and local laws and regulations relating to the protection of the environment. These laws, the underlying regulatory requirements and the enforcement thereof, some of which are described below, impact, or may impact, our proposed business operations by imposing:  
Restrictions on our existing and proposed business operations and/or the need to install enhanced or additional controls;  
The need to obtain and comply with permits and authorizations;  
Liability for exceeding applicable permit limits or legal requirements in certain cases for the remediation of contaminated soil and groundwater at our facilities, contiguous and adjacent properties and other properties owned and/or operated by third parties; and  
Specifications for the ethanol we market and plan to produce.  In addition, some of the governmental regulations to which we are subject are helpful to our ethanol marketing business and proposed ethanol production business. The ethanol fuel industry is greatly dependent upon tax policies and environmental regulations that favor the use of ethanol in motor fuel blends in North America. Some of the governmental regulations applicable to our ethanol marketing business and proposed ethanol production business are briefly described below.  Federal support in Canada for ethanol dates back to the mid-1990s when the Canadian government removed the excise tax on the ethanol portion of blended gasoline and established a program to protect producers from any future change in this policy. In December 1994, the Canadian federal government announced the National Biomass Ethanol Program (NBEP) designed to support the development of a domestic ethanol industry. The program established a C$70 million line of credit for  15      qualified ethanol producers to access in the event that all, or part, of the gasoline tax exemption on ethanol was removed during the period 1999 to 2005.  On December 20, 2006, the Canadian federal government announced a regulation that will require all gasoline sold in Canada to have 5% renewable content by 2010. This requirement is a flexible means of promoting increased ethanol content in the Canadian gasoline market. Driven by Canadas Clean Air Act, this legislation will strengthen the governments ability to take action on reducing air pollution and greenhouse gases. In Canada, the ethanol portion of blended gasoline receives an exemption from the Federal Excise Tax of C$0.10 cents per litre on gasoline. The Canadian Federal Government Budget, tabled in the House of Commons on March 19, 2007, proposed to repeal this exemption for renewable fuels effective April 1, 2008, but allocated a C$1.5 billion operating incentive over seven years to producers of renewable alternatives to gasoline, such as ethanol. Incentive rates
will be up to $0.10 per litre for renewable alternatives to gasoline, for the first three years, then decline thereafter. In order to ensure companies do not earn excessive profits, government support will not be provided when rates of return exceed 20 per cent, determined annually. Support under the program to individual companies will be capped to ensure that benefits are provided to a wide range of participants in the sector  not just the largest oil-producing companies. It is expected that this Budget will receive majority support in the House of Commons and become law by June 2007. In Ontario, there is also a C$0.147 cent per litre ($CDN) exemption on Provincial Fuel Tax until 2010.  Ontario Renewable Fuels Standard  In November 2005, the Ontario Government enacted legislation known as the Renewable Fuel Standard (RFS), which mandates a 5% ethanol blend in all gasoline sold in the province after January 1, 2007. The RFS is a flexible, market orientated means of achieving increased ethanol content in the Ontario gasoline pool. The RFS will increase the demand for fuel ethanol in Ontario to approximately 700 million litres per year.  U.S. Federal Excise Tax Exemption  In the U.S., ethanol blends have been either wholly or partially exempt from the federal excise tax (FET) on gasoline since 1978. The exemption has ranged from $0.04 to $0.06 per gallon of gasoline during that 25-year period. Current law provides a $0.051 per gallon exemption from the $0.183 per gallon FET on gasoline if the taxable product is blended in a mixture containing at least 10% ethanol. The FET exemption was revised and its expiration date was extended for the sixth time since its inception as part of the Jumpstart Our Business Strength (JOBS) Act enacted in October 2004. The new expiration date of the FET exemption is December 31, 2010. We believe that it is highly likely that this tax incentive will be extended beyond 2010 if Congress deems it necessary for the continued growth and prosperity of the ethanol industry.  Clean Air Act Amendments of 1990 (CAAA90)  In November 1990, a comprehensive amendment to the Clean Air Act of 1977 established a series of requirements and restrictions for gasoline content designed to reduce air pollution in identified problem areas of the United States. The two principal components affecting motor fuel content are the Oxygenated Fuels Program, which is administered by states under federal guidelines and a federally supervised RFG.  Oxygenated Fuels Program   16       Federal law requires the sale of oxygenated fuels in certain carbon monoxide non-attainment Metropolitan and Micropolitan Statistical Areas (MSA) during at least four winter months, typically November through February. An MSA as defined by the U.S. Office of Management and Budget: 1) a county or group of contiguous counties that contains at least one city of 50,000 inhabitants or more, or 2) an urbanized area of at least 50,000 inhabitants and a total MSA population of at least 100,000 inhabitants (75,000 in New England). Contiguous counties are included in an MSA if, according to certain criteria, they are essentially metropolitan in character and are socially and economically integrated with the central city or cities. In New England, MSAs consist of towns and cities rather than counties. Additionally, any MSA not in compliance for a period of two consecutive years in subsequent years may
also be included in the program. The EPA Administrator is afforded flexibility in requiring a shorter or longer period of use depending upon available supplies of oxygenated fuels or the level of non-attainment.  Reformulated Gasoline Program (RFG)  The CAAA090 established special standards effective January 1, 1995, for the most polluted ozone non-attainment areas: Los Angeles Basin, Baltimore, Chicago Area, Houston Area, Milwaukee Area, New York-New Jersey, Hartford Region, Philadelphia Area and San Diego, with provisions to add other areas in the future if conditions warrant. Californias Central Valley was added in 2002. At the outset of the program there were a total of 96 MSAs not in compliance with clean air standards for ozone, which currently represents approximately 60% of the national market.  The legislation requires a minimum of 2.0% oxygen by weight in reformulated gasoline as a means of reducing carbon monoxide pollution and replacing octane lost by reducing aromatics that are high-octane portions of refined oil. The RFG also includes a provision that allows individual states to opt into the federal program by request of the governor, to adopt standards promulgated by California that are stricter than federal standards, or to offer alternative programs designed to reduce ozone levels. Nearly the entire Northeast and middle Atlantic areas from Washington, D.C. to Boston not under the federal mandate have opted into the federal standards.  National Energy Bill Legislation  A national Energy Bill was signed into law in August 2005 by President Bush. The Energy Bill substitutes the existing oxygenation program in the RFG with a national renewable fuels standard. The standard sets a minimum amount of renewable fuels that must be used by fuel refiners. Beginning in 2006, the minimum amount of renewable fuels that must be used by fuel refiners is 4.0 billion gallons, which increases progressively to 7.5 billion gallons by 2012.  Additional Environmental Regulations  In addition to the governmental regulations applicable to the ethanol marketing and production industries described above, our business is subject to additional federal, state, provincial and local environmental regulations, including regulations established by the EPA, the California Air Quality Management District, the San Joaquin Valley Air Pollution Control District and the California Air Resources Board, or CARB. We cannot predict the manner or extent to which these regulations will harm or help our business or the ethanol production and marketing industry in general.  EMPLOYEES  As of the date of this Report, we employ seven persons, including three members of management, two in administration and two in operations. Upon the development of our proposed ethanol plants, we anticipate that the number of persons we employ will increase significantly, specifically in the areas of  17      plant operations. We expect to recruit additional employees of high skill, and our success will depend in part upon our ability to retain such employees and attract new qualified employees who are in great demand. None of our employees are members of a union. We consider our employee labor relations to be good.  ITEM 2.
DESCRIPTION OF PROPERTY  Our principal executive offices are located at 193 King Street East, Suite 300, Toronto, Ontario, M5A 1J5, Canada, telephone: (416) 366-5511. These offices consist of a 7,200 square foot space leased under an agreement dated April 20, 2006, between our wholly owned subsidiary company, Northern Ethanol (Canada) Inc., and Fercan Developments Inc.SeePART III, ITEM 12, CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The initial lease term is for five years with an option to extend for an additional five years.  Also on April 20, 2006, our wholly-owned subsidiary company, Northern Ethanol (Barrie) Inc., entered into a 25 year lease, with two ten year optional renewal periods, on a 35 acre industrial property located in Barrie, Ontario, Canada, on which it intends to construct an ethanol processing facility. This property was also leased from Fercan Developments Inc.SeePART III, ITEM 12, CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.  ITEM 3.
LEGAL PROCEEDINGS  We are not party to any legal proceedings as of the date of this Report.  ITEM 4.
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS  None.   18       PART II  ITEM 5.
MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS  As of the date of this Report there is no market for our Common Stock. An application has been filed on our behalf to list our Common Stock for trading on the OTCBB. There can be no assurances that our Common Stock will be approved for listing on the OTCBB, or any other existing trading market. (SeePART II, ITEM 6, MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS RISK FACTORS.)  As of the date of this Report, there are 104,096,500 shares of our Common Stock issued and outstanding.  As of the date of this Report, there are 58 stockholders of record of our Common Stock.  We have not paid cash dividends in the past, nor do we expect to pay cash dividends for the foreseeable future. We anticipate that earnings, if any, will be retained for the development of our business.  ITEM 6.
MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  The following discussion should be read in conjunction with our consolidated financial statements and notes thereto included herein. In connection with, and because we desire to take advantage of, the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, we caution readers regarding certain forward looking statements in the following discussion and elsewhere in this report and in any other statement made by, or on our behalf, whether or not in future filings with the Securities and Exchange Commission.Forward-looking statements are statements not based on historical information and which relate to future operations, strategies, financial results or other developments.Forward looking statements are necessarily based upon estimates and assumptions that are inherently
subject to significant business, economic and competitive uncertainties and contingencies, many of which are beyond our control and many of which, with respect to future business decisions, are subject to change.These uncertainties and contingencies can affect actual results and could cause actual results to differ materially from those expressed in any forward-looking statements made by, or on, our behalf.We disclaim any obligation to update forward-looking statements.  OVERVIEW  We were incorporated as Beaconsfield I, Inc. in the State of Delaware on November 29, 2004, as a blank check companyfor the purpose of engaging in the potential future merger or acquisition of an unidentified target business.  On December 15, 2004, we issued 150,000 shares of our Common Stock for a total of $15 in cash. Additionally on that date, we issued 10,000,000 shares (pre-forward split) of our Common Stock, for a total of $50,000 in cash.  In July 2006, we engaged in a forward split of our Common Stock whereby we issued ten (10) shares of our Common Stock for every one (1) share then issued and outstanding. Also in July 2006, the holders of a majority of our then issued and outstanding Common Stock approved an amendment to our  19      Certificate of Incorporation wherein we did change our name to Northern Ethanol, Inc. to better reflect our current business plan that is described under PLAN OF OPERATION below. We are currently considered a development stage company.  We have two wholly-owned subsidiaries, Northern Ethanol, LLC, a New York limited liability company and Northern Ethanol (Canada) Inc., a Canadian corporation, which has three wholly-owned subsidiaries, Northern Ethanol (Barrie) Inc., Northern Ethanol (Sarnia) Inc. and Northern Ethanol Investments Inc., each of which is also a Canadian corporation.  RESULTS OF OPERATIONS  Comparison of Results of Operations for the year ended December 31, 2006 and 2005  During the years ended December 31, 2006 and 2005, we did not generate any revenues. We do not expect to begin generating revenues until such time as the ethanol plants described below under PLAN OF OPERATION become operational, or we successfully acquire an existing ethanol plant.  During the year ended December 31, 2006, we incurred costs and expenses totaling $3,245,400, including $2,153,342 in salaries and benefits, $970,351 in general and administrative expense, $99,644 in occupancy costs and $22,063 in depreciation expense.  The general and administrative expense of $970,351 included consulting fees of $346,236, legal and accounting fees of $286,655, travel related costs of $103,516, and other miscellaneous costs totaling $233,944. Occupancy costs of $99,644 are the costs of rent, utilities, insurance and maintenance for our head office location incurred since the start of the lease on April 20, 2006. During the year ended December 31, 2005, our total expenses were $27,765. This significant increase in operating expenses in the same period in 2006 is a direct result of our commencement of our new business plan, described herein.  As a result, we incurred a net loss of $3,245,400 for the year ended December 31, 2006 ($0.03 per share),compared to a net loss of $27,765 for the year ended December 31, 2005 (less than $.01 per share).  PLAN OF OPERATION  As of the date of this Report we have adopted a new business plan to initially construct and operate twoethanol plants. Our goal is to produce ethanol in Ontario and market and sell ethanol in Central Canada and the Eastern United States. In this regard we have secured or are in advanced stages of securing sites to build ethanol processing facilities at two locations in Ontario, Canada (Barrie and Sarnia) for total planned production capacity of approximately 216 million gallons per annum. Each of these locations will be the site for a corn-based ethanol processing facility. The two facilities currently envisaged for Ontario are expected to be completed and operational over the next two years.  We have secured, or are in the advanced stages of securing, sites to build ethanol processing facilities at the following locations, in the capacities indicated:  
Barrie, Ontario, Canada; 108 million gallons This 35 acre site has been obtained under a 25 year lease with two ten year renewal options at the then current market for comparable properties. The lease allows us to utilize all existing site infrastructure and demolish or modify existing structures to optimize plant operations. We are leasing our Barrie site and our Head Office space  20      from Fercan Developments Inc., a company owned by the same individual that owns Rosten Investments Inc. (Rosten). Rosten owns 10,000,000 shares of our outstanding Common Stock, or 9.5% interest.See PART III, ITEM 12, CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.  
Sarnia, Ontario, Canada; 108 million gallons This site comprises approximately 30 acres. We have entered into an exclusive non-binding letter of intent with the owner of this location that provides us with a 99-year lease with an annual rental payment of C$10, plus payment by us of all real estate taxes and other operating expenses, including utilities. This letter of intent is exclusive so long as the parties are negotiating in good faith. Prior to completion of construction we anticipate the annual real estate taxes to be less than C$10,000 annually. The terms of the lease are subject to our reaching an agreement with the lessor to supply steam to our proposed plant for a minimum of 15 years. The proposed terms also include a right of first refusal for us to acquire this land at a price to be agreed in the future and also provides for us to
receive C$4 million as a tenant inducement to enter into a definitive agreement. This site is adjacent to a major rail line, has good highway access, access to the Great Lakes for shipping purposes and is fully zoned and serviced. As of the date of this Report we are proceeding with the finalization of the business terms incorporating the aforementioned provisions along with other provisions for site services including steam energy.  Each of these locations will be the site for an ethanol processing facility, using corn as the feedstock. Our proposed plants will be designed to incorporate many of the newest technological innovations, including molecular sieves for dehydrating ethanol and continuous fermentation processing. The Barrie location represents a conversion of an existing sites servicing infrastructure from a former brewery.As of the date of this Report we plan on renovating existing structures, demolishing those that are not germane to our proposed operations at the Barrie site and to utilize the rail spur and the utility connections. The Sarnia location offers an existing rail spur, steam connection from a neighboring power plant, utility connections and dock facilities. Both locations have been zoned for industrial use.  We have selected these sites because of our belief that in order to be competitive with both existing and proposed new ethanol plants the following criteria needs to be considered:  
Local access to feedstock 
Access to end users 
Access to skilled labor market 
Status of infrastructure 
Zoning  Our proposed facilities are to be located on industrial zoned sites. There are three primary means of transporting ethanol in North America, including rail, truck or barge and not all of these transportation modes are available to all our competitors. The Barrie and Sarnia locations have ease of access to all three modes, which are expected to reduce our transportation costs. We believe the sites we have chosen provide access to a number of available local gasoline blending facilities owned by major refiners including Imperial Oil (Exxon), Shell, PetroCanada and Suncor.  The potential drawbacks of these locations include higher transportation costs for feedstock and higher property costs. We believe that this will be offset by the reduced cost of transporting ethanol because of proximity to the end use market.   21       Based on the target price range of $180 million to $200 million stated in the EPC term sheet executed March 9, 2007 with AKSC for our Barrie plant, preliminary engineering estimates and our indicative term sheet executed December 13, 2006 with West LB, we estimate that the Barrie and Sarnia plants will cost $454 million in the aggregate, as described in the following table:  Items







Barrie





Sarnia





TotalFixed Price EPC Contract Costs:EPC Price Materials







$
124,000,000





$
120,000,000





$
244,000,000EPC Price Labor








66,000,000






70,000,000






136,000,000Total EPC Costs








190,000,000






190,000,000






380,000,000Owners Costs:Project Management








745,000






710,000






1,455,000Infrastructure Upgrades








1,627,000






805,000






2,432,000Permitting (Environmental and Building)








143,000






134,000






277,000Insurance During Construction








662,000






659,000






1,321,000Owners Engineer








219,000






202,000






421,000Startup Materials& Labor








658,000






640,000






1,298,000Spare Parts








570,000






552,000






1,122,000Lenders Engineer








319,000






319,000






638,000Other Miscellaneous Costs








368,000






368,000






736,000Total Owners Costs








5,311,000






4,389,000






9,700,000SubTotal Costs








195,311,000






194,389,000






389,700,000Contingency








15,625,000






15,551,000






31,176,000Interest During Construction








16,601,000






16,523,000






33,124,000Total Costs







$
227,537,000





$
226,463,000





$
454,000,000  We will need to raise this $454 million amount in equity and/or debt financing to complete construction of the Barrie and Sarnia ethanol production facilities. Effective December 13, 2006, we executed an engagement letter and indicative term sheets with WestLB AG (WestLB) whereby WestLB has conditionally agreed to solicit and arrangesenior debt and subordinate debt financing for up to 75% of the construction costs (to a maximum of approximately $365 million) of our Barrie and Sarnia facilities on a best efforts basis. The term best efforts means that West LB believes that they can syndicate the debt financing we require but that there is no guarantee that they will be successful or that the terms will be as indicated in their term sheets until they market the transaction and receive firm commitments from a syndicate of lenders
for the funds required on acceptable terms to the Company. Among other things, the engagement letter and indicative term sheets are conditional on our obtaining subordinate debt or equity investment for the remaining 25% of construction costs. The WestLB indicative term sheets offer first priority senior secured construction and term financing for up to 60% of the total capital requirements of plant construction and for working capital for a total term of up to 7.5 years and subordinated secured construction and term financing for up to 15% of the total capital requirements of plant construction for a total term of up to eight years. Following conversion of the senior construction loan to a senior term loan, the loan amount is to be repaid in equal quarterly installments over 6 years. Surplus cash as defined by debt service covenant is to be swept to accelerate the repayment of the senior term loan and to repay the subordinated term loan. We paid a non-refundable retainer deposit of $200,000 to WestLB
on execution  22      of the engagement letter and indicative term sheets. In the event that we chose to terminate the WestLB engagement and we enter into a similar debt financing with another lender, within twelve months of terminating WestLB, we will pay WestLB a termination fee of $5,000,000 if termination occurs within 60 days from December 13, 2006 and $10,000,000 thereafter. If the financing contemplated in the engagement letter and indicative term sheets is finalized with WestLB, we will pay to WestLB a structuring and arrangement fee of the greater of $5,000,000 or 2% of the principal amount of the senior financing and $5,000,000 or 2% of the principal amount of the subordinated financing. In addition, we will pay a fee to market the senior and subordinate loans of 1% of the principal amount of each. The interest rate on the senior financing will be at LIBOR plus an anticipated spread of 325 to 350 basis points. Until the senior loan
has been fully drawn, we shall pay a commitment fee of 0.50% on the undrawn portion. The interest rate on the subordinate financing will be at LIBOR plus an anticipated spread of 1000 basis points. As the subordinate financing will be fully drawn on closing there will be no commitment fees applicable on that facility. We expect that other covenants, representations and warranties will form part of the final documentation on closing of the loan agreement. We have had discussions with investment bankers, financial institutions and private investors about obtaining the 25% subordinate debt or equity investment required to complete the project financing but as of the date of this Report we have received no binding commitments. We may not be able to obtain sufficient funding from one or more investors or lenders, or if such funding is obtained, that it will be on terms that we have anticipated or that are otherwise acceptable to us.  Effective July 24, 2006, we entered into a five-year Project Development Agreement (the Delta-Barrie Agreement) with Delta-T Corporation, Williamsburg, Virginia (Delta), wherein Delta shall provide us professional advice, business and technical information, design and engineering and related services in order to assist us in assembling all of the information, permits, agreements and resources necessary for construction of an ethanol plant having the capacity to produce 108 million gallons per year in Barrie, Ontario, Canada. We paid Delta the non-refundable sum of $100,000 for their services.  In September 2006, we entered into a similar five-year agreement with Delta relating to our proposed Sarnia ethanol plant (the Delta-Sarnia Agreement) and paid Delta an initial non-refundable amount of $70,000 for such services, with the balance of $30,000 due upon issuance of an air permit by the Province of Ontario. References to the Delta-Barrie Agreement and Delta-Sarnia Agreement are hereinafter jointly referred to as the Delta Agreements, unless otherwise indicated.  The Delta Agreements provide for Delta to assist us in the development and analysis of the operating costs, plant specifications, compliance with environmental issues, product marketing, industry economics, technical and other assistance. Deltas sole remedy in the event that we breach theDelta Agreements is limited to the non-refundable fees of $100,000 paid under each of the agreements. The relationship between Delta and us is deemed exclusive during the five-year term of the Delta Agreements whereby we agreed to use our best efforts to enter into an EPC contract or a technology agreement with Delta at these locations and if we fail to do so, to give them a first right of refusal for 60 days to assume any agreements made with other ethanol plant technology vendors.  Although Delta has been involved in 120 projects on five continents, it has no previous experience developing or constructing ethanol plants in Canada. The construction of ethanol plants using Delta technology is carried out by construction contractors. We have selected Aker Kvaerner Songer Canada Ltd. (AKSC) as the construction contractor for our Barrie and Sarnia facilities because of their extensive experience in the construction of power plants in the United States and Canada. Delta and AKSCs US affiliate are currently working jointly on the development and construction of two ethanol plants in the United States.   23       On March 9, 2007, we executed a term sheet with AKSC for the development of an engineering, procurement and construction (EPC) contract for the Barrie site. We are obligated to pay a non-refundable fee of $500,000 to AKSC for executing the term sheet and we will pay AKSC a further non-refundable fee of $500,000 in June 2007 on receipt of the fixed EPC contract price for our Barrie plant. Providing the EPC contract price is acceptable and financing is obtained, we expect to execute the EPC contract(AKSC-EPC) within 60 days of receiving the fixed EPC contract price and commence construction at the Barrie site immediately thereafter.  We also expect to enter into a similar arrangement with AKSC for the Sarnia location during 2007although we have not received a term sheet from AKSC regarding the Sarnia facility at this time. AKSC is a multinational EPC firm with extensive experience erecting and constructing facilities in Canada. Deltas primary role in the projects will be to provide the process technology and engineering. This will include all of the prime processes in the receiving and milling of the corn, the cook process, fermentation process, distillation process, molecular sieve and centrifuge process, chemical storage area, fuel and ethanol storage and load-out as well as DDGS drying, storage and load-out. AKSC will erect the Delta process components as well as engineer, procure and construct the balance of plant equipment for such items as the boiler house, cooling towers, all
utility tie-ins, plant fire water system, and any water treatment systems.AKSC will be responsible for all labor supply and project completion risk(i.e. project completed on schedule, at the contract price, meeting design specifications). The EPC contract will be guaranteed by AKSCs parent company, Aker Kvaerner ASA of Baerum, Norway, a leading global provider of engineering and construction services, technology products and integrated solutions with NOK14 billion (approximately $2.3 billion) in annual revenue. The Delta plant design that we have selected is based on plant designs and components currently being utilized by other Delta customers. Any differences in our plant designs from the standard Delta design will be to provide for higher reliability and performance. Not all current projects undertaken by Delta appear on their website due to client preferences with regards to
confidentiality.  In August 2006, we retained the services of the engineering firm of Charles G. Turner & Associates for an initial term to December 31, 2006, to monitor the design, equipment selection, construction and commissioning phases of the projects on a hourly fee basis. This agreement is continuing in effect on a month-to-month basis.  Also in August 2006, we contracted with Parrish & Heimbecker Ltd. (P&H) to provide corn procurement and co-product merchandizing services on a fee per shipment basis for a five-year period for our proposed Barrie and Sarnia ethanol plants upon the opening of such plants. P&H is a privately held grain merchant corporation that owns and operates grain elevators and has extensive domestic and international experience in international grain origination and co-product merchandizing. We engaged them to source all of the corn required for the operation of the Barrie and Sarnia ethanol facilities at competitive prices. We expect they will assist us in negotiations with major corn suppliers to guarantee supply and price by committing to long-term purchase agreements or opportunistic purchases on the spot market when this can be done at favorable rates. We will pay P&H C$1.00 per
metric ton of corn procured for our Barrie and Sarnia operations. P&H will manage the sale of our dried distiller grain by-product. We will pay P&H C$1.00 per metric ton of DDGS sold for marketing the sale of our product. Our agreement with P&H does not include any minimum purchase requirements.  We are currently in the process of finalizing contracts covering the Barrie and Sarnia facilities with ECO Energy Inc., a privately held Tennessee corporation that provides ethanol marketing capability across North America (ECO). ECO is a fully integrated marketing company supported by an experienced sales force, a knowledgeable logistics and scheduling department, customer service, and an online computer system that we will be able to access to streamline all necessary correspondence for daily  24      shipments and transportation transactions. We expect to engage this marketing company to handle the sales and transportation logistics of our ethanol production.  None of our current management has any experience in developing or operating ethanol plants. Our Chief Operating Officer and Vice President Development, Steven Reader, and our Director of Project Management and Operations, Gordon Langille, have extensive experience in the construction and operation of North American power plants and pipelines.  We are implementing a growth strategy by:  
Building state of the art processing plants;
Negotiating stable long term contracts with key suppliers;
Securing long term sales agreements;
Pursuing acquisitions of existing ethanol producers; and
Pursuing acquisitions and/or strategic alliances with ethanol technology companies.  We are committed to investing in the latest technology to ensure that the processing costs are as low as possible, and the outputs are of the highest quality. The initial locations have been chosen due to proximity to supply of corn, natural gas, and water and are well located for the transportation of inputs and products.  The manner in which we intend to develop future sites beyond the initial aforementioned locations will depend on the nature of the opportunity, the respective needs of the parties involved, and ourselves. We have set up a separate subsidiary to own each ethanol plant. We may purchase ethanol producing facilities outright, acquire an ownership interest in companies controlling ethanol producing facilities, or issue shares in the subsidiary company that controls the site to outside parties who control ethanol producing facilities. We were in negotiations to acquire an existing ethanol plant site in the Province of Quebec, Canada. We made a fully refundable deposit to the prospective sellers solicitor, in trust, in the amount of $750,000. But we elected to terminate this potential acquisition and the deposit has been returned to us.  We were in the negotiations with the steam supplier at a site in Lewiston, New York, but we were unable to negotiate an appropriate steam agreement as the supplier was at the end of their power purchase agreement with the utility. As the supplier has been unable to negotiate a new electric agreement there is was no way to assure ourselves that the steam supply would be there for the life of the plant and as such we have stopped considering this site for now, or at least until the supplier is in a position to guarantee a firm and reliable steam supply to our plant. We will continue to investigate alternative sites in upper state New York.  On February 14, 2007, we executed a non-binding letter of intent offering to invest $6.5 million into Energen Development Ltd., Kingston, Jamaica (EDL) in exchange for a 70% interest in that company. EDL is currently involved in developing an ethanol dehydration plant (Phase 1) and biodiesel plant (Phase 2) on the island of Jamaica, for local and export sales markets. Effective March 13, 2007, the parties terminated the letter of intent. We will continue to pursue opportunities in the Caribbean Basin to develop ethanol dehydration plants using hydrous ethanol.   25       On March 27, 2007, we entered into a non-binding letter of intent with Quad County Corn Processors Cooperative, Galva, Iowa (Quad) wherein we have agreed in principle to acquire most of the assets and liabilities of Quad, including its existing ethanol plant (current annual ethanol production of 30 million gallons) for the purchase price of $105 million. The purchased assets shall exclude Quads cash on hand and on deposit and all insurance policies pertaining to the business. The liabilities exclude Quads long-term indebtedness and the current portion of long-term indebtedness. The exact form of the proposed acquisition has not yet been determined, as it may be an asset acquisition, merger or some other form. We are currently discussing this issue with Quads management. The structure of this acquisition will depend upon the most favorable tax consequences to both Quad and
us. The proposed purchase price shall be payable by our delivery of a certified check or other good funds in the amount of $78,750,000, representing 75% of the proposed purchase price, plus the issuance by us of a 5.5% Convertible Subordinated Debenture (the Debenture) in the principal amount of $26,250,000. The Debenture shall mature two (2) years from the Closing Date, unless converted by Quad, in whole or in part. Quads right to convert shall commence six (6) months from the Closing Date and terminate upon payment in full of the Debenture. The Debenture may be converted into shares of our Common Stock at a conversion price (subject to adjustment for stock splits or other recapitalization after the date hereof) equal to the greater of $1.00 per share or a Formula Price per share (as defined in the letter of intent and as subsequently explained in the next paragraph). Interest shall be due and payable semi-annually. The first payment shall be due on the six month anniversary of the
Closing Date. No prepayment penalty provision shall be included in the Debenture. At Quads option, it may elect to increase the amount of the Debenture to $42,000,000 (40% of the purchase price) with the cash payment due at the Closing Date reduced by like amount, provided that Quad shall make such election prior to May 15, 2007. We have the right to redeem the Debenture, upon 30 days prior written notice to Quad, on or after March 31, 2008. We have agreed to register the Common Stock issuable under the Debenture with the Securities and Exchange Commission on or before the 180th day following the Closing Date. The holder(s) of the Debenture shall also have the right to convert and participate in any underwritten public offering of our Common Stock occurring anytime after the Closing Date; provided, however, if the managing underwriter advises us that the inclusion of the converted Common Stock would interfere with the successful marketing (including pricing) of all such
securities to be included in such registration, then the number of shares of Common Stock included in such offering, including the converted shares of Common Stock, shall be reduced pro rata.  The Formula Price is determined as follows: (A) 110% of the most recent price that we have raised equity pursuant to a Qualified Sale, if the amount raised was greater than $10,000,000, but less than $20,000,000; (B) 120% of the most recent price that we have raised equity pursuant to a Qualified Sale, if the amount raised was greater than $20,000,000, but less than $30,000,000; (C) 125% of the most recent price that we have raised equity pursuant to a Qualified Sale, if the amount raised was greater than $30,000,000, but less than $40,000,000; (D) 130% of the most recent price that we have raised equity pursuant to a Qualified Sale, if the amount raised was greater than $40,000,000. Qualified Sale means a sale of Common Stock by us for cash during the period beginning on March 27, 2007, the date of execution of the letter of intent and ending on the Closing Date, to one or more unrelated
third parties in an arms length transaction where the total consideration received by us is not less that $10 million.  As of the date of this Report we are beginning our due diligence of Quads history and operations and drafting definitive agreements. It is expected that these activities shall take approximately 45-60 days to complete. There can be no assurances that we will finalize the definitive agreement with Quad or otherwise consummate this acquisition.  We are continuing to review and explore other acquisitions of existing ethanol plants, but no definitive agreements have been reached and there can be no assurances that we will reach any agreements in the future. It is likely that we will finance our participation in a business opportunity  26      through the issuance of Common Stock or other securities and through the issuance of senior debt secured against the assets of each operating location. In the case of cash acquisition, the transaction may be accomplished upon the sole determination of management without any vote or approval by stockholders. In the case of a statutory merger or consolidation directly involving us, it will likely be necessary to call a stockholders meeting or otherwise obtain the approval of the holders of a majority of our outstanding shares. The necessity to obtain such stockholder approval may result in delay and additional expense in the consummation of any proposed transaction and may also give rise to certain appraisal rights to dissenting stockholders.  We plan to identify and exploit new technologies for reduced costs and greater manufacturing yields. For example, we are examining new technologies enabling the conversion of cellulose, which is generated predominantly from wood waste, paper waste and agricultural waste, into ethanol which would reduce or eliminate our dependency on corn as a primary feedstock while also helping local municipalities deal with ever increasing demands on their garbage disposal sites.  LIQUIDITY AND CAPITAL RESOURCES  At December 31, 2006, we had $561,715 in cash and cash equivalents.  In July 2006, we engaged in a forward split of our Common Stock whereby we issued ten (10) shares of our Common Stock for every one (1) share then issued and outstanding. Following the aforesaid forward stock split, we commenced a private offering of our Common Stock. We closed this offering in September 2006 after selling an aggregate of 4,096,500 shares of our Common Stock at a price of $1.00 per share and received aggregate net proceeds of $3,846,500 therefrom. The proceeds from our private placement that closed September 2006 financed our working capital requirements, including salaries and benefits, lease commitments, and capital expenditures on property, plant and equipment through March 31, 2007.  In order to allow us to continue to implement our business plan, on March 30, 2007, we entered into a Line of Credit Agreement with Union Capital Trust, Nassau, Bahamas (Union) wherein Union has agreed to provide us with a $6 million unsecured line of credit. Interest accrues at the rate of twelve percent (12% per annum) and is payable monthly. Principal and unpaid interest is due on or before March 30, 2008. As of the date of this Report, we have drawn down an aggregate of $469,000 on this line of credit. We believe that this Union line of credit will provide sufficient monies to fund the $1,000,000 deposits required on each of our EPC contracts for Barrie and Sarnia and our expected working capital requirements for project development (approximately $1,500,000 per quarter) until we are in a position to begin construction at Barrie in September 2007 and draw on the proposed West LB line of
credit outlined in its engagement letter and indicative term sheet executed effective December 13, 2006.  We estimate that we will require $454 million in additional debt or equity capital to complete the construction and commissioning of the Barrie and Sarnia facilities, and there are no assurances that we will be able to raise this capital when needed.  Effective December 13, 2006, we executed an engagement letter and indicative term sheets with WestLB AG (WestLB) whereby WestLB has conditionally agreed to solicit and arrangesenior debt and subordinate debt financing for up to 75% of the construction costs (to a maximum of approximately $365 million) of our Barrie and Sarnia facilities on a best efforts basis. The term best efforts means that West LB believes that they can syndicate the debt financing we require but that there is no guarantee that they will be successful or that the terms will be as indicated in their term sheets until they market the transaction and receive firm commitments from a syndicate of lenders for the funds required on  27      acceptable terms to the Company. Among other things, the provision of the 75% financing in accordance with engagement letter andthe indicative term sheets is conditional on our obtaining subordinate debt or equity investment for the remaining 25% of construction costs. The WestLB indicative term sheets offer first priority senior secured construction and term financing for up to 60% of the total capital requirements of plant construction and for working capital for a total term of up to 7.5 years and subordinated secured construction and term financing for up to 15% of the total capital requirements of plant construction for a total term of up to eight years. Following conversion of the senior construction loan to a senior term loan, the loan amount is to be repaid in equal quarterly installments over six years. Surplus cash as defined by debt service covenant is to be swept to
accelerate the repayment of the senior term loan and to repay the subordinated term loan. We paid a non-refundable retainer deposit of $200,000 to WestLB on execution of the engagement letter and indicative term sheets. In the event that we chose to terminate the WestLB engagement and we enter into a similar debt financing with another lender within 12 months of terminating WestLB, we will pay WestLB a termination fee of $5,000,000 if termination occurs within 60 days from December 13, 2006 and $10,000,000 thereafter. If the financing contemplated in the engagement letter and indicative term sheets is finalized with WestLB, we will pay to WestLB a structuring and arrangement fee of the greater of $5,000,000 or 2% of the principal amount of the senior financing and $5,000,000 or 2% of the principal amount of the subordinated financing. In addition, we will pay a fee to market the senior and subordinate loans of 1% of the principal amount of each. The interest rate on the senior financing will be at
LIBOR plus an anticipated spread of 325 to 350 basis points. Until the senior loan has been fully drawn, we shall pay a commitment fee of 0.50% on the undrawn portion. The interest rate on the subordinate financing will be at LIBOR plus an anticipated spread of 1000 basis points. As the subordinate financing will be fully drawn on closing there will be no commitment fees applicable on that facility. Other covenants, representations and warranties will form part of the final documentation on closing of the loan agreement. We have had discussions with investment bankers, financial institutions and private investors about obtaining the 25% subordinate debt or equity investment required to complete the project financing but as of the date of this Report we have received no binding commitments. We may not be able to obtain sufficient funding from one or more investors or lenders, or if such funding is obtained, that it will be on terms that we have anticipated or that are otherwise acceptable to us.SeeRISK FACTORS.  Our lease commitments for our head office space and for our Barrie plant are as follows:  Fiscal Year




Barrie Lease




Head OfficeLease




Total2007



$

1,947,833



$

154,453



$

2,102,2862008





1,947,833





154,453





2,102,2862009





1,947,833





154,453





2,102,2862010





1,947,833





154,453





2,102,2862011





1,947,833





64,355





2,012,188Thereafter





43,078,276











43,078,276Total minimum lease payments



$

52,817,441



$

682,167



$

53,499,608  However, effective January 24, 2007, under agreement with the lessor, the monthly lease payments under the Barrie lease were deferred until the completion of an engineering study to determine the extent of the demolition of the buildings on the leased property. This study and any amendment to the lease are expected to be completed later in 2007. We anticipate that we will be able to satisfy our current lease commitments through the Union line of credit. Thereafter we expect to satisfy these commitments with the proceeds from the senior construction and term financing provided by WestLB pursuant to an engagement letter and indicative term sheets effective December 13, 2006, and from additional subordinate debt or equity to be raised. There are no assurances that we will be able to raise additional  28      subordinate debt or equity on terms acceptable to us, or at all. In the event we are unable to raise additional funds on acceptable terms, we will need to reconsider our objectives and undertake efforts to reduce costs. Once construction of our Barrie and Sarnia plants is complete, we expect to satisfy the lease commitments with cash flow generated from the operations of these plants.  INFLATION  Although our operations are influenced by general economic conditions, we do not believe that inflation had a material affect on our results of operations during the year ended December 31, 2006.  CRITICAL ACCOUNTING ESTIMATES  The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates based on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. The following
represents a summary of our critical accounting policies, defined as those policies that we believe are the most important to the portrayal of our financial condition and results of operations and that require managements most difficult, subjective or complex judgments, often as a result of the need to make estimates about the effects of matters that are inherently uncertain.  Leases We follow the guidance in SFAS No. 13 Accounting for Leases, as amended, which requires us to evaluate the lease agreements we enter into to determine whether they represent operating or capital leases at the inception of the lease.  Capitalized Interest In accordance with SFAS No. 34, the interest costs associated with our capital lease obligation will be capitalized to assets under capital lease until the Barrie plant is substantially complete and ready for the production of ethanol.  Foreign currency translation Our functional currency is United States dollars and the functional currency of our Canadian subsidiaries is currently Canadian dollars. The operations of our Canadian subsidiaries are translated into U.S. dollars in accordance with SFAS No. 52 Foreign Currency Translation as follows:  (i)
Assets and liabilities at the rate of exchange in effect at the balance sheet date; and(ii)
Revenue and expense items at the average rate of exchange prevailing during the period.  Translation adjustments are included as a separate component of stockholders equity (deficiency) as a component of comprehensive income or loss. We expect the functional currency of our Canadian subsidiaries to change to the United States dollar once our planned ethanol production facilities in Canada commence ethanol producing operations, as debt, operating revenues and costs of our Canadian subsidiaries will primarily be denominated in United States dollars.  We and our subsidiaries translate foreign currency transactions into the Companys functional currency at the exchange rate effective on the transaction date. Monetary items denominated in foreign  29      currencies are translated into the functional currency at exchange rates in effect at the balance sheet date. Foreign exchange gains and losses are included in income.  Stock-based compensationEffective January 1, 2006, we adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standard (SFAS) No. 123R, Share Based Payment. SFAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is recognized on a straight-line basis over the employee service period (usually the vesting period). That cost is measured based on the fair value of the equity or liability instruments issued using the Black-Scholes option pricing model.  Recent accounting pronouncementsIn February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No.133 and 140. SFAS No. 155 allows financial instruments that contain an embedded derivative and that otherwise would require bifurcation to be accounted for as a whole on a fair value basis, at the holders election. SFAS No. 155 also clarifies and amends certain other provisions of SFAS No. 133 and 140. This statement is effective for all financial instruments acquired or issued in fiscal years beginning after September 15, 2006. The adoption of SFAS No. 155 is not expected to have a material impact on our consolidated financial condition or results of
operations.  In March 2006, the FASB issued SFAS No. 156,Accounting for Servicing of Financial Assets-an amendment of FASB Statement No.140.SFAS No. 156 provides guidance on the accounting for servicing assets and liabilities when an entity undertakes an obligation to service a financial asset by entering into a servicing contract. This statement is effective for all transactions in fiscal years beginning after September 15, 2006. The adoption of SFAS No. 156 is not expected to have a material impact on our consolidated financial condition or results of operations.  In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes  an interpretation of FASB Statement No.109(FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure. FIN 48 is effective for fiscal years beginning after December 15, 2006. We are in the process of evaluating the impact, if any, FIN 48 will have on our consolidated financial statements.  In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements.SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy as defined in the standard. Additionally, companies are required to provide enhanced disclosure regarding financial instruments in one of the categories (level 3), including a reconciliation of the beginning and ending balances separately for each major category of assets and liabilities. SFAS No.157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS No. 157 is not expected to have a material
impact on our consolidated financial statements.  In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.SFAS No. 158 requires the recognition of the funded status of a defined benefit plan in the balance sheet; the recognition in other comprehensive income of gains or losses and prior service costs or credits arising during the period but which are not included as  30      components of periodic benefit cost; the measurement of defined benefit plan assets and obligations as of the balance sheet date; and disclosure of additional information about the effects on periodic benefit cost for the following fiscal year arising from delayed recognition in the current period. In addition, SFAS No. 158 amends SFAS No. 87, Employers Accounting for Pensions, and SFAS No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions, to include guidance regarding selection of assumed discount rates for use in measuring the benefit obligation. The recognition and disclosure requirements of SFAS No. 158 are effective for our year ended December 31, 2006. The measurement requirements are effective for fiscal years ending December 31, 2008. We do not believe the adoption of SFAS 158 will have a material impact on our consolidated financial statements.  In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). Under the provisions of SFAS No. 159, companies may choose to account for eligible financial instruments, warranties and insurance contracts at fair value on a contract-by-contract basis. Changes in fair value will be recognized in earnings each reporting period. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. We are required to adopt the provisions of SFAS No. 159 effective January 1, 2008. We are currently assessing the impact of the adoption of SFAS No. 159.  RISK FACTORS  An investment in our Common Stock is a risky investment.Prospective investors should carefully consider the following risk factors before purchasing shares of our Common Stock.We believe that we have included all material risks.  RISKS RELATED TO OUR PROPOSED OPERATIONS  We have incurred losses in the past and expect to incur greater losses until our ethanol production begins.We are a development stage company and we have not yet commenced operations. As of December 31, 2006, we had an accumulated deficit of $3,276,873. For the year ended December 31, 2006, we incurred a net loss of $3,245,400. We expect to incur significantly greater losses at least until the completion of our initial ethanol production facility in Barrie, Ontario. We estimate that the earliest completion date of this facility and, as a result, our earliest date of ethanol production will not occur until the second quarter of 2009. Until then, we expect to rely on cash from debt and equity financing to fund all of the cash requirements of our business. Until we successfully build and begin operating our proposed ethanol plants we will
experience negative cash flow. Once our ethanol plants are built and become operational, there are no assurances that we will be able to attain, sustain or increase profitability on a quarterly or annual basis. A downturn in the demand for ethanol would significantly and adversely affect our sales and profitability.  Ethanol competes with other existing products and other alternative products could also be developed for use as fuel additives. Our revenue will be derived primarily from sales of ethanol. Ethanol competes with MTBE (methyl tertiary butyl ether) as an oxygenate in gasoline to meet both oxy-fuel and reformulated gasoline requirements. Until recently, MTBE has been the most widely used oxygenate to meet the requirements of the Clean Air Act Amendments of 1990. Because of its favorable handling qualities and the fact that it is a petroleum product, MTBE has been the preferred oxygenate for the petroleum industry. However, MTBE has shown significant adverse environmental and health safety characteristics that have led to the decision by several key States to ban its use. Specifically, MTBE is highly persistent and has been identified as a potential carcinogen. MTBE has
been detected in drinking water supplies in almost all areas where it is used. Reflecting these issues, California, New York, Connecticut, New Jersey and more than twenty other States have banned the use of MTBE.  31       We expect to be completely focused on the production and marketing of ethanol and its co-products for the foreseeable future. We may be unable to shift our business focus away from the production and marketing of ethanol to other renewable fuels or competing products. Accordingly, an industry shift away from ethanol or the emergence of new competing products may reduce the demand for ethanol. A downturn in the demand for ethanol would significantly and adversely affect our sales and profitability.  In addition to selling ethanol, we will also sell the co-products of ethanol production  dried distillers grains (DDGS) and carbon dioxide (CO2) and the markets for these products may decrease in the future.The primary use of DDGS is for livestock feed as a replacement for traditional animal feeds such as soy-meal. In the United States, cattle (both dairy and beef) have so far been the primary users of DDGS as livestock feed, but larger quantities of DDGS are making their way into the feed rations of hogs and poultry. In 2005, ethanol dry mills in the United States produced approximately 9 million tons of distillers grains. Of this, approximately 75-80% was fed to dairy and cattle, 18-20% to swine, and 3-5% to poultry. Due to the fact that DDGS have a long shelf life, they are suitable for transportation to markets all over the world. In
2005, the United States exported more than 1 million tons of distillers grains. In recent years, large markets for DDGS have developed in Europe, led by Ireland and the United Kingdom, as well as in Canada, Mexico, China, Japan, and Taiwan. Asia has a long history of importing U.S. grain because of its large population and limited space in which to grow crops. Worldwide, there is a large market for animal feed but DDGS generally need to displace other feeds as buyers will base their selection primarily on cost competitiveness. As increasing volumes of ethanol production come on-line, the amount of DDGS in the marketplace should increase proportionately. This may put downward pressure on prices and presents a risk to our business. At todays prices, it is estimated that DDGS sales will represent approximately 19% of our total sales.  Carbon dioxide is produced during the fermentation stage of the ethanol production process. This excess gas is captured and sold to carbon dioxide resellers. The carbon dioxide market is well established and consists of three major segments: the beverage market (27%), the food market (43%), and the industrial market (30%). The market is cyclical in that demand increases during the summer as beverage and food demands create shortages and higher spot prices. Transportation is a limiting factor when sourcing carbon dioxide. On average, transportation costs account for 50% of the delivered cost of carbon dioxide. For that reason, customers generally must be within 200 miles of the plant. As increasing volumes of ethanol production come on-line, it is possible that the market prices for CO2 will soften due to a finite amount of demand and an increasing supply. At todays prices, it is
estimated that CO2 sales will represent approximately 0.4% of our total sales.  Carbon dioxide is believed to contribute to global warming.Future government regulations to reduce carbon dioxide emissions may impact our ability to produce ethanol. Carbon dioxide is the most common of the compounds collectively referred to as greenhouse gases. In the recently released Summary for Policymakers, the Intergovernmental Panel on Climate Change (IPCC) indicated that most of the observed increase in globally averaged temperatures since the mid-20th century is very likely due to the observed increase in anthropogenic greenhouse gas concentrations (IPCC, 2007). The IPCC assigns a rating of very likely when the expected outcome of a result is greater than 90%.  A number of proposals are being considered around the world to combat increased greenhouse gas emissions. The specifics of these proposals vary. Typically, one of their overarching objectives is to reduce anthropogenic greenhouse gas emissions. Proposals include methods as varied as improving energy efficiency, adopting energy sources that create minimal greenhouse gas emissions (e.g., generating electricity from wind or solar energy), or shifting from fossil fuels to alternatives fuels derived from renewable sources (e.g., deriving ethanol from corn). Therefore, current proposals to combat global  32      warming do not appear to be contrary to, or pose a risk of a material adverse impact on, the proposed project to derive ethanol from corn.  In order to complete the construction of our planned ethanol production facilities, we will require the infusion of significant additional debt and equity funding. We anticipate that we will need to raise approximately $454 million in equity and/or debt financing to complete construction of our initial two ethanol production facilities in Barrie and Sarnia, Ontario.SeePart II, Item 6, MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS PLAN OF OPERATION. There are no assurances that we will be able to obtain this financing and/or investment.  Effective December 13, 2006, we executed an engagement letter and indicative term sheets with West LB AG (West LB) whereby West LB has conditionally agreed to solicit and arrange debt financing for 75% of the cost of constructing our Barrie and Sarnia facilities up to a maximum of $1.35 per gallon of annual plant capacity in senior debt and $0.34 per gallon of annual plant capacity in subordinated debt. Combined the Barrie and Sarnia plants are expected to have annual plant capacity of 216 million gallons on an undenatured basis. As such, West LB would conditionally provide up to $365 million of financing. 75% of the combined construction cost estimate of $454 million for the Barrie and Sarnia facilities would equate to $340 million. Interest during construction of the two plants of $33 million was estimated at the interest rate on the senior financing conditionally offered at London
Interbank Offering Rate (LIBOR) plus an anticipated spread of 325 to 350 basis points and at LIBOR plus an anticipated spread of 1000 basis points on the subordinate financing. Currently LIBOR is at 5.4%, so that the interest rate on the senior financing would be 8.65% to 8.9% and the interest rate on the subordinate financing would be 15.4%. On a construction cost of $454 million, the senior financing would total $272,400,000 and would be repaid in quarterly installments over 6 years following completion of construction. The subordinate financing would amount to $68,100,000 and would be repaid over 8 years from advance, with repayment terms to be negotiated. Among other things, the provision of the West LB financing in accordance with the engagement letter and indicative term sheets isconditional on our obtaining subordinate debt or equity investment for the remaining 25% of construction costs. We have had discussions
with investment bankers, financial institutions and private investors about obtaining subordinate debt or equity investment but as of the date of this Prospectus we have received no binding commitments. We may not be able to obtain sufficient funding from one or more investors or other financial institutions, or if such funding is obtained, that it will be on terms that we have anticipated or that are otherwise acceptable to us. If we are unable to secure adequate financing, or financing on acceptable terms is unavailable for any reason, we may be forced to abandon our construction of one or more, or even all, of our planned ethanol production facilities. (See a complete description of the terms under Part II, Item 6, MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS PLAN OF OPERATIONin this Report.)  Holders of our Common Stock may suffer significant dilution in the future. As of the date of this Report we do not have sufficient capital available to allow us to build the two ethanol plants discussed herein. As a result, it is possible that we may elect to raise additional equity capital by selling shares of our Common Stock or other securities in the future to raise the funds necessary to allow us to implement our business plan. If we do so, investors herein will suffer significant dilution.  Our capital structure will be highly leveraged because we plan to fund a substantial majority of the construction costs of our planned ethanol production facilities through the issuance of a significant amount of debt. Our debt levels and debt service requirements could have important consequences which could reduce the value of your investment, including:   33        
limiting our ability to borrow additional amounts for operating capital or other purposes and causing us to be able to borrow additional funds only on unfavorable terms;
reducing funds available for operations and distributions because a substantial portion of our cash flow will be used to pay interest and principal on our debt;
making us vulnerable to increases in prevailing interest rates;
placing us at a competitive disadvantage because we may be substantially more leveraged than some of our competitors;
subjecting all or substantially all of our assets to liens, which means that there may be no assets left for our stockholders in the event of a liquidation; and
limiting our ability to adjust to changing market conditions, which could increase our vulnerability to a downturn in our business or general economic conditions.  If cash flow from operations is insufficient to pay our debt service obligations it is possible that we could be forced to sell assets, seek to obtain additional equity capital or refinance or restructure all or a portion of our debt on substantially less favorable terms. In the event that we are unable to refinance all or a portion of our debt or raise funds through asset sales, sales of equity or otherwise, we may be forced to liquidate and you could lose your entire investment. However, while no assurances can be provided, based upon our discussions and negotiations with financing entities as of the date of this Report, we do believe that our proposed business plan is viable and that we will obtain the additional financing necessary to develop our ethanol plants.  Our success depends, to a significant extent, upon the continued services of Gordon Laschinger, our President and Chief Executive Officer, who has no prior experience in the ethanol industry. While Mr. Laschinger has developed key personal relationships with our expected suppliers and customers, most of these individuals have significantly more experience than Mr. Laschinger in the ethanol industry. This may place us at a competitive disadvantage because we will greatly rely on these relationships in the conduct of our proposed operations and the execution of our business strategies. The loss of Mr. Laschinger could also result in the loss of our favorable relationships with one or more of our suppliers and customers. Although we have entered into an employment agreement with Mr. Laschinger, that agreement provides for a termination date of April 30, 2009. In addition,
we do not maintain key person life insurance covering Mr. Laschinger or any other executive officer. The loss of Mr. Laschinger could also significantly delay or prevent the achievement of our business objectives.  We will be competing with other established ethanol production and marketing companies who have greater experience and resources than we currently have. We will have several significant competitors in the ethanol production industry including GreenField Ethanol Inc. (formerly Commercial Alcohols Inc.), currently the largest producer of ethanol in Canada, Archer-Daniels-Midland Company, (ADM), the largest producer of ethanol in the United States, VeraSun Energy, Corp. and Aventine Renewable Energy Holdings, Inc, both large U.S. ethanol producers, and Suncor Energy Inc., whichhas an ethanol plant in Sarnia, and others. These companies are presently producing ethanol in substantial volume, have greater financial resources and have more experienced personnel than we presently do. We are not currently producing any
ethanol. Those competitors who are presently producing ethanol have greater capital resources than we currently do. As a result, this will be a significant obstacle that we will need to overcome in order to become successful. In addition, our lack of experience in our chosen  34      industry relative to many of our significant competitors may cause us to fail to anticipate or respond adequately to new developments and other competitive pressures. This failure could reduce our competitiveness and cause a decline in our market share, sales and profitability.  We will be competing with other ethanol production companies, animal farmers and other corn users for our feedstock.The principal raw material we expect to use to produce ethanol and its co-products is corn. We expect that corn feedstock costs will represent approximately 79% of operating costs. The profitability of our business fluctuates greatly with changes in the price of corn. For each $0.10 per bushel increase in the cost of corn, our total corn cost increases by $8,059,701 per year. Significant increases in the price of corn will have substantial negative impacts on the profitability of our plants.  Feedstock costs may rise in the future as a result of the increased competition from additional ethanol plants beginning production and continued growth and demand from other users such as animal farmers and corn oil manufacturers. The supply of corn may be insufficient to meet this competing demand and as a result corn prices may rise, resulting in lower profit margins or making the production of ethanol uneconomical. Corn prices as measured by the United States Department of Agriculture, or USDA, reported as prices received, had increased 57% over the previous year by December 2006. The USDAs December 2006 crop report estimated that corn bought by ethanol plants will represent approximately 17% of the 2006/2007 crop years total corn supply, up from 13% in the prior crop year. Increasing ethanol capacity could boost demand for corn and result in sustained prices at a current levels or a
further increase in corn prices.  The development of our two proposed ethanol plants will result in a period of rapid growth that will impose a significant burden on our current administrative and operational resources. If we are able to obtain the financing necessary to implement our business plan, of which there can be no assurance, our ability to effectively manage our growth will require us to substantially expand the capabilities of our administrative and operational resources by attracting, training, managing and retaining additional qualified personnel, including additional members of management, technicians and others. To successfully develop our two proposed ethanol plants, we will need to manage the construction of these facilities, as well as operating, producing, marketing and selling the end products generated by these facilities. There can be no assurances that we will be able to do so.
Our failure to successfully manage our growth will have a negative impact on our anticipated results of operations.  Our proposed business of producing and selling ethanol is subject to significant supply and demand fluctuations.An increase in production of ethanol could have a negative impact on our anticipated revenues. We may increase inventory levels in anticipation of rising ethanol prices and decrease inventory levels in anticipation of declining ethanol prices. As a result, we are subject to the risk of ethanol prices moving in unanticipated directions, which could result in declining or even negative gross profit margins for this segment of our business. Accordingly, this segment of our business would be subject to fluctuations in the price of ethanol and these fluctuations may result in lower or even negative gross margins and which could materially and adversely affect our profitability.  We believe that the production of ethanol is expanding rapidly. According to the Renewable Fuels Association, current ethanol production capacity in the United States stands at 5,633mm gallons per year. According to the Ethanol Producer Magazine, in Canada, current production capacity is roughly 198mm gallons per year. There is capacity under construction of 6,194mm gallons in the United States and 180mm gallons in Canada. In our immediate market, consisting of Ontario, Quebec, Indiana, Ohio, Pennsylvania, New York and New Jersey, there is current production capacity of 395mm gallons per year, with capacity under construction of 1,170mm gallons per year.   35        US Ethanol Production 1999-2006  January 1999

January 2000

January 2001

January 2002

January 2003

January 2004

January 2005

January 2006Total Ethanol Plants

50

54

56

61

68

72

81

95Ethanol Production Capacity

1701.7 mgy

1748.7 mgy

1921.9 mgy

2347.3 mgy

2706.8 mgy

3100.8 mgy

3643.7 mgy

4336.4 mgyPlants Under Construction

5

6

5

13

11

15

16

31Capacity Under Construction

77 mgy

91.5 mgy

64.7 mgy

390.7 mgy

483 mgy

598 mgy

754 mgy

1778 mgy _______________________  Source: Renewable Fuels Association - http://www.ethanolrfa.org/industry/statistics/  Increases in the demand for ethanol may not be commensurate with increasing supplies of ethanol. Thus, increased production of ethanol may lead to lower ethanol prices. The increased production of ethanol could also have other adverse effects. For example, increased ethanol production will lead to increased supplies of co-products from the production of ethanol, such as DDGS and CO2. Those increased supplies could lead to lower prices for those co-products. We cannot predict the future price of ethanol or DDGS. Any material decline in the price of ethanol or DDGS will adversely affect our sales and profitability. Also, the increased production of ethanol could result in increased demand for corn. This could result in higher prices for corn and cause higher ethanol production costs. Additionally, due to the fact that the price of ethanol usually moves with the price of wholesale unleaded
gasoline, we will not be able to pass any increases in corn costs on to the customer. This presents a risk to us as our margin will suffer greatly if corn prices increase while gasoline prices decrease.  We cannot rely on long-term ethanol orders or commitments by our customers for protection from the negative financial effects of a decline in the price for ethanol. The ethanol industry does not use fixed price long-term contracts. According to the Renewable Fuels Association (www.ethanolRFA.org/industry/statistics/), between 90% and 95% of the ethanol in the U.S. and Canada is sold pursuant to six to twelve month contracts, negotiated between the ethanol producer and the oil refiner or gasoline blender. As such, we believe that we will not be able to rely on long-term (over one year) contracts for the sale of our product. Entering in to a long-term contract would require us to give the buyer a significant discount to current market prices. We believe that if and when wecommence operations, it will be more profitable for
us to sell into the spot market and through a mixture of short-term (less than one year) contracts. The Chicago Board of Trade launched an ethanol futures contract in March 2005. As of the date of this Report, there has been limited trading activity in ethanol futures. There is no certainty that this market will develop sufficient liquidity to provide an effective means of hedging against a decline in ethanol prices. As a result, the limited certainty of ethanol orders can make it difficult for us to forecast our sales and allocate our resources in a manner consistent with our actual sales. Our expense estimates are based in part on our expectations of future sales and, if our expectations regarding future sales are inaccurate, we may be unable to reduce costs in a timely manner to adjust for sales shortfalls.  36       The market for fuel ethanol in Canada is extremely similar to the market in the United States. With free trade the border is essentially invisible to ethanol producers and cross-border selling is common. We intend to sell our product in the market that nets us the highest price at the time.  We will be dependent on a small number of customers because there are a finite number of petroleum refiners and mixers in North America. We intend to sell our ethanol to petroleum refiners and gasoline blenders in the Northeastern United States and Central Canada. According to Eco Energy Inc., there are upwards of fifty potential customers in our target market with whom they currently work. Our proposed Barrie location is close to Imperial Oils facility in Toronto, Ontario and Petro-Canadas facility in Oakville, Ontario, Canada. The Sarnia site is in close proximity to large refineries owned by Shell Canada and Suncor Energy. This comparatively small group of potential customers represents a risk compared to if our sales were less concentrated within a larger number of customers because a smaller group of customers can exert greater influence on our selling
prices and if we lose a customer or a customer becomes insolvent, we could experience a significant decrease in revenue. As many of our costs and expenses will be relatively fixed, a reduction in revenue could decrease our profit margins and adversely affect our business, financial condition and results of operations. We expect that the costs of transportation will allow us to ship our ethanol production competitively within a 300 mile radius of our Barrie and Sarnia facilities, although if there are shortages in markets outside of this area, market conditions at times may allow us to ship beyond this radius.  We have not conducted any significant business operations as yet and have been unprofitable to date. Accordingly, there is no prior operating history by which to evaluate the likelihood of our success or our contribution to our overall profitability. We may never complete construction of an ethanol production facility and commence significant operations or, if we do complete the construction of an ethanol production facility, it may not be successful in contributing positively to our profitability.  The market price of ethanol is dependent on many factors, including the price of gasoline, which is in turn dependent on the price of petroleum.These fluctuations may cause our results of operations to fluctuate significantly.Petroleum prices are highly volatile and difficult to forecast due to frequent changes in global politics and the world economy. The distribution of petroleum throughout the world is affected by incidents in unstable political environments, such as Iraq, Iran, Kuwait, Saudi Arabia, the former U.S.S.R. and other countries and regions. The industrialized world depends critically on oil from these areas and any disruption or other reduction in oil supply can cause significant fluctuations in the prices of oil and gasoline. As we cannot predict the future
price of oil or wholesale gasoline, this may lead to unprofitable prices for the sale of ethanol due to significant fluctuations in market prices. For example, the New York spot price of wholesale unleaded gasoline and ethanol rose from approximately $1.70 per gallon and $2.00 per gallon respectively in December 2005 to approximately $2.30 and over $4.00 per gallon, respectively, in June 2006. Since that time the price of wholesale gasoline and ethanol has fallen again to approximately $1.85 and $2.25 per gallon, respectively, as of February 28,2007. This move in part was linked to the price of petroleum reaching a historically high level, only to decline shortly thereafter. If the prices of gasoline and petroleum continue to decline we believe that the price of ethanol may be adversely affected. Fluctuations in the market price of ethanol may cause our profitability to fluctuate significantly.  We will be subject to extensive air, water and other environmental regulations in connection with the construction and operation of our planned ethanol production facilities.We cannot predict in what manner or to what extent governmental regulations will harm our business or the ethanol production and marketing industry in general.Our proposed business is subject to extensive regulation by federal and provincial governmental agencies in Canada,where we intend to initially produce and sell ethanol. In addition, we have recently signed a non-binding letter of intent to  37      acquire an existing ethanol plant in Quad County, Iowa. If we are successful in consummating this acquisition, of which there can be no assurance, or we acquire a different ethanol plant in the US or elect to build a new ethanol facility in the US, this business will also be subject to such extensive regulation.SeeITEM 1., DESCRIPTION OF BUSINESS. The production and sale of ethanol is subject to regulation by agencies of the US Federal Government, including, but not limited to, the Environmental Protection Agency (the EPA) in the US as well as other agencies in each jurisdiction in which ethanol is produced, sold, stored or transported. In Canada, the production and sale of ethanol is subject to regulation by Environment Canada, through the Canadian Environmental Protection Act 1999 and by the Ontario Ministry of the Environment.  Environmental laws and regulations that are expected to affect our planned operations are extensive and have become progressively more stringent. Applicable laws and regulations are subject to change, which could be made retroactively. Violations of environmental laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns. If significant unforeseen liabilities arise for corrective action or other compliance, our sales and profitability could be materially and adversely affected.  In addition, the production of ethanol involves the emission of various airborne pollutants, including particulates, carbon monoxide, oxides of nitrogen and volatile organic compounds. We also may be required to obtain various other water-related permits, such as a water discharge permit and a storm-water discharge permit, a water withdrawal permit and a public water supply permit. If for any reason we are unable to obtain any of the required permits, construction costs for our planned ethanol production facilities are likely to increase. In addition, the facilities may not be fully constructed at all. It is also likely that operations at the facilities will be governed by other regulations. Compliance with regulations may be time-consuming and expensive and may delay or even prevent sales of ethanol in Ontario or in other jurisdictions.  We will need to obtain various construction permits relating to our proposed ethanol plants and there can be no assurances that we will be able to obtain these permits, or that we will not incur significant delay in obtaining the same.As of the date of this Report we have begun obtaining those permits required relating to the construction of our proposed ethanol plants. Each of our proposed locations is located on an existing industrial site. Existing industrial sites typically require fewer permits because they already have road and rail access permits, water intake and discharge permits. We will be required to obtain a Site Plan Approval. The Site Plan Approval process entails submitting a detailed layout of the proposed plant including a landscape plan and items such as building finishes and an artists rendering showing what the
plant will look like from various street level views. While we do not believe that we will encounter any problem obtaining this permit from the local municipalities because the sites have existingfire suppression and storm water management systems in place, there can be no assurances that we will not experience a problem or delay in obtaining these permits. The general time period required for this permit is 90 days. We have filed the application for the relevant permits on our proposed Barrie plant and expect to receive Site Plan Approval by July 2007. For the Sarnia site, we have recently commenced this process and expect to receive our Site Plan Approval permit in 2007.  For our two proposed locations, environmental permits are issued by the Ministry of the Environment of Ontario. For the Barrie plant, in March 2007, we applied for this permit and expect to receive the final permit in June 2007. We expect that our Site Plan Approval permit and environmental permits for Sarnia, once submitted, will be processed within the same time frame as the Barrie permits. The receipt of environmental permits on existing industrial sites tends to be less onerous than on greenfield sites. Other permits that will be required are standard building permits that our EPC contractor will obtain as part of the obligations included in the EPC contract. There can be no assurances that we  38      will obtain all permits in a timely manner, or at all. Failure to obtain all necessary permits will have a significant negative impact on our proposed plan of operation.  We face a risk that the Government of Canada may institute a corn countervailing duty that could increase feedstock costs for our proposed Canadian plants.The Ontario corn market relies on imports from the United States to increase liquidity. The most recent corn countervailing duty was brought about in September 2005, by the Ontario Corn Producers. Originally, the Corn Producers successfully lobbied for a provisional countervailing duty that was effective from December 15, 2005 until April 18, 2006. On April 17, 2006, the Canadian International Trade Tribunal (CITT) found that the importation of grain corn from the U.S. had not caused and is not threatening to cause material injury to domestic Canadian corn producers despite a determined legal and public relations effort by Canadian corn producers to persuade the CITT that U.S.
subsidies, together with alleged dumping by U.S. producers of corn in Canadian markets were indeed causing such injury. In the event that a corn countervailing duty is enacted again, it is not expected to apply to product shipped back to the United States. Therefore, if we import U.S. corn into Canada and then export ethanol and DDGS to the U.S. we expect that we will be able to draw the duty back. However, we would not be able to recover the corn countervailing duty on any US produced corn used to make ethanol for sale in the Canadian market and we could be faced with higher corn prices in Ontario given the Ontario markets reliance on imported US corn.  Delays in our ability to obtain the financing necessary to commence construction of our proposed ethanol plants, delays in the construction of our planned ethanol production facilities or defects in materials and/or workmanship may occur. As of the date of this Report we have not begun construction of our proposed ethanol plants, nor do we have any commitment for all of the financing that is required to begin construction. No assurances can be provided that we will obtain the same.  Further, construction projects often involve delays in obtaining permits and encounter delays due to weather conditions, fire, the provision of materials or labor or other events. In addition, changes in interest rates or the credit environment or changes in political administrations at the federal, provincial, state or local levels that result in policy change towards ethanol or our project in particular, could cause construction and operation delays. Any of these events may adversely affect our ability to commence our proposed operations, which may expose us to additional unknown risks that arise due to such a delay.  As of the date of this Report, we expect the timeframe to the commencement of ethanol production at our planned Barrie facility to be as follows:  1.
Based on Ontario Ministry of Environment guidelines and communications, receive Ontario Ministry of Environment permit June 2007 2.
Based on EPC term sheet signed March 9, 2007 with AKSC, develop and negotiate EPC contract in July 2007 3.
Receive City of Barrie site plan approval in July 2007 4.
Based on EPC term sheet signed March 9, 2007 with AKSC, EPC pricing received from AKSC in July, 2007 5.
Based on EPC term sheet signed March 9, 2007 with AKSC, sign EPC contract in September 2007 6.
Based on requirements of West LB indicative term sheets dated December 13, 2006, close this financing in September or October of 2007 7.
With financing closed, give AKSC full notice to proceed following closing 8.
Based on discussions with AKSC, completion of site preparation work in November 2007 9.
Based on discussions with AKSC, EPC contractor mobilizes to site in November 2007 10.
Based on discussions with AKSC, first pour of concrete in December 2007 11.
Based on discussions with AKSC, start of plant commissioning in December 2008  39       12.
Based on EPC term sheet signed March 9, 2007 with AKSC, full operations of plant in April 2009  We expect the Sarnia plant start up will follow the Barrie timeline by approximately three months.  Any significant increase in the final construction costs of our proposed facilities will adversely affect our capital resources.We have estimated that the construction cost of our proposed two facilities to be approximately $454 million. The estimated cost of these facilities is based on the target EPC price range included in the AKSC term sheet executed on March 9, 2007 for our Barrie Plant, engineering estimates and on West LBs experience with other ethanol construction projects that they have financed, but the final construction cost of the facility may be significantly higher when firm EPC prices are received. We expect to receive a fixed EPC contract price from AKSC for our Barrie Plant in June 2007 and approximately 90 days later for Sarnia. Once executed, the EPC contracts will guarantee a fixed price for the
Barrie and Sarnia plants and that they will achieve 95% of their design capacity. Final construction costs however may vary from EPC contract prices due to possible price escalation factors that may be agreed to in the EPC contract on certain material inputs, force majeure events that the EPC contractor can not control and that may be exempted in the EPC contract from the fixed price guarantee, and change orders that we may request over the course of construction. While we will seek additional funding to deal with any adverse contingencies that may arise before construction is completed, there can be no assurances that we will be able to raise this additional capital to fund the cost of these variances, if they occur.  There is a risk that, because of the proposed location of our ethanol plants, we may incur additional costs for corn, water, electricity and natural gas, the raw materials required for the production of ethanol.The September 2006 Muse Stancil report, commissioned by the Company to assess the feasibility of its Barrie and Sarnia locations for ethanol production, estimated that these facilities will process approximately 78 million bushels of corn each year at expected annual production of 216 million gallons of ethanol and will require significant and uninterrupted supplies of water, electricity and natural gas. The prices for corn, electricity and natural gas have fluctuated significantly in the past and may fluctuate significantly in the future. In addition, droughts, severe winter weather and other problems may cause delays or
interruptions of various durations in the delivery of corn to our facilities, reduce corn supplies and increase corn prices.  In 2006, approximately 218 million bushels of corn were grown in Ontario, and an additional 96 million bushels were grown in Quebec. We anticipate sourcing approximately one-third (26,865,670 bushels) of our corn needs locally, with the balance (53,731,340 bushels) being purchased from the United States. A study performed by Muse Stancil & Co. suggests that we should expect to incur freight costs of $0.18 per bushel or $4,835,820 annually from Ohio to Sarnia, Ontario, and $0.70 per bushel or $18,805,969 annually from Ohio to Barrie, Ontario. The transportation of a large proportion of our corn presents a risk to the Company Ethanol as we would be negatively affected by increases in transportation costs.  The anticipated freight costs may also be higher than expected in the event of severe winter weather conditions. The locations chosen for our plants present a weather risk because significant snowfalls may result in transportation delays. Sarnia, Ontario receives annual snowfall of 51 inches on average and Barrie, Ontario receives average annual snowfall of 128 inches. We believe that having three  _________________________ SOURCES: http://www.statcan.ca/Daily/English/061207/d061207a.htm. Muse Stancil & Co., Corn and Distillers Grains Report  pg 3   40      ways to transport corn including via truck, rail, and freighter on the Great Lakes, will help reduce the risk of weather-related delays.  Additionally, local water, electricity and gas utilities may not be able to reliably supply the water, electricity and natural gas that our Barrie and Sarnia facilities will need or may not be able to supply such resources on acceptable terms. Although a stable supply exists for gas, water and electricity in the Barrie and Sarnia areas, localized conditions such as drought or severe weather conditions may affect the supply of raw materials to these areas from time to time over the life of the plant. Each proposed plant will require approximately 10,500 cubic ft. of gas per day, 1,000,000 US gallons of water per day and an average of 16 MW/hr of electricity. The loss of any of these utilities would cause us to shut down the plant until normal utilities are restored. We may not be able to successfully anticipate or mitigate fluctuations in the prices of raw materials and energy through the implementation
of hedging and contracting techniques. Our hedging and contracting activities may not lower our prices of raw materials and energy, and in a period of declining raw materials or energy prices, these hedging and contracting strategies may result in our paying higher prices than our competitors. In addition, we may be unable to pass increases in the prices of raw materials and energy to our customers. Higher raw materials and energy prices will generally cause lower profit margins and may even result in losses. Accordingly, our potential sales and profitability may be significantly and adversely affected by the prices and supplies of raw materials and energy.  We may be exposed to potential risks relating to our internal controls over financial reporting and our ability to have those controls attested to by our independent auditors.As directed by Section 404 of the Sarbanes-Oxley Act of 2002 (SOX 404), the Securities and Exchange Commission adopted rules requiring public companies to include a report of management on the companys internal controls over financial reporting in their annual reports, including Form 10-KSB. In addition, the independent registered public accounting firm auditing a companys financial statements must also attest to and report on managements assessment of the effectiveness of the companys internal controls over financial reporting as well as the operating effectiveness of the companys internal controls. We have not yet been
subject to these requirements. We are evaluating our internal control systems in order to allow our management to report on, and our independent auditors attest to, our internal controls, as a required part of our annual report on Form 10-KSB beginning with our reports for the fiscal year ended December 31, 2007. A recent release from the SEC has indicated that newly public companies may be granted an additional year after becoming public to demonstrate the effectiveness of their internal controls as required under SOX 404.  While we expect to expend significant resources in developing the necessary documentation and testing procedures required by SOX 404, there is a risk that we will not comply with all of the requirements imposed thereby. At present, there is no precedent available with which to measure compliance adequacy. Accordingly, there can be no positive assurance that we will receive a positive attestation from our independent auditors.  In the event we identify significant deficiencies or material weaknesses in our internal controls that we cannot remediate in a timely manner or we are unable to receive a positive attestation from our independent auditors with respect to our internal controls, investors and others may lose confidence in the reliability of our financial statements and our ability to obtain equity or debt financing could suffer.   _________________________ SOURCES: http://www.theweathernetwork.com/weather/stats/pages/C02022.htm?CAON0040   41       Risks Related to our Common Stock  Thereisno trading market for our securities and there can be no assurance that such a market will develop in the future. We have filed a registration statement on Form SB-2 with the Securities and Exchange Commission pursuant to the Securities Act of 1933, as amended, registering those shares that we issued in our recent private offering. In addition, an application to have our Common Stock listed for trading on the OTC Electronic Bulletin Board operated by the National Association of Securities Dealers, Inc. (NASD) has also been filed and is currently being reviewed. The process of obtaining a listing for our Common Stock on the OTCBB involves a market maker submitting an application with the NASD. The NASD then reviews the application and issues comments or questions concerning our Company and the class of stock (Common Stock) for
which a listing has been requested. There is no assurance that our application for listing on the OTCBB will be approved, or if so approved that a market will develop in the future or, if developed, that it will continue. In the absence of a public trading market, an investor may be unable to liquidate his investment in our Company.  We do not have significant financial reporting experience, which may lead to delays in filing required reports with the Securities and Exchange Commission and suspension of quotation of our securities on the OTCBB, which will make it more difficult for you to sell your securities.If we are successful in listing our Common Stock for trading on the OTCBB, of which there can be no assurance, the OTCBB limits quotations to securities of issuers that are current in their reports filed with the Securities and Exchange Commission (the SEC). Because we do not have significant financial reporting experience, we may experience delays in filing required reports with the SEC following the effectiveness of our registration statement. Because issuers whose securities are qualified for quotation on the OTCBB are required to
file these reports with the SEC in a timely manner, the failure to do so may result in a suspension of trading or delisting from the OTCBB. We have been late in filing some of the reports we have been required to file with the SEC but are reviewing our internal procedures to insure that future reports are filed in a timely manner.  If we are successful in listing our Common Stock for trading on the OTCBB, there are no automated systems for negotiating trades on the OTCBB and it is possible for the price of a stock to go up or down significantly during a lapse of time between placing a market order and its execution, which may affect your trades in our securities.Because there are no automated systems for negotiating trades on the OTCBB, they are conducted via telephone. In times of heavy market volume, the limitations of this process may result in a significant increase in the time it takes to execute investor orders. Therefore, when investors place market orders, an order to buy or sell a specific number of shares at the current market price, it is possible for the price of a stock to go up or down significantly during the lapse of time between
placing a market order and its execution.  Our stock will be considered a penny stock so long as it trades below $5.00 per share, This can adversely affect its liquidity. If and when trading commences our Common Stock will be considered a penny stock, so long as it trades below $5.00 per share and as such, trading in our Common Stock will be subject to the requirements of Rule 15g-9 under the Securities Exchange Act of 1934. Under this rule, broker/dealers who recommend low-priced securities to persons other than established customers and accredited investors must satisfy special sales practice requirements. The broker/dealer must make an individualized written suitability determination for the purchaser and receive the purchasers written consent prior to the transaction.  SEC regulations also require additional disclosure in connection with any trades involving a penny stock, including the delivery, prior to any penny stock transaction, of a disclosure schedule explaining the penny stock market and its associated risks. In addition, broker-dealers must disclose  42      commissions payable to both the broker-dealer and the registered representative and current quotations for the securities they offer. The additional burdens imposed upon broker-dealers by such requirements may discourage broker-dealers from recommending transactions in our securities, which could severely limit the liquidity of our securities and consequently adversely affect the market price for our securities. In addition, few broker-dealers are likely to undertake these compliance activities. Other risks associated with trading in penny stocks could also be price fluctuations and the lack of a liquid market.  We do not anticipate payment of dividends, and investors will be wholly dependent upon the market for the Common Stock to realize economic benefit from their investment. As holders of our Common Stock, you will only be entitled to receive those dividends that are declared by our Board of Directors out of retained earnings. We do not expect to have retained earnings available for declaration of dividends in the foreseeable future. There is no assurance that such retained earnings will ever materialize to permit payment of dividends to you. Our Board of Directors will determine future dividend policy based upon our results of operations, financial condition, capital requirements, reserve needs and other circumstances.  Any adverse effect on the market price of our Common Stock could make it difficult for us to raise additional capital through sales of equity securities at a time and at a price that we deem appropriate.If and when our registration statement is declared effective, holders of our shares of Common Stock that are registered pursuant to our registration statement will be permitted, subject to few limitations, to freely sell these shares of Common Stock. At that time, sales of substantial amounts of Common Stock, including shares issued upon the exercise of stock options issued pursuant to the Stock Plan we have adopted, or in anticipation that such sales could occur, may materially and adversely affect prevailing market prices for our Common Stock. In addition to the shares of Common Stock being registered herein, there is an
aggregate of 3,404,333 shares of our Common Stock underlying options that have been issued and which may be exercised over the next 12 month period. Also, an aggregate of 100,000,000 shares of our Common Stock have been held by certain non-affiliates of our Company (as that term is defined under the Securities Act of 1933, as amended) for a period sufficient to allow them to sell their shares subject to those limitations provided by Rule 144 promulgated under the Securities Act of 1933, as amended. In January 2007, these limitations shall cease and these holders will be entitled to sell their shares of our Common Stock at their discretion. If they do so, such sales could have a material and adverse affect on the prevailing market prices for our Common Stock, if and when such a market develops.  The market price of our Common Stock may fluctuate significantly in the future.If our Common Stock is approved for trading, of which there can be no assurance, the market price of our Common Stock may fluctuate in response to one or more of the following factors, many of which are beyond our control:  
the volume and timing of the receipt of orders for ethanol from major customers;
competitive pricing pressures;
our ability to produce, sell and deliver ethanol on a cost-effective and timely basis;
our inability to obtain construction, acquisition, capital equipment and/or working capital financing;
the introduction and announcement of one or more new alternatives to ethanol by our competitors;   43        
changing conditions in the ethanol and fuel markets;
changes in market valuations of similar companies;
stock market price and volume fluctuations generally;
regulatory developments; and
future sales of our Common Stock or other securities.  Furthermore, adverse economic conditions in Ontario and other jurisdictions could have a negative impact on our results of operations. Demand for ethanol could also be adversely affected by a slow-down in overall demand for oxygenate and gasoline additive products. The levels of our ethanol production and purchases for resale will be based upon forecasted demand. Accordingly, any inaccuracy in forecasting anticipated revenues and expenses could adversely affect our business. Furthermore, we recognize revenues from ethanol sales at the time of delivery. The failure to receive anticipated orders or to complete delivery in any quarterly period could adversely affect our results of operations for that period. Quarterly results are not necessarily indicative of future performance for any particular period, and we may not experience revenue growth or profitability on a quarterly or an annual
basis.  The price at which you purchase shares of our Common Stock may not be indicative of the price that will prevail in the trading market. You may be unable to sell your shares of Common Stock at or above your purchase price, which may result in substantial losses to you and which may include the complete loss of your investment. In the past, securities class action litigation has often been brought against a company following periods of stock price volatility. We may be the target of similar litigation in the future. Securities litigation could result in substantial costs and divert managements attention and our resources away from our business. Any of the risks described above could adversely affect our sales and profitability and also the price of our Common Stock.  ITEM 7.
FINANCIAL STATEMENTS   44       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS   PageReports of Independent Registered Public Accounting Firms
F-2 to F-3Consolidated Balance Sheets as of December 31, 2006 and 2005
F-4Consolidated Statements of Operations for the years ended December 31, 2006, 2005

and from November 29, 2004, date of inception, to December 31, 2006
F-5Consolidated Statement of Changes in Stockholders Equity for the years ended

December 31, 2006, 2005 and from November 29, 2004, date of inception, to

December 31, 2006
F-6Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005

and from November 29, 2004, date of inception, to December 31, 2006
F-7Notes to Consolidated Financial Statements
F-8 to F-25               F-1   45         REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  To the Shareholders and Board of Directors of Northern Ethanol, Inc.  We have audited the accompanying consolidated balance sheet of Northern Ethanol, Inc. and subsidiaries (a development stage company) as of December 31, 2006 and the related consolidated statements of operations, consolidated stockholders equity and comprehensive income and consolidated cash flows for the year ended December 31, 2006 and from November 29, 2004, date of inception, to December 31, 2006. These consolidated financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these consolidated statements based on our audits. The cumulative statements of operations, stockholders equity and comprehensive income and cash flows for the period from November 29, 2004, date of inception, to December 31, 2006 include amounts for each of the years in the two-year period ended December 31, 2005, which were audited by other auditors
whose report has been furnished to us, and in our opinion, insofar as it relates to the amounts included for the period November 29, 2004, date of inception, through December 31, 2005 is based solely on the report of the other auditors.  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. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Northern Ethanol, Inc. and subsidiaries (a development stage company) as of December 31, 2006 and results of their operations and their cash flows for the year ended December 31, 2006 and from November 29, 2004, date of inception, to December 31, 2006, in conformity with United States generally accepted accounting principles.  The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 a) to the consolidated financial statements, the Company is a development stage company and has no revenue, no earnings, and negative operating cash flows. These factors raise substantial doubt about the Companys ability to continue as a going concern. Managements plans in regard to these matters are described in note 11 d). These consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.  s/ KPMG LLP  Chartered Accountants, Licensed Public Accountants  Toronto, Canada April 26, 2007  F-2   46          REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM  To the Board of Directors Beaconsfield I, Inc. Buffalo, New York  We have audited the accompanying balance sheets of Beaconsfield I, Inc. (a development stage company) as of December 31, 2005 and 2004 and the related statements of operations, changes in stockholders equity and cash flows for the year ended December 31, 2005 and the periods November 29, 2004 (inception) through December 31, 2004 and 2005. 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 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. 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 Beaconsfield I, Inc. as of December 31, 2005 and 2004 and the results of its operations and its cash flows for the year ended December 31, 2005 and the periods November 29, 2004 (inception) through December 31, 2004 and 2005 in conformity with accounting principles generally accepted in the United States of America.  s/Raich Ende Malter & Co. LLP  RAICH ENDE MALTER & CO. LLP East Meadow, New York March 29, 2006          F-3  47       Northern Ethanol, Inc. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.) Consolidated Balance Sheets as of December 31, 2006 and 2005  2006



2005ASSETSCURRENT ASSETS:Cash and cash equivalents

$
561,715



$
13,390Accounts receivable


112,636




Deposits
402,308
Prepaid expenses
480,886
10,250Total current assets


1,557,545




23,640Property under development and equipment (note 3)


438,467




Assets under capital lease (notes 4 and 8)


17,233,707




Other assets


5,506




$
19,235,225



$
23,640LIABILITIES AND STOCKHOLDERS EQUITYCURRENT LIABILITIES:Accounts payable

$
117,371



$
2,000Accrued professional fees


125,000




3,098Current portion of obligation under capital lease (note 8)


18,993




Total current liabilities


261,364




5,098Obligation under capital lease (note 8)


16,031,367




16,292,731




5,098STOCKHOLDERS EQUITY:Preferred stock, $.0001 par value; 100,000,000 shares authorized; none issued and outstanding (note 7)







Common stock, $.0001 par value; 250,000,000 shares authorized;(104,096,500 and 101,500,000 shares issued and outstanding as of December 31, 2006 and 2005, respectively (note 7))


10,410




10,150Additional paid-in capital


5,554,459




39,865Deficit accumulated during the development stage


(3,276,873
)



(31,473
)Accumulated other comprehensive income


654,498




2,942,494




18,542Going concern (note 2 a))Commitments (note 10)Subsequent events (note 11)$
19,235,225



$
23,640  See accompanying notesto consolidated financial statements  F-4  48       Northern Ethanol, Inc. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.) Consolidated Statements of Operations For the years ended December 31, 2006, 2005 and from November 29, 2004, date of inception, to December 31, 2006   For the years ended

December 31

Nov 29, 2004(Inception) toDecember 312006


2005


2006REVENUES

$


$


$
COST OF GOODS SOLD








GROSS MARGIN








OPERATING EXPENSESSalaries and benefits (note 6)


2,153,342





2,153,342General and administrative


970,351


27,765


1,001,824Occupancy costs


99,644





99,644Depreciation


22,063





22,0633,245,400


27,765


3,276,873NET LOSS

$
(3,245,400
)
$
(27,765
)
$
(3,276,873
)BASIC AND DILUTED LOSS PER SHARE

$
(0.03
)
$
(0.00
)WEIGHTED AVERAGE COMMONSHARES OUTSTANDING


102,534,308


101,500,000   See accompanying notes to consolidated financial statements  F-5  49       Northern Ethanol, Inc. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.) Consolidated Statement of Stockholders Equity and Comprehensive Income For the years ended December 31, 2006, 2005 and from November 29, 2004, date of inception, to December 31, 2006   Common StockShares



Amount



AdditionalPaid-InCapital



AccumulatedDeficit



AccumulatedOtherComprehensiveIncome



TotalInception, November 29, 2004Stock issued for cash

101,500,000



$
10,150



$
39,865



$




$




$
50,015Net loss for the period November 29, 2004 (inception) to December 31, 2004
















(3,708
)








(3,708
)Balances, December 31, 2004

101,500,000



$
10,150



$
39,865



$
(3,708
)


$




$
46,307Net loss for the year ended December 31, 2005
















(27,765
)








(27,765
)Balances, December 31, 2005

101,500,000



$
10,150



$
39,865



$
(31,473
)


$




$
18,542Shares cancelled (note 7)

(1,500,000
)



(150
)



150














Options issued for services











1,668,354














1,668,354Stock issued for cash,net of issuance costs

4,096,500




410




3,846,090














3,846,500Cumulative translation adjustment





















654,498




654,498Net loss for the year ended December 31, 2006
















(3,245,400
)








(3,245,400
)Balances, December 31, 2006

104,096,500



$
10,410



$
5,554,459



$
(3,276,873
)


$
654,498



$
2,942,494   See accompanying notes to consolidated financial statements  F-6  50       Northern Ethanol, Inc. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.) Consolidated Statements of Cash Flows For the years ended December 31, 2006, 2005 and from November 29, 2004, date of inception, to December 31, 2006  For the years endedDecember 31,


November 29, 2004 (Inception toDecember 31,2006



2005


2006CASH FLOWS FROM INVESTING ACTIVITIES:Net loss

$
(3,245,400
)


$
(27,765
)

$
(3,276,873)Items not involving cash:Depreciation


22,063








22,063Stock-based compensation


1,668,354








1,668,354Changes in non-cash working capital balances:Accounts receivable


(112,636
)







(112,636)Deposits


(402,308
)







(402,308)Prepaid expenses


(470,636
)



(750
)


(480,886)Accounts payable


115,371




2,000



117,371Accrued liabilities


121,902




2,390



125,000Other


(52,972
)







(52,972)Net cash (used in) provided by operating activities


(2,356,262
)



(24,125
)


(2,392,887)CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from issuance of common stock


3,846,500








3,896,515Principal payment of capital lease obligation


(3,735
)







(3,735)Net cash (used in) provided by financing activities


3,842,765








3,892,780CASH FLOWS FROM INVESTING ACTIVITIES:Purchase of property under development and equipment


(460,530
)







(460,530)Assets under capital lease


(472,142
)







(472,142)Other assets


(5,506
)







(5,506)Net cash (used in) provided by investing activities


(938,178
)







(938,178)NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS


548,325




(24,125
)


561,715CASH AND CASH EQUIVALENTS:Beginning of period


13,390




37,315



End of period

$
561,715



$
13,390


$
561,715SUPPLEMENTAL CASH FLOW INFORMATIONAssets acquired under capital lease

$
16,761,565



$



$
16,761,565Cash paid for income taxes











353  See accompanying notes to consolidated financial statements    F-7  51        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  1.
OVERVIEW:  The Company was incorporated as Beaconsfield I, Inc. in the State of Delaware on November 29, 2004, as a blank check company for the purpose of engaging in the potential future merger or acquisition of an unidentified target business.  On December 15, 2004, the Company issued 150,000 shares of its Common Stock for a total of $15 in cash. Additionally on that date, the Company issued 10,000,000 shares (pre-forward split) of its Common Stock, for a total of $50,000 in cash.  In July 2006, the Company engaged in a forward split of its Common Stock whereby it issued ten (10) shares of its Common Stock for every one (1) share then issued and outstanding. All references in these consolidated financial statements and notes to our issued and outstanding Common Stock are provided on a post-forward split basis, unless otherwise indicated.  In July 2006, the holders of a majority of the then issued and outstanding Common Stock approved an amendment to the Certificate of Incorporation wherein the Companys name was changed to Northern Ethanol, Inc. to better reflect its current business plan. Northern Ethanol, Inc. is currently considered a development stage company.  The Company has two wholly-owned subsidiaries, Northern Ethanol, LLC, a New York limited liability company and Northern Ethanol (Canada) Inc., a Canadian corporation, which has three wholly-owned subsidiaries, Northern Ethanol (Barrie) Inc., Northern Ethanol (Sarnia) Inc. and Northern Ethanol Investments Inc., each of which is also a Canadian corporation.  2.
SIGNIFICANT ACCOUNTING POLICIES:  a)
Basis of presentation  Going concern:  There is substantial doubt about the Companys ability to continue as a going concern.  These consolidated financial statements have been prepared on a going concern basis, which assumes that the Company will commence ethanol producing operations in the foreseeable future and accordingly will be able to realize its assets and discharge its liabilities in the normal course of operations. The Company has no revenue, no earnings, and negative operating cash flows, and has financed its activities through the issuance of shares and capital lease arrangements. The Companys ability to continue as a going concern is dependent on obtaining investment capital and achieving profitable operations. There can be no assurance that the Company will be successful in raising sufficient investment capital to commence ethanol producing operations and to generate sufficient cash flows to continue as a going concern. These consolidated financial statements do not reflect the adjustments that might be
necessary to the carrying amount of reported assets, liabilities and revenue and expenses and the balance sheet classification used if the Company were unable to commence ethanol producing operations in accordance with this assumption. F-8  52        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued):  Consolidation:  The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries. All intercompany balances and transactions are eliminated on consolidation. Comparatives:  Certain items in the comparative statements have been reclassified to be consistent with the presentation in the current year.  b)
Use of estimates:  The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the reported amounts of revenues and expenses and the disclosure of contingent liabilities. Actual results may differ from these estimates.  c)
Cash and cash equivalents:  Cash and cash equivalents consist of all highly-liquid investments with an original maturity of three months or less. Such investments are stated at cost plus accrued interest, which approximates market value.  d)
Property under development and equipment:  Computer equipment and software are recorded at cost and depreciated on a straight-line basis over their estimated useful life of three years.  Furniture and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful life of ten years.  Leasehold improvements are recorded at cost and depreciated on a straight-line basis over the shorter of the term of the lease and their estimated useful life.  Property under development consists of engineering, site design, permitting, and other development costs related to preparation for the construction of ethanol production facilities.  Depreciation and amortization commences at the time when the assets are available for use in operations.   F-9  53        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued):  e)
Leases:  The Company follows the guidance in Statement of Financial Accounting Standard (SFAS) No. 13 Accounting for Leases, as amended, which requires the Company to evaluate the lease agreements it enters into to determine whether they represent operating or capital leases at the inception of the lease.  f)
Impairment of long-lived assets:  Long-lived assets are reviewed for impairment at least annually or whenever events or changes in circumstance indicate that the carrying amount of the asset may not be recoverable. Recoverability is measured by a comparison of the carrying amount of an asset to estimated undiscounted cash flows expected to be generated by the long-lived asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized for the amount that the carrying amount exceeds the fair value of the particular assets.  g)
Capitalized interest:  In accordance with SFAS No. 34, the interest costs associated with the Companys capital lease obligation will be capitalized to assets under capital lease until the Barrie plant is substantially complete and ready for the production of ethanol.  h)
Stock-based compensation:  Effective January 1, 2006, the Company adopted Financial Accounting Standards Board (FASB) SFAS No. 123R, Share Based Payment. SFAS 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost is recognized on a straight-line basis over the employee service period (usually the vesting period). That cost is measured based on the fair value of the equity or liability instruments issued using the Black-Scholes option pricing model.      F-10  54        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued):  i)
Foreign currency translation:  The functional currency of the Company is United States dollarsand the functional currency of its Canadian subsidiaries is Canadian dollars. The operations of the Canadian subsidiaries are translated into U.S. dollars in accordance with SFAS No. 52 Foreign Currency Translation as follows:  (i)
Assets and liabilities at the rate of exchange in effect at the balance sheet date; and  (ii)
Revenue and expense items at the average rate of exchange prevailing during the period  Translation adjustments are included as a separate component of stockholders equity (deficiency) as a component of comprehensive income or loss.  The Company and its subsidiaries translate foreign currency transactions into the Companys functional currency at the exchange rate effective on the transaction date. Monetary items denominated in foreign currencies are translated into the functional currency at exchange rates in effect at the balance sheet date. Foreign exchange gains and losses are included in income.  j)
Income taxes:  Deferred income tax assets and liabilities are recognized for the estimated future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, and are measured using enacted tax rates expected to apply in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is provided when it is more likely than not that the full benefit of the deferred tax assets will not be realized.  k)
Earnings (loss) per common share:  The Company computes net loss per common share using SFAS No. 128 Earnings Per Share. Basic loss per common share is computed based on the weighted average number of shares outstanding for the period. Diluted loss per share is computed by dividing net loss by the weighted average common shares outstanding assuming all dilutive potential common shares were issued.  l)
Fair value of financial instruments:  The carrying value of cash and cash equivalents, other current assets, accrued expenses and accounts payable approximates fair value due to the short period of time to maturity. The carrying value of the obligation under capital lease approximates fair value as the discount rate of 12% in the capital lease approximates current market rates of interest available to the Company for the same or similar debt instruments.  F-11  55        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued):  m)
Financial statement misstatements:  In September 2006, the SEC issued Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements(SAB 108). SAB No. 108 addresses how to quantify the effect of an error on the financial statements and requires a dual approach to compute the materiality of the misstatement. Specifically, the amount of the misstatement is to be computed using both the rollover (i.e., the current year income statement perspective) and the iron curtain (i.e., the year-end balance sheet perspective). SAB 108 is effective for fiscal years ending after November 15, 2006, and accordingly, the Company adopted SAB No. 108 in the fourth quarter of 2006. The adoption of SAB 108 did not have a material impact on the
Companys consolidated financial statements.  n)
Recent Accounting Pronouncements  In February 2006, the Financial Standards Board (FASB) issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments-an amendment of FASB Statements No.133 and 140. SFAS No. 155 allows financial instruments that contain an embedded derivative and that otherwise would require bifurcation to be accounted for as a whole on a fair value basis, at the holders election. SFAS No. 155 also clarifies and amends certain other provisions of SFAS No. 133 and 140. This statement is effective for all financial instruments acquired or issued in fiscal years beginning after September 15, 2006. The adoption of SFAS No. 155 is not expected to have a material impact on the Companys consolidated financial condition or results of operations.  In March 2006, the FASB issued SFAS No. 156,Accounting for Servicing of Financial Assets-an amendment of FASB Statement No.140.SFAS No. 156 provides guidance on the accounting for servicing assets and liabilities when an entity undertakes an obligation to service a financial asset by entering into a servicing contract. This statement is effective for all transactions in fiscal years beginning after September 15, 2006. The adoption of SFAS No. 156 is not expected to have a material impact on the Companys consolidated financial condition or results of operations.      F-12  56        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  2.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued):  n)
Recent Accounting Pronouncements (Continued)  In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes  an interpretation of FASB Statement No.109(FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is in the process of evaluating the impact, if any, FIN 48 will have on its consolidated financial statements.  In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements.SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy as defined in the standard. Additionally, companies are required to provide enhanced disclosure regarding financial instruments in one of the categories (level 3), including a reconciliation of the beginning and ending balances separately for each major category of assets and liabilities. SFAS No.157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS No. 157 is
not expected to have a material impact on the Companys consolidated financial statements.  In September 2006, the FASB issued SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plans.SFAS No. 158 requires the recognition of the funded status of a defined benefit plan in the balance sheet; the recognition in other comprehensive income of gains or losses and prior service costs or credits arising during the period but which are not included as components of periodic benefit cost; the measurement of defined benefit plan assets and obligations as of the balance sheet date; and disclosure of additional information about the effects on periodic benefit cost for the following fiscal year arising from delayed recognition in the current period. In addition, SFAS No. 158 amends SFAS No. 87, Employers Accounting for Pensions, and SFAS No. 106,
Employers Accounting for Postretirement Benefits Other Than Pensions, to include guidance regarding selection of assumed discount rates for use in measuring the benefit obligation. The recognition and disclosure requirements of SFAS No. 158 are effective for the Companys year ended December 31, 2006. The measurement requirements are effective for fiscal years ending December 31, 2008.The Company does not believe the adoption of SFAS No.158 will have a material impact on its consolidated financial statements.   F-13   57       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  n)
Recent Accounting Pronouncements (Continued)  In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS No. 159). Under the provisions of SFAS No. 159, companies may choose to account for eligible financial instruments, warranties and insurance contracts at fair value on a contract-by-contract basis. Changes in fair value will be recognized in earnings each reporting period. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The Company is required to adopt the provisions of SFAS No. 159 effective January 1, 2008. The Company is currently assessing the impact of the adoption of SFAS No. 159.  3.
PROPERTY UNDER DEVELOPMENT AND EQUIPMENT:  December 31, 2006

Cost

AccumulatedDepreciation

Net bookValueComputer equipment and software

$
37,966

$
8,307

$
29,659Furniture and equipment


168,894


10,286


158,608Leasehold improvements


34,958


3,470


31,488Property under development


218,712





218,712$
460,530

$
22,063

$
438,467   December 31, 2005

Cost

AccumulatedDepreciation

Net bookValueComputer equipment and software

$


$


$
Furniture and equipment








Leasehold improvements








$


$


$
  4.
ASSETS UNDER CAPITAL LEASE:  December 31, 2006

Cost

AccumulatedDepreciation

Net bookValueAssets under capital lease

$
17,233,707

$


$
17,233,707  December 31, 2005

Cost

AccumulatedDepreciation

Net bookValueAssets under capital lease

$


$


$
   F-14  58       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  4.
ASSETS UNDER CAPITAL LEASE (Continued):  Assets under capital lease consist of land and buildings located in Barrie, Ontario to be developed for ethanol producing operations. Management determined that the fair value of the land at the Barrie site was less than 25% of the fair value of the leased property at the inception of the lease and therefore considered the land and building as a single unit for purposes of determining whether the lease should be classified as a capital lease in accordance with SFAS No. 13. Management concluded that the present value of the minimum lease payments, excluding any executory costs to be paid by the lessor, equals or exceeded 90% of the fair value of the leased property. The Company used its incremental borrowing rate of 12% to measure the present value of the minimum lease payments.  The buildings under capital lease at the Barrie site cannot currently be used to carry out the business of the Company without extensive renovation and construction activities. As such, management considers that the assets are not available for their intended use. Specifically, management expects to make substantial renovations to portions of the existing building to provide the space needed to construct an ethanol processing facility. The portion of the building that will eventually serve as the administrative offices requires extensive renovation in order to bring it up to standard for occupation. Managements initial examination of the infrastructure items has indicated that substantial additional expenditures will be required to ensure that rail lines are serviceable, and in correct locations, and that the gas and water lines can be expanded to provide the required capacity for the plant
operations. Before commencing demolition and construction activities, the Company will use the findings of an engineering study that will be performed, with detailed recommendations on the usefulness of individual assets. The Company will write-off any portion of the buildings that may be demolished.  During the year ended December 31, 2006, the Company capitalized interest costs of $321,979, lessors operating cost charges of $87,595 and property tax of $62,568 to the cost of the assets under capital lease at the Barrie property that is being developed into an ethanol production facility. The Company will not capitalize costs to assets under capital leases beyond what is recoverable from operations. Depreciation of capital assets will commence once they are determined to be available for their intended use. The assets will be depreciated over the lesser of their estimated useful life or the remaining lease term.  5.
RELATED PARTY TRANSACTIONS:  During the year, the Company repaid $2,000 to Corsair Advisors, Inc., an entity owned by a stockholder, for advances it had made on behalf of the Company prior to December 31, 2005. This $2,000 amount was included in accounts payable at December 31, 2005.  The Company utilized the office space and equipment of a stockholder at no cost, until April 2006, when the Company entered into a lease for office space, as further discussed in note 8. During April 2006, the Company, through a Canadian subsidiary, entered into the Barrie lease for property to be used as an ethanol processing facility, as further discussed in note 8. These leases were entered into with Fercan Developments Inc., a company owned by the same individual that owns Rosten Investments Inc. (Rosten). Rosten owns 10,000,000 shares of the Companys outstanding common stock or 9.5% interest. F-15  59       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  5.
RELATED PARTY TRANSACTIONS (Continued):  In September 2006, the Company deposited $200,000 in trust with Aurora Beverage Corporation, a company owned by the same individual that owns Rosten, to hold storage tanks for possible use in ethanol production. This refundable deposit gave the Company a right of first refusal to purchase the tanks for a period of 180 days at a price to be negotiated. Following a decision not to utilize these storage tanks, the Company was refunded this deposit in February 2007.  During the year ended December 31, 2006, the Company paid Andrew I. Telsey, P.C. $86,324 in fees and expenses for corporate and securities counsel. Of this amount $8,758 was included in accounts payable at December 31, 2006.  Andrew I. Telsey, the Companys Corporate Secretary and one of its Directors, is the sole shareholder of Andrew I. Telsey, P.C.  During the year ended December 31, 2006, the Company purchased $59,202 in furniture and design services from Dragonfly Design Group, a company owned by the adult daughter of the Companys Chairman, President and Chief Executive Officer. Of this amount $9,791 was included in accounts payable at December 31, 2006.  6.
STOCK OPTIONS:  On April 4, 2006, the Company approved the 2006 Stock Plan (the Plan) and reserved 8,000,000 shares of common stock for issuance under the Plan.  On April 12, 2006, pursuant to an employment agreement, the Company granted options to purchase an aggregate of 2,000,000 shares of the Companys common stock at an exercise price equal to $1.00, to its Chief Executive Officer. The options will vest in equal amounts each quarter over the next two years from the date of grant. The options expire five years following the date of grant.  On April 21, 2006, pursuant to an employment agreement, the Company granted options to purchase an aggregate of 500,000 shares of the Companys common stock at an exercise price equal to $1.00, to its Chief Financial Officer. The options were to vest in equal amounts each quarter over the next two years from the date of grant. The options were to expire five years following the date of grant. These options were forfeited with the resignation of the Chief Financial Officer on October 31, 2006.  On May 1, 2006 and on June 8, 2006, the Company granted options to purchase an aggregate of 224,000 shares of the Companys common stock at an exercise price equal to $1.00, to certain new employees. The options will vest in equal amounts each quarter over the next two years from the date of grant. The options expire five years following the date of grant.  On July 15, 2006, pursuant to an employment agreement, the Company granted options to purchase an aggregate of 300,000 shares of the Companys common stock at an exercise price equal to $1.00, to its Chief Operating Officer. The options will vest in equal amounts each quarter over the next three years from the date of grant. The options expire five years following the date of grant.   F-16  60       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  6.
STOCK OPTIONS (Continued):  On September 8, 2006, the Company granted options to purchase an aggregate of 250,000 shares of the Companys common stock at an exercise price equal to $1.00, to the non-salaried Directors of the Company. The options vested immediately at the date of grant. The options expire five years following the date of grant. Also on September 8, 2006, pursuant to a consulting agreement, the Company granted options to purchase an aggregate of 200,000 shares of the Companys common stock at an exercise price equal to $1.00, to a Director. The options will vest at a rate of 50,000 shares in equal amounts each quarter over the first year from the date of grant, 50,000 shares in equal amounts each quarter over the second year from the date of grant and 100,000 shares in equal amounts each quarter over the third year from the date of grant. The options expire five years following the date of
grant.  On November 2, 2006, the Company granted options to purchase an aggregate of 900,000 shares of the Companys common stock at an exercise price equal to $1.00 to non-employees. The options will vest in equal amounts each quarter over one year from the date of grant. The options expire five years following the date of grant.  Also on November 2, 2006, the Company granted options to purchase 100,000 shares of the Companys common stock at an exercise price equal to $1.00, to a non-salaried Director of the Company. The options will vest in equal amounts annually over the next three years from the date of grant. The options expire five years following the date of grant.  Additionally, on November 2, 2006, pursuant to an employment agreement, the Company granted options to purchase an aggregate of 90,000 shares of the Companys common stock at an exercise price equal to $1.00, to its new Chief Financial Officer. The options will vest in equal amounts each quarter over the next 27 months from the date of grant. Also on November 2, 2006, pursuant to an employment agreement, the Company granted options to purchase an aggregate of 75,000 shares of the Companys common stock at an exercise price equal to $1.00, to a new employee. The options will vest in equal amounts annually over the next three years from the date of grant. The options expire five years following the date of grant.  A summary of the status of Companys stock option plan as of December 31, 2006 and of changes in options outstanding under the Companys plan during the year is as follows:  Number of Shares



Weighted Average Exercise PriceOutstanding at December 31, 2005





$
Granted

4,639,000




1.00Exercised






Forfeited

500,000




1.00Outstanding at December 31, 2006

4,139,000



$
1.00Options exercisable at December 31, 2006

1,297,553



$
1.00Non-vested options at December 31, 2006

2,841,447



$
1.00  F-17  61       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  6.
STOCK OPTIONS (Continued):  Stock options outstanding as of December 31, 2006, were as follows:  Options Outstanding

Options ExercisableExercise Price

Number Outstanding

Weighted Average RemainingContractual Life

Weighted-AverageExercisePrice

NumberExercisable

WeightedAverageExercisePrice$
1.00

4,139,000

4.49

$
1.00

1,297,553

$
1.00  The fair value of each option granted was estimated on the date of the grant using the Black-Scholes option pricing model with the following assumptions:  Risk-free interest rate

5.1
%Volatility factor of the future expected market priceof the Companys common shares

86.6
%Weighted average expected life in years

5.0Weighted average forfeiture rate

2.8
%Expected dividends

None  The fair value of the options granted as determined above was $2,746,874, of which $1,668,354 was expensed in fiscal 2006.  7.
CAPITAL STOCK:  Holders of shares of common stock are entitled to cast one vote for each share held at all stockholders meetings for all purposes, including the election of directors. The common stock does not have cumulative voting rights.  The preferred stock of the Company shall be issued by the Board of Directors of the Company in one or more classes or one or more series within any class, and such classes or series shall have such voting powers, full or limited or no voting powers, and such designations, preferences, limitations or restrictions as the Board of Directors of the Company may determine, from time-to-time.  Holders of shares of stock of any class shall not be entitled as a matter of right to subscribe for or purchase or receive any part of any new or additional issue of shares of stock of any class, or of securities convertible into shares of stock of any class, whether now hereafter authorized or whether issued for money, for consideration other than money, or by way of dividend.    F-18  62       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  7.
CAPITAL STOCK (Continued):  During the year ended December 31, 2006, the Company received gross proceeds of $4,096,500 under the terms of a unit subscription agreement that provided for the purchase of one share of common stock for $1.00 in a private placement. Cost of issuance related to raising these funds amounted to $250,000. In September 2006, sales of the units of the Companys common stock under these agreements were completed and 4,096,500 shares of common stock were issued. The Company did not grant registration rights to these investors.  On May 19, 2006 three founding shareholders of the Company, each owning 500,000 shares of the common stock of the Company, agreed to surrender a portion of their stock ownership to the Company for cancellation. In total, 1,150,000 shares were surrendered. The Company transferred $115 from common stock to additional paid in capital.  Effective July 3, 2006, the Companys shareholders approved an increase in the authorized capital stock of the Company from 80,000,000 shares of $0.0001 par value stock to 350,000,000 shares of authorized capital stock, consisting of 250,000,000 shares of common stock having a par value of $0.0001 per share, and 100,000,000 shares of preferred stock, having a par value of $0.0001 per share  On July 5, 2006, the Company affected a ten-for-one forward stock split of its common stock to holders of record on that date. The number of commons shares and options presented in these consolidated financial statements and notes has been revised for the ten-for-one stock split.  On September 8, 2006, the three founding shareholders of the Company, each owning 500,000 shares of the common stock of the Company, agreed to surrender the balance of their stock ownership to the Company for cancellation. In total, 350,000 shares were surrendered. The Company transferred $35 from common stock to additional paid in capital.  8.
LEASE AGREEMENTS:  On April 20, 2006, the Company entered into a lease agreement through its wholly-owned subsidiary, Northern Ethanol (Barrie) Inc, for a 25 year lease, with two ten year optional renewal periods, on an industrial property located in Barrie, Ontario, Canada, (the Barrie Lease), on which it intends to construct an ethanol processing facility.  The Company also entered into a five year lease on April 20, 2006 through its wholly-owned subsidiary, Northern Ethanol (Canada) Inc., for office premises located in Toronto, Ontario, Canada to be used for its head office (the Head Office Lease). The terms of the office lease at the Toronto location require it to be accounted for as an operating lease.     F-19  63        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  8.
LEASE AGREEMENTS (continued):  The terms of the leases require the following minimum payments:  Fiscal Year


Barrie Lease


Head OfficeLease


Total2007


$
1,947,833


$
154,453


$
2,102,2862008



1,947,833



154,453



2,102,2862009



1,947,833



154,453



2,102,2862010



1,947,833



154,453



2,102,2862011



1,947,833



64,355



2,012,188Thereafter



43,078,276







43,078,276Total minimum lease payments


$
52,817,441


$
682,167


$
53,499,608Less amount representing interest of 12%



36,767,08116,050,360Less current portion



18,993$
16,031,367  The Barrie lease payments are due on a monthly basis starting in November 2006. Upon commissioning of the ethanol facility at the Barrie location, the value of the capital lease will be amortized on a straight line basis over the period remaining in the 25 year term. The interest cost implicit in the capital lease obligation will be recognized at the 12% rate implicit in the lease, and will be calculated on a monthly basis on the balance outstanding at each month end. Since the lease payments are in Canadian dollars, the actual amortization and interest cost reflected in the account will vary as the exchange rate changes.  The Barrie lease provides for two renewal periods of ten years under the same terms and conditions, at the market rates for similar properties in the area at the time of renewal. The lease requires total payments of C$61,553,443 ($52,817,441) over the remaining term of the lease, of which C$42,848,353 ($36,767,081) is interest and C$18,705,090 ($16,050,360) is the repayment of the capital lease amount. The capital lease principal will be paid down by C$22,135 ($18,993) as a result of monthly lease payments that will be made over the next year.  Effective January 24, 2007, under agreement with the lessor, the monthly lease payments under the Barrie lease were deferred until the completion of an engineering study to determine the extent of the renovation of the buildings on the leased property. This study and any amendment to the lease are expected to be completed in March 2007.     F-20  64       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  9.
INCOME TAXES:  The tax effect of temporary differences that give rise to significant portions of future tax assets as at December 31 are as follows:  2006



2005Deferred tax assets:Property under development and equipment



$
8,000



$
Obligation under capital lease




6,033,000




Eligible capital expenditures




2,000




1,000Start-up costs  United States




178,000




9,000Non-capital loss  Canada




562,000




6,783,000




10,000Deferred tax liabilities:Assets under capital lease




(6,204,000
)



579,000




10,000Less: valuation allowance




579,000




10,000Net deferred tax asset



$




$
  The Company has available a Canadian non-capital loss carryforward of approximately C$1,787,000 ($1,562,000). This loss expires in 2026.           F-21  65       NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  10.
COMMITMENTS:  a)
Effective July 24, 2006, the Company entered into a five-year Project Development Agreement with Delta-T Corporation, Williamsburg, Virginia (Delta), wherein Delta agreed to provide professional advice, business and technical information, design and engineering and related services to assist in assembling all of the information, permits, agreements and resources necessary for the construction of an ethanol plant having a production capacity of 108 million gallons per year in Barrie, Ontario, Canada. Delta was paid $100,000 in advance for their future services and the non-refundable amount was capitalized to property under development. In September 2006, the Company entered into a similar agreement with Delta relating to the construction of an ethanol plant having a production capacity of 108 million gallons per year in Sarnia, Ontario, Canada. Delta was paid an initial
amount of $70,000 and that non-refundable amount was recorded as a prepaid expense at December 31, 2006. The remaining balance of $30,000 due Delta will be paid upon issuance of an air permit by the Province of Ontario. No further amounts are payable under the terms of the Delta agreements. The relationship between Delta and the Company is exclusive during the five-year term of the Agreement whereby the Company agreed to use its best efforts to enter into an engineering procurement and construction contract or a technology agreement with Delta at these locations and if we fail to do so, to give them a first right of refusal for 60 days to assume any agreements made with other ethanol plant technology vendors.  b)
On August 18, 2006, the Company entered an Agreement for Procurement and Merchandizing Services with Parrish & Heimbecker, Ltd (P&H), wherein P&H shall provide the Company with a commodity and currency hedging system in order to protect the Company from the risk of currency and raw material price fluctuations. In addition, P&H will source all the corn required for the operation of the Companys planned plants in Barrie and Sarnia, Ontario at the best possible prices and in a pattern that meets the plants processing requirements. P&H will also manage the sale of the Companys dried distiller grain by-product. The Company will pay P&H C$1.00 per metric tonne of corn procured and C$1.00 per metric tonne of dried distiller grain sold for its Barrie and Sarnia operations. There are no minimum purchase quantities to P&H. The term of the
Agreement is five years.       F-22  66        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  10.
COMMITMENTS (continued):  c)
Effective December 13, 2006, the Company executed an engagement letter and indicative term sheets with WestLB AG (WestLB) whereby WestLB has conditionally agreed to solicit and arrange for senior debt and subordinate debt financing for up to 75% of the construction costs (to a maximum of approximately $365 million) of our Barrie and Sarnia facilities on a best efforts basis. The term best efforts means that West LB believes that they can syndicate the debt financing we require but that there is no guarantee that they will be successful or that the terms will be as indicated in their term sheets until they market the transaction and receive firm commitments from a syndicate of lenders for the funds required on acceptable terms to the Company. Among other things, the provision of the 75% financing in accordance with the engagement letter and the
indicative term sheetsis conditional on the Company obtaining subordinate debt or equity investment for the remaining 25% of construction costs. The WestLB indicative term sheets offer first priority senior secured construction and term financing for up to 60% of the total capital requirements of plant construction and for working capital for a total term of up to 7.5 years and subordinated secured construction and term financing for up to 15% of the total capital requirements of plant construction for a total term of up to eight years. Following conversion of the senior construction loan to a senior term loan, the loan amount is to be repaid in equal quarterly installments over six years. Surplus cash as defined by debt service covenant is to be swept to accelerate the repayment of the senior term loan and to repay the subordinated term loan. The Company paid a non-refundable retainer deposit of $200,000 to West LB on execution of
the engagement letter and indicative term sheets. This payment has been recorded as a deposit at December 31, 2006. In the event that WestLB engagement is terminated by the Company and it enters into a similar debt financing with another lender within 12 months of terminating WestLB, the Company will pay WestLB a termination fee of $5,000,000 if termination occurs within 60 days from December 6, 2006 and $10,000,000 thereafter. If the financing contemplated in the engagement letter and indicative term sheets is finalized with WestLB, the Company will pay to WestLB a structuring and arrangement fee of the greater of $5,000,000 or 2% of the principal amount of the senior financing and $5,000,000 or 2% of the principal amount of the subordinated financing. In addition, the Company will pay a fee to market the senior and subordinate loans of 1% of the principal amount of each. The interest rate on the senior financing will be at LIBOR plus an anticipated spread of 325 to 350 basis points. Until the senior
loan has been fully drawn, the Company shall pay a commitment fee of 0.50% on the unutilized portion. The interest rate on the subordinate financing will be at LIBOR plus an anticipated spread of 1000 basis points. As the subordinate financing will be fully drawn on closing there will be no commitment fees applicable on that facility. Other covenants, representations and warranties will form part of the final documentation on closing of the loan agreement.     F-23  67        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  11.
SUBSEQUENT EVENTS:  a)
On February 14, 2007, the Company executed a non-binding letter of intent offering to invest $6.5 million into Energen Development Ltd., Kingston, Jamaica (EDL) in exchange for a 70% interest in that company. EDL is currently involved in developing an ethanol dehydration plant (Phase 1) and biodiesel plant (Phase 2) on the island of Jamaica, for local and export sales markets. Effective March 13, 2007, the parties terminated the Letter of Intent.  b)
On March 9, 2007 the Company executed a term sheet with Aker Kvaerner Songer Canada Ltd. (AKSC) for the development of an engineering, procurement and construction (EPC) contract for the Barrie site. The Company is obligated to pay a non-refundable fee of $500,000 to AKSC for executing the term sheet and we will pay AKSC a further non-refundable fee of $500,000 on receipt of the fixed EPC contract price for our Barrie plant in June 2007. Providing the EPC contract price is acceptable and financing is obtained, the Company expects to execute the EPC contract(AKSC-EPC) within 60 days of receiving the fixed EPC contract price and commence construction at the Barrie site immediately thereafter.  c)
On March 27, 2007, the Company entered into a non-binding letter of intent with Quad County Corn Processors Cooperative, Galva, Iowa (Quad), wherein it agreed to acquire most of the assets and liabilities of Quad, excluding cash and long-term indebtedness, for $105 million. Quad operates an ethanol plant with current annual ethanol production of 28 million gallons. The form of the proposed acquisition; an asset acquisition, merger or some other form has not yet been determined. The proposed purchase price shall be cash in the amount of $78,750,000, plus the issuance by of a 5.5% Convertible subordinated debenture (the Debenture), in the principal amount of $26,250,000. The Debenture shall mature two (2) years from the Closing Date, unless converted by Quad, in whole or in part. Quads right to convert shall commence six (6) months from the Closing Date and
terminate upon payment in full of the Debenture. The Debenture may be converted into shares of the Companys Common Stock at a conversion price (subject to adjustment for stock splits or other recapitalization after the date hereof), equal to the greater of $1.00 per share or a Formula Price per share (as defined in the letter of intent). Interest shall be due and payable semi-annually. At Quads option, it may elect to increase the amount of the Debenture to $42,000,000 (40% of the purchase price), with the cash payment due at the Closing Date reduced by like amount, provided that Quad shall make election prior to May 15, 2007. The Company will have the right to redeem the Debenture, upon 30 days prior written notice to quad, on or after March 31, 2008. The Company has agreed to register the common stock issuable under the Debenture with the Securities and Exchange Commission on or before the 180th day following the Closing Date. This proposed transaction is subject to due
diligence, which is expected to take 60 days from the date of the Letter of Intent. The Company has been granted exclusivity on this project until completion of its due diligence and final closing of a definitive agreement between the parties.  F-24  68        NORTHERN ETHANOL, INC. (A DEVELOPMENT STAGE COMPANY) (Formerly BEACONSFIELD I, INC.)  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS FOR THE YEARS ENDED DECEMBER 31, 2006 AND 2005 AND FROM NOVEMBER 29, 2004, DATE OF INCEPTION, TO DECEMBER 31, 2006  11.
SUBSEQUENT EVENTS (continued):  d)
On March 30, 2007, the Company entered into a Line of Credit Agreement with Union Capital Trust, Nassau, Bahamas (Union) wherein Union has agreed to provide a $6 million unsecured line of credit. Interest accrues at the rate of twelve percent (12% per annum) and is payable monthly. Principal and unpaid interest is due on or before March 30, 2008.                    F-25   69       ITEM 8.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE  On July 19, 2006, the firm of Raich Ende Malter & Co. LLP (REM), our independent accountant during the period from November 29, 2004 (inception) through July 19, 2006, was dismissed. Our Board of Directors authorized this action. REM had audited our financial statements for the fiscal year ended December 31, 2005, and for the period from November 29, 2004 (inception) to December 31, 2004, and reviewed our financial statements for the period ended March 31, 2006.  In connection with the audits of our financial statements from November 29, 2004 (inception) to December 31, 2004 and for the year ended December 31, 2005 and during the interim period through July 19, 2006, there were no disagreements with REM on any matter of accounting principles or practices, financial statement disclosure, or auditing scope of procedures, which disagreements, if not resolved to the satisfaction of REM, would have caused them to make reference in connection with its reports to the subject matter of the disagreements.  The audit report of REM on our financial statements from November 29, 2004 (inception) to December 31, 2004 and as of and for the year ended December 31, 2005, did not contain an adverse opinion or disclaimer of opinion, nor was it qualified or modified as to uncertainty, audit scope, or accounting principles.  Effective July 19, 2006, we retained the firm of KPMG LLC as our auditors. There were no consultations between us and KPMG prior to their appointment.  ITEM 8A.
CONTROLS AND PROCEDURES  EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES  We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed pursuant to the Securities Exchange Act of 1934, as amended (the Exchange Act), is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commissions rules, regulations and related forms, and that such information is accumulated and communicated to the our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.  In the course of evaluating our internal controls over financial reporting as at December 31, 2006, management has identified a weakness in the area of segregation of duties which could result in a material misstatement in our financial statements. Given our limited staff level, certain duties within the accounting and finance department cannot be properly segregated. However, none of the segregation of duties deficiencies resulted in a misstatement to the financial statements as we rely on certain compensating controls, including substantive periodic review of the financial statements by the Chief Executive Officer and Audit Committee. This weakness is considered to be a common area of deficiencies for many smaller listed companies.  On December 7, 2006, and as amended on December 26, 2006, we filed reports on Forms 8-K and 8-KA1 to advise that our Form 10-QSB filed on November 21, 2006, consisting of the unaudited interim consolidated balance sheets at September 30, 2006 and December 31, 2005, and the unaudited interim consolidated statements of operations, stockholders equity and cash flows for the three-months and nine-months period ended September 30, 2006 and 2005 and for the period November 29, 2004  70      (inception) to September 30, 2006 and the related Managements Discussion and Analysis, had been withdrawn and should no longer be relied upon. We were formally notified via a letter dated November 30, 2006 that KPMG LLP, our independent registered public accountants, did not complete their review of such interim financial statements despite the fact that our management believed that such review had been completed. Further, management wished to consider the possible impact of the SECs comment letter dated November 14, 2006 relating to our registration statement on Form SB-2, filed on October 12, 2006, regarding various matters pertaining to our aforesaid report on Form 10-QSB. Our Audit Committee of the Board of Directors has approved such action and has discussed the matters disclosed in this filing with our independent registered public accountants. We have discussed the circumstances of the misunderstanding
with our independent registered public accountants and have implemented procedures to ensure that we will not make such future filings without written sign-off from our independent registered public accountants.  CHANGES IN INTERNAL CONTROLS  There have been no changes in our internal controls or in other factors that could significantly affect these controls and procedures during the year ended December 31, 2006.  ITEM 8B.
OTHER INFORMATION  None.   71       PART III  ITEM 9.
DIRECTORS AND EXECUTIVE OFFICERS  Information concerning our directors and officers is incorporated by reference to our Definitive Proxy Statement on Schedule 14A to be filed with the Securities and Exchange commission within 120 days after the end of our fiscal year.  ITEM 10.
EXECUTIVE COMPENSATION  Information concerning executive and director compensation is incorporated by reference to our Definitive Proxy Statement on Schedule 14A to be filed with the Securities and Exchange commission within 120 days after the end of our fiscal year.  ITEM 11.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS ANDMANAGEMENT AND RELATED STOCKHOLDER MATTERS  Information concerning security ownership of each person known by us to own beneficially more than 5% of the outstanding shares of our Common Stock, of each of our directors and all officers and directors as a group and of our equity compensation plans is incorporated by reference to our Definitive Proxy Statement on Schedule 14A to be filed with the Securities and Exchange commission within 120 days after the end of our fiscal year.  ITEM 12.
CERTAIN REALTIONSHIPS AND RELATED TRANSACTIONS  Information concerning certain relationships and related transactions is incorporated by reference to our Definitive Proxy Statement on Schedule 14A to be filed with the Securities and Exchange commission within 120 days after the end of our fiscal year.  ITEM 13.
EXHIBITS  Exhibit No.
Description3.1
Certificate of Incorporation*3.2
Bylaws*3.3
Certificate of Amendment to Certificate of Incorporation dated August 2, 2006****10.1
Lease dated April 20, 2006 for proposed Barrie facility**10.2
Lease dated April 11, 2006 for Toronto offices**10.3
Employment Agreement of Gordon Laschinger dated April 12, 2006**10.5
Employment Agreement of Steven Reader dated July 17, 2006***10.6
Project Development Agreement with Delta-T Corporation, Williamsburg, Virginia, dated July 27, 2006****   72        10.7
Project Development Agreement with Delta-T Corporation, Williamsburg, Virginia, dated September 7, 2006****10.8
Agreement with Parish & Heimbecker, Limited dated August 18, 2006****10.9
Employment Agreement of Richard Smith dated December 13, 2006*****10.10
Line of Credit Agreement with Union Capital Trust10.11
Letter of Intent with Quad County Corn Processors Cooperative dated March 27, 200721.1
List of Subsidiaries****31.1
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1
Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.32.2
Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002  *Filed as an exhibit to the Companys registration statement on Form 10-SB/A, as filed with the Securities and Exchange Commission on November 10, 2005, and incorporated herein by this reference.  **Filed as an exhibit to the Companys Form 10-QSB for the period ended March 31, 2006, as filed with the Securities and Exchange Commission on May 24, 2006, and incorporated herein by this reference.  ***Filed as an exhibit to the Companys Form 8-K, as filed with the Securities and Exchange Commission on August 7, 2006, and incorporated herein by this reference.  ****Filed as an exhibit to the Companys Registration Statement on Form SB-2, as filed with the Securities and Exchange Commission on October 12, 2006.  *****Filed as an exhibit to the Companys Registration Statement on Form SB-2/A1, as filed with the Securities and Exchange Commission on January 19, 2007.  ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES  Information concerning principal accountant fees and services is incorporated by reference to our Definitive Proxy Statement on Schedule 14A to be filed with the Securities and Exchange Commission within 120 days after the end of our fiscal year.   73        SIGNATURES  In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on April 27, 2007.  NORTHERN ETHANOL, INC.

(Registrant)





By:s/Gordon Laschinger

Gordon Laschinger

Chief Executive Officer & President  In accordance with the Exchange Act, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on April 27, 2007.  s/Gordon Laschinger

Gordon Laschinger, Directors/Andrew I. Telsey

Andrew I. Telseys/Andrew M. Gertler

Andrew M. Gertler, Directors/Robert Richards

Robert Richards, Directors/Paul T. Durst

Paul T. Durst, DirectorFrank F. Klees, Director    74