Northern Ethanol 10QSB/A Quarterly report (small business) (amended)

U.S. SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-QSB/A1

Quarterly Report Under

the Securities Exchange Act of 1934

For Quarter Ended: June 30, 2007

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 August 15, 2008, 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) ____ Yes _X_ No

EXPLANATORY NOTE

This Amendment No. 1 to our Quarterly Report on Form 10-QSB for the three months ended June 30, 2007 initially filed with the Securities and Exchange Commission (“SEC”) on August 29, 2007 (the “Originally Filed 10-Q”) is being filed to reflect restatements of the following unaudited interim financial statements: consolidated statements of operations and cash flows for the three and six month periods ended June 30, 2007 and consolidated balance sheets as at June 30, 2007 and December 31, 2006. On April 9, 2008, we announced that we would restate our consolidated financial statements for the year ended December 31, 2006; and for the quarters ended March 31, 2007, June 30, 2007 and September 30, 2007 due to errors in our accounting for the foreign currency translation of our Canadian subsidiaries in accordance with SFAS No. 52. For a description of the restatements, see “Restatements” in note 3 to the accompanying unaudited consolidated interim financial statements and “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Recent Developments — Restatements” in this Amendment No. 1. This Amendment No. 1 amends and restates Items 1, 2, and 3 of Part I and Item 6 of Part II of the Originally Filed 10-Q and, except for such items and Exhibits 31.1, 31.2, and 32, no other information in the Originally Filed 10-Q is amended hereby. The explanatory caption at the beginning of each item of the Amendment No. 1 sets forth the nature of the revisions to that item.

On April 16, 2008, we filed our Annual Report on Form 10-KSB for the year ended December 31, 2007, which includes the following audited restated financial statements: consolidated statements of operations, shareholders’ equity and cash flows for the year ended December 31, 2006, and a consolidated balance sheet as at December 31, 2006.

For a discussion of events and developments subsequent to June 30, 2007, see:

• our Amendment No. 1 to our Quarterly Report on Form 10-QSB for the quarterly period ended September 30, 2007 filed with the SEC on August 15, 2008 which contained unaudited restated consolidated statements of operations for the three and nine month periods ended September 30, 2007, unaudited restated consolidated statement of cash flows for the three and nine month periods ended September 30, 2007 and unaudited restated consolidated balance sheet as at September 30, 2007 and December 31, 2006;

and

• all our other filings subsequent to August 29, 2007.

PART I.

ITEM 1. FINANCIAL STATEMENTS

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

The (unaudited) restated consolidated financial statements and supplementary data, including the notes to the restated consolidated financial statements, set forth in this Item 1 have been revised to reflect the restatements and, except for these revisions, do not reflect events and developments subsequent to June 30, 2007.

INDEX TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

	Page

Consolidated Balance Sheets	F-1
Consolidated Statements of Operations	F-2
Consolidated Statement of Changes in Stockholders’ Equity and Comprehensive Income	F-3
Consolidated Statements of Cash Flows	F-4
Notes to Consolidated Interim Financial Statements	F-5 to F-26

Northern Ethanol, Inc.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

Consolidated Balance Sheets

As at:	June 30, 2007			December 31, 2006
	(Unaudited)
ASSETS		(as restated –note 3)			(as restated –note 3)
CURRENT ASSETS:
Cash and cash equivalents	$	2,758		$	567,249
Accounts receivable (note 4)		174,162			112,636
Deposits (note 5)		2,056			202,308
Prepaid expenses (note 6)		504,361			480,886
Total current assets		683,337			1,363,079

Property under development and equipment (note 7)		1,324,433			425,886
Assets under capital lease (notes 8 and 11)		19,622,359			16,526,080
Deferred financing costs (note 9)		320,473			200,000
Other assets		6,024			5,506
	$	21,956,626		$	18,520,551
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Bank indebtedness (note 10)	$	476,309		$	5,534
Accounts payable		2,649,291			117,371
Accrued liabilities		152,298			125,000
Due to related party (notes 11)		98,000			—
Current portion of obligation under capital lease (note 11 and 14)		28,005			18,993
Total current liabilities		3,403,903			266,898

Obligation under capital lease (note 11 and 14)		17,515,882			16,031,367
		20,919,785			16,298,265
STOCKHOLDERS’ EQUITY:
Preferred stock, $.0001 par value; 100,000,000 shares authorized; none issued and outstanding (note 13)		—			—
Common stock, $.0001 par value; 250,000,000 shares authorized;
(104,096,500 shares issued and outstanding as of June 30, 2007 and December 31, 2006, respectively (note 13))		10,410			10,410
Additional paid-in capital		6,258,350			5,554,459
Deficit accumulated during the development stage		(5,312,703	)		(3,279,416	)
Accumulated other comprehensive income		80,784			(63,167	)
		1,036,841			2,222,286
Going concern (note 2 a))
Commitments (note 16)
	$	21,956,626		$	18,520,551

See accompanying notes to unaudited consolidated interim financial statements

F-1

Northern Ethanol, Inc.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

Consolidated Statements of Operations

(Unaudited)

		Three months ended June 30					Six months ended June 30						Nov 29, 2004 (Inception) to June 30
		2007			2006			2007			2006			2007
		(as restated –note 3)						(as restated –note 3)						(as restated –note 3)
REVENUES	$	—		$	—		$	—		$	—		$	—

OPERATING EXPENSES
Salaries and benefits (note 12)		659,885			755,352			1,320,182			755,352			3,473,524
General and administrative		353,243			152,410			624,607			161,858			1,626,431
Occupancy costs		44,965			13,905			85,471			13,905			185,115
Foreign exchange loss (gain)		(32,289	)					(28,872	)					(26,336	)
Depreciation		10,131			5,287			19,172			5,287			41,242
Interest		12,727			—			12,727			—			12,727
		1,048,662			926,954			2,033,287			936,402			5,312,703

NET LOSS	$	(1,048,662	)	$	(926,954	)	$	(2,033,287	)	$	(936,402	)	$	(5,312,703	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.01	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING		104,096,500			100,700,000			104,096,500			101,097,790

See accompanying notes to unaudited consolidated interim financial statements

F-2

Northern Ethanol, Inc.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

Consolidated Statement of Stockholders’ Equity and Comprehensive Income

(Unaudited)

Six Months ended June 30, 2007 and June 30, 2006

	Common Stock
	Shares		Amount			Additional Paid-In Capital		Accumulated Deficit				Accumulated Other Comprehensive Income		Total

Balances, December 31, 2005	101,500,000		$	10,150		$	39,865	$	(31,473	)	$	—			$	18,542
Comprehensive Income:
Net loss for the six months ended June 30, 2006	—			—			—		(936,402	)		—				(936,402	)
Cumulative translation adjustment	—			—			—		—			(4,472	)			(4,472	)
Total Comprehensive Income																(940,874	)
Shares cancelled	(800,000	)		(80	)		80		—			—				—
Stock-based compensation	—			—			657,379		—			—				657,379
Stock issued for cash, net of issuance costs	—			—			1,500,000		—			—				1,500,000
Balances, June 30, 2006	100,700,000		$	10,070		$	2,197,324	$	(967,875	)	$	(4,472	)		$	1,235,047

Balances, December 31, 2006 (as restated – note 3)	104,096,500		$	10,410		$	5,554,459	$	(3,279,416	)	$	(63,167	)		$	2,222,286
Comprehensive Income:
Net loss for the six months ended June 30, 2007 (as restated – note 3)	—			—			—		(2,033,287	)		—				(2,033,287	)
Cumulative translation adjustment (as restated – note 3)	—			—			—		—			143,951				143,951
Total Comprehensive Income																(1,889,336	)
Stock-based compensation	—			—			703,891		—			—				703,891
Balances, June 30, 2007	104,096,500		$	10,410		$	6,258,350	$	(5,312,703	)	$	80,784			$	1,036,841

See accompanying notes to unaudited consolidated interim financial statements

F-3

Northern Ethanol, Inc.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

Consolidated Statements of Cash Flows

(Unaudited)

	For the three months ended June 30,							For the six months ended June 30,						November 29, 2004 (Inception) to June 30,
		2007			2006				2007			2006				2007
CASH FLOWS FROM OPERATING ACTIVITIES:		(as restated – note 3)							(as restated – note 3)								(as restated – note 3)
Net loss	$	(1,048,662	)	$	(926,954	)	$		(2,033,287	)	$	(936,402	)		$		(5,312,703	)
Items not involving cash:
Depreciation		10,131			5,287				19,172			5,287					41,242
Stock-based compensation		318,428			657,379				703,891			657,379					2,372,245
Unrealized foreign exchange loss		25,834			-				25,834			-					25,834
Changes in non-cash working capital balances:
Accounts receivable		(67,051	)		(33,659	)			(47,905	)		(33,659	)				(160,541	)
Deposits		5,845			(750,000	)			205,823			(750,000	)				3,515
Prepaid expenses		15,893			(266,805	)			19,890			(263,680	)				(460,996	)
Accounts payable		192,530			72,334				339,713			70,334					457,083
Accrued liabilities		57,543			-				24,437			3,600					149,437
Net cash (used in) provided by operating activities		(489,509	)		(1,242,418	)			(742,432	)		(1,247,141	)				(2,884,884	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		(43,576	)		-				(43,576	)		-					(243,576	)
Bank indebtedness		473,839			-				470,190			-					475,724
Due to related party		92,002			-				92,002			-					92,002
Proceeds from issuance of common stock		-			1,500,000				-			1,500,000					3,896,515
Principal payment of capital lease obligation		-			-				(2,090	)		-					(5,825)
Net cash (used in) provided by financing activities		522,265			1,500,000				516,526			1,500,000					4,214,840

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property under development and equipment		(35,930	)		(160,298	)			(98,312	)		(160,298	)				(558,946	)
Assets under capital lease		-			-				(237,530	)		-					(709,672	)
Other assets		-			-				-			-					(5,506	)
Net cash (used in) provided by investing activities		(35,930	)		(160,298	)			(335,842	)		(160,298	)				(1,274,124	)

Effect of exchange rate changes on cash		(8,182	)		(4,472	)			(2,743	)		(4,472	)				(53,074	)

NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		(11,356	)		92,812				(564,491	)		88,089					2,758

CASH AND CASH EQUIVALENTS:
Beginning of period		14,114			8,667				567,249			13,390					—
End of period	$	2,758		$	101,479		$		2,758		$	101,479			$		2,758

SUPPLEMENTAL CASH FLOW INFORMATION
Assets acquired under capital lease	$	737,671		$	16,761,565		$		1,213,017		$	16,761,565			$		17,974,582
Cash paid for income taxes		-			-				-			-					353

See accompanying notes to unaudited consolidated interim financial statements

F-4

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

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:

Basis of presentation

Interim Financial Statements:

The accompanying interim financial statements of the Company as of June 30, 2007, for the three and six month periods ended June 30, 2007 and 2006 and for the period from November 29, 2004 (Inception) to June 30, 2007 have been prepared in accordance with United States accounting principles generally accepted for interim financial statement presentation and in accordance with the rules and regulations of the United States Securities and Exchange Commission for small business users. Accordingly, these interim financial statements do not include all of the information and footnotes required by accounting principles generally accepted in the United States of America for annual financial statement presentation. In the opinion of management, all adjustments necessary for a fair statement of the results of operations and financial position for the interim period presented have been included. All such adjustments are of a normal recurring nature. The results of operations for the interim periods are not necessarily indicative of the results to be expected for a full year. This financial information should be read in conjunction with the restated December 31, 2006 financial statements and notes included in the Company’s Form 10-KSB for the year ended December 31, 2007.

F-5

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (Continued):

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.

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.

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.

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.

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.

F-6

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (Continued):

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.

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. The application of this policy is described in notes 8 and 14.

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 the estimated future cash flows from operations and residual value of the asset, an impairment charge is recognized for the amount that the carrying amount exceeds the fair value of the particular assets.

Capitalized interest:

In accordance with SFAS No. 34, the interest costs associated with the Company’s capital lease obligation are being capitalized to assets under capital lease until the Barrie plant is substantially complete and ready for the production of ethanol.

Deferred financing costs:

Deferred financing costs are costs and all related fees incurred to obtain debt financing and will be amortized as interest expense over the term of the related financing using the effective interest rate method.

F-7

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (Continued):

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 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.

Foreign currency translation:

The functional currency of the Company is United States dollars and 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.

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. In June2006, 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 was adopted by the Company effective January 1, 2007. The adoption of FIN 48 did not have a material impact on the Company’s consolidated financial statements or results of operations.

F-8

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (Continued):

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.

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.

In February2006, 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 by the Company on or after January 1 2007. The adoption SFAS No.155 did not have a material impact on the Company’s consolidated financial statements or results of operations.

F-9

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

2.	SIGNIFICANT ACCOUNTING POLICIES (Continued):

Recent Accounting Pronouncements:

In September2006, 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 the Company’s consolidated financial statements issued for fiscal years beginning after November15, 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 or results of operations.

In September2006, 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 were effective for the Company’s year ended December31, 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.

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.

F-10

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

3.	RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS:

Subsequent to the issuance of the Company’s consolidated financial statements for the year ended December 31, 2006, the consolidated interim financial statements for the three month period ended March 31, 2007 and for the three and six month period ended June 30, 2007, the Company determined that the accounting for the foreign currency translation of its Canadian subsidiaries was not in accordance with SFAS No. 52 and required revisions. In addition the Company has reclassified bank indebtedness separate from cash and cash equivalents and has also reclassified deferred financing costs as a separate long-term asset from prepaid expenses and deposits. The effects of the restatement and reclassifications on the consolidated balance sheet as of December 31, 2006 and the consolidated statement of operations and the consolidated statement of cash flows for the year ended December 31, 2006 are as follows:

Consolidated balance sheet as at December 31, 2006		As previously reported			Restatement			As restated
ASSETS
Cash and cash equivalents	$	561,715		$	5,534		$	567,249
Deposits		402,308			(200,000	)		202,308
Property under development and equipment		438,467			(12,581	)		425,886
Assets under capital lease		17,233,707			(707,627	)		16,526,080
Deferred financing costs		—			200,000			200,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
Bank indebtedness		—			5,534			5,534
Deficit accumulated during the development stage		(3,276,873	)		(2,543	)		(3,279,416	)
Accumulated other comprehensive income		654,498			(717,665	)		(63,167	)

Consolidated statement of operations for the year ended December 31, 2006		As previously reported			Restatement			As restated

OPERATING EXPENSES
Foreign exchange loss	$	—		$	2,536		$	2,536
Depreciation		22,063			7			22,070

NET LOSS	$	(3,245,400	)	$	(2,543	)	$	(3,247,943	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.03	)	$	—		$	(0.03)

F-11

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

3.	RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS (continued):

Consolidated statement of cash flows for the year ended December 31, 2006		As previously reported			Restatement			As restated

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(3,245,400	)	$	(2,543	)	$	(3,247,943	)
Items not involving cash:
Depreciation		22,063			7			22,070
Changes in non-cash working capital balances:
Deposits		(402,308	)		200,000			(202,308	)
Other		(52,972	)		52,972			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		—			(200,000	)		(200,000	)
Bank indebtedness		—			5,534			5,534
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property under development and equipment		(460,530	)		(105	)		(460,635	)
Effect of exchange rate changes on cash		—			(50,331	)		(50,331	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		548,325			5,534			553,859
CASH AND CASH EQUIVALENTS:
End of period	$	561,715		$	5,534		$	567,249

There are no current and deferred income tax implications to this restatement.

The effects of the restatement and reclassifications on the consolidated balance sheet as of June 30, 2007 and the consolidated statement of operations and the consolidated statement of cash flows for the three and six month period ended June 30, 2007 are as follows:

Consolidated balance sheet as at June 30, 2007		As previously reported			Restatement			As restated
ASSETS
Deposits	$	202,056		$	(200,000	)	$	2,056
Prepaid expenses		627,465			(123,104	)		504,361
Property under development and equipment		1,246,869			77,564			1,324,433
Assets under capital lease		18,719,139			903,220			19,622,359
Deferred financing costs		—			320,473			320,473
Other assets		5,506			518			6,024
LIABILITIES AND STOCKHOLDERS’ EQUITY
Deficit accumulated during the development stage		(5,340,348	)		27,645			(5,312,703	)
Accumulated other comprehensive income		(870,242	)		951,026			80,784

F-12

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

3.	RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS (continued):

Consolidated statement of operations for the three months ended June 30, 2007		As previously reported			Restatement			As restated

OPERATING EXPENSES
General and administrative	$	353,101		$	142		$	353,243
Foreign exchange loss (gain)		—			(32,289	)		(32,289	)
Depreciation		9,861			270			10,131

NET LOSS	$	(1,080,539	)		31,877			(1,048,662	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.01	)	$	—		$	(0.01)

Consolidated statement of operations for the six months ended June 30, 2007		As previously reported			Restatement			As restated

OPERATING EXPENSES
General and administrative	$	625,895		$	(1,288	)	$	624,607
Foreign exchange loss (gain)		—			(28,872	)		(28,872	)
Depreciation		19,200			(28	)		19,172

NET LOSS	$	(2,063,475	)	$	30,188		$	(2,033,287	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.02	)	$	—		$	(0.02	)

F-13

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

3.	RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS (continued):

Consolidated statement of cash flows for the three months ended June 30, 2007		As previously reported			Restatement			As restated

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,080,539	)	$	31,877		$	(1,048,662	)
Items not involving cash:
Depreciation		9,861			270			10,131
Unrealized foreign exchange loss		—			25,834			25,834
Changes in non-cash working capital balances:
Accounts receivable		(80,672	)		13,621			(67,051	)
Deposits		274			5,571			5,845
Prepaid expenses		(69,514	)		85,407			15,893
Accounts payable		506,930			(314,400	)		192,530
Accrued liabilities		60,404			(2,861	)		57,543
Other		(35,171	)		35,171			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		—			(43,576	)		(43,576	)
Bank indebtedness		474,424			(585	)		473,839
Due to related party		98,000			(5,998	)		92,002
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property under development and equipment		(213,781	)		177,851			(35,930	)
Effect of exchange rate changes on cash		—			(8,182	)		(8,182	)
SUPPLEMENTAL CASH FLOW INFORMATION
Assets acquired under capital lease		772,556			(34,885	)		737,671

F-14

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

3.	RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS (continued):

Consolidated statement of cash flows for the six months ended June 30, 2007		As previously reported			Restatement			As restated

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,063,475	)	$	30,188		$	(2,033,287	)
Items not involving cash:
Depreciation		19,200			(28	)		19,172
Unrealized foreign exchange loss		—			25,834			25,834
Changes in non-cash working capital balances:
Accounts receivable		(61,526	)		13,621			(47,905	)
Deposits		200,252			5,571			205,823
Prepaid expenses		(146,579	)		166,469			19,890
Accounts payable		1,059,470			(719,757	)		339,713
Accrued liabilities		27,298			(2,861	)		24,437
Other		(42,105	)		42,105			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		—			(43,576	)		(43,576	)
Bank indebtedness		470,775			(585	)		470,190
Due to related party		98,000			(5,998	)		92,002
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property under development and equipment		(827,602	)		729,290			(98,312	)
Assets under capital lease		—			(237,530	)		(237,530	)
Effect of exchange rate changes on cash		—			(2,743	)		(2,743	)
SUPPLEMENTAL CASH FLOW INFORMATION
Assets acquired under capital lease		1,485,432			(272,415	)		1,213,017

There are no current and deferred income tax implications to this restatement.

4.	ACCOUNTS RECEIVABLE:

	June 30, 2007		December 31, 2006

Canadian federal government Goods and Services tax receivable	$	174,162	$	110,062
Overpayment of legal fee		—		2,574
	$	174,162	$	112,636

F-15

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

5.	DEPOSITS:

	June 30, 2007		December 31, 2006
		(restated – note 3)		(restated – note 3)
Refundable deposit on storage tanks paid to related party (note 11)	$	—	$	200,000
Refundable deposit on head office lease utilities		1,117		1,021
Refundable deposit on non-binding letter of intent for Sarnia lease		939		858
Other non-refundable deposit		—		429
	$	2,056	$	202,308

6.	PREPAID EXPENSES:

	June 30, 2007		December 31, 2006
		(restated – note 3)		(restated – note 3)
Prepaid rent for Barrie and head office leases (note 14)	$	277,242	$	253,454
Prepaid development costs for planned Sarnia location		226,103		202,479
Prepaid insurance		828		22,025
Prepaid other		188		2,928
	$	504,361	$	480,886

7.	PROPERTY UNDER DEVELOPMENT AND EQUIPMENT:

June 30, 2007 (restated – note 3)	Cost		Accumulated Depreciation		Net book Value

Property under development		1,096,737		—		1,096,737
Computer equipment and software		46,056		16,035		30,021
Furniture and equipment		185,468		20,224		165,244
Leasehold improvements		40,093		7,662		32,431
	$	1,368,354	$	43,921	$	1,324,433

December 31, 2006 (restated – note 3)	Cost		Accumulated Depreciation		Net book Value

Property under development	$	213,818	$	—	$	213,818
Computer equipment and software		36,544		8,097		28,447
Furniture and equipment		163,468		10,028		153,440
Leasehold improvements		33,539		3,358		30,181
	$	447,369	$	21,483	$	425,886

F-16

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

7.	PROPERTY UNDER DEVELOPMENT AND EQUIPMENT continued):

During the six months ended June 30, 2007, the Company capitalized a $500,000 deposit for the development of an engineering, procurement and construction contract, $252,441 of engineering and site design costs, $49,330 of legal advisory costs and $10,371 of permit application costs to the cost of property under development at the Barrie location that is being developed into an ethanol production facility. The Company will not capitalize costs to property under development beyond what is recoverable from operations. Depreciation of property under development will commence once the property has been determined to be available for its intended use. The assets will be depreciated over their estimated useful life.

8.	ASSETS UNDER CAPITAL LEASE:

June30, 2007 (restated – note 3)	Cost		Accumulated Depreciation		Net book Value
Assets under capital lease	$	19,622,359	$	—	$	19,622,359

December 31, 2006 (restated – note 3)	Cost		Accumulated Depreciation		Net book Value
Assets under capital lease	$	16,526,080	$	—	$	16,526,080

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.

F-17

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

8.	ASSETS UNDER CAPITAL LEASE (continued):

During the six months ended June 30, 2007, the Company capitalized interest costs of $1,011,694, lessor’s operating cost charges of $276,347 and property tax of $197,391 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 lease beyond what is recoverable from operations. Depreciation of assets under capital lease 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.

9.	DEFERRED FINANCING COSTS:

	June 30, 2007		December 31, 2006
		(restated – note 3)		(restated – note 3)
Non-refundable retainer paid to WestLB AG (note 16 c)	$	200,000	$	200,000
Deferred financing costs for WestLB AG commitment (note 16 c)		120,473		—
	$	320,473	$	200,000

10.

BANK INDEBTEDNESS:

	June 30, 2007		December 31, 2006

Indebtedness under Line of Credit Agreement	$	469,192	$	—
Indebtedness under corporate credit card		7,117		5,534
	$	476,309	$	5,534

On March 30, 2007, the Company entered into a Line of Credit Agreement with Union Capital Trust, Nassau, Bahamas (“Union”) wherein Union 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. As at June 30, 2007, a principal amount of $469,192 was outstanding under this line of credit and interest of $12,495 was accrued as an accrued liability.

11.

RELATED PARTY TRANSACTIONS:

During the six months ended June 30, 2006, 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.

F-18

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

11.

RELATED PARTY TRANSACTIONS (continued):

During the six months ended June 30, 2006, the Company utilized the office space and equipment of a stockholder at no cost. In April 2006, the Company entered into a lease for office space, as further discussed in note 14. Also in 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 14. 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 9.6% interest.

In September 2006, the Company deposited $200,000 in trust with Aurora Beverage Corporation (“Aurora”), 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.

The trustee of the Union Capital Trust Line of Credit (note 10) is Ronald Wyles. Ronald Wyles owns 10,000,000 shares of the Company’s outstanding Common Stock or 9.6% interest.

In May 2007, the Company received loan advances of $24,000 from Aurora and $20,000 from Richard Brezzi that were repaid. Richard Brezzi owns 10,000,000 shares of the Company’s outstanding Common Stock or 9.6% interest. In June 2007, the Company, received loan advances from Aurora totaling $98,000. In July 2007, the Company entered into a Line of Credit Agreement with Aurora as further discussed in note 17 a).

12.

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.

F-19

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

12.

STOCK OPTIONS (Continued):

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.

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.

On June 6, 2007, 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 the non-salaried Directors of the Company. The options will vest in equal amounts on the date of grant and annually over the next two years from the date of grant. The options expire five years following the date of grant.

F-20

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

12.

STOCK OPTIONS (Continued):

A summary of the status of Company’s stock option plan as of June 30, 2007 and of changes in options outstanding under the Company’s plan during the six month period ended June 30, 2007 is as follows:

	Number of Shares		Weighted Average Exercise Price
Outstanding at December 31, 2006	4,139,000	$	1.00
Granted	300,000		1.00
Exercised	—		—
Forfeited	—		—
Outstanding at June 30, 2007	4,439,000	$	1.00

Options exercisable at June 30, 2007	2,414,710	$	1.00
Non-vested options at June 30, 2007	2,024,290	$	1.00

Stock options outstanding as of June30, 2007, were as follows:

		Options Outstanding				Options Exercisable
Exercise Price		Number Outstanding	Weighted Average Remaining Contractual Life	Weighted-Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$	1.00	4,439,000	4.06	$	1.00	2,414,710	$	1.00

The fair value of each option granted during the six months ended June 30, 2007 and during the year ended December 31, 2006, 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 price of the Company’s common shares	86.6	%
Weighted average expected life in years	5.0
Weighted average forfeiture rate	2.8	%
Expected dividends	None

The fair value of the options granted as determined above was $2,952,611, of which $703,891 was expensed during the six month period ended June 30, 2007 (June 30, 2006 – $657,379). The weighted average fair value per share for the options granted above was $0.66.

F-21

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

13.

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 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.

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 common 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.

F-22

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

14.

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.

The terms of the leases require the following minimum payments:

Fiscal Year		Barrie Lease			Head Office Lease			Total
Balance of 2007	$		1,065,329	$		84,475	$		1,149,804
2008			2,130,659			168,951			2,299,610
2009			2,130,659			168,951			2,299,610
2010			2,130,659			168,951			2,299,610
2011			2,130,659			70,396			2,201,055
Thereafter			47,121,666			—			47,121,666
Total minimum lease payments	$		56,709,631	$		661,724	$		57,371,355
Less amount representing interest of 12%			39,165,744
			17,543,887
Less current portion			28,005
	$		17,515,882

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 carrying value of the assets under 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$60,418,441 ($56,709,631) over the remaining term of the lease, of which C$41,727,183 ($39,165,744) is interest and C$18,691,258 ($17,543,887) is the repayment of the capital lease amount. The capital lease principal will be paid down by C$29,837 ($28,005) as a result of monthly lease payments that will be made over the next year.

F-23

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

14.

LEASE AGREEMENTS (Continued):

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 later in 2007.

15.

INCOME TAXES:

The Company has incurred losses resulting from start-up costs. A valuation allowance has been recorded to fully offset any deferred tax asset because the future realization of the related income tax benefits is uncertain.

16.

COMMITMENTS:

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 it fails to do so, to give Delta a first right of refusal for 60 days to assume any agreements made with other ethanol plant technology vendors.

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-24

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

16.

COMMITMENTS (continued):

Effective December 13, 2006, the Company executed an engagement letter and indicative term sheets with WestLB AG (“WestLB”) whereby WestLB has conditionally agreed to provide arrangement, placement and underwriting services on senior debt and subordinate debt financing for up to 75% of the construction costs (to a maximum of approximately $365 million) of the Company’s Barrie and Sarnia facilities on a “best efforts” basis. The term “best efforts” means that WestLB believes that they can syndicate the debt financing the Company requires 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 of $200,000 to WestLB on execution of the engagement letter and indicative term sheets. This payment has been recorded as deferred financing costs 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 $10,000,000. 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 5% 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. The Company will also pay WestLB’s costs and expenses in connection with the financing. Other covenants, representations and warranties will form part of the final documentation on closing of the loan agreement.

F-25

NORTHERN ETHANOL, INC.

(A DEVELOPMENT STAGE COMPANY)

(Formerly BEACONSFIELD I, INC.)

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

16.

COMMITMENTS (continued):

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 using Delta technology for the Barrie site. The Company has not paid a non-refundable fee of $500,000 to AKSC for executing the term sheet and is reviewing its options on ethanol plant technology providers and engineering procurement and construction contractors. In the event the Company accepts another ethanol plant technology provider’s offer, Delta has a first right of refusal for 60 days to assume any agreements made with other ethanol plant technology vendors. If the Company continues with Delta, it expects to pay the non-refundable fee of $500,000 to AKSC for executing the term sheet and to pay AKSC a further non-refundable fee of $500,000 on receipt of the fixed EPC contract price for the Barrie plant. If Delta decides not to assume the agreement negotiated with another ethanol plant technology provider, the Company expects to engage an EPC contractor acceptable to the other ethanol plant technology provider and establish an EPC contract price. 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.

17. SUBSEQUENT EVENTS:

On July 9, 2007, the Company entered into a Line of Credit Agreement with Aurora Beverage Corporation (“Aurora’), a related party (note 11), wherein Aurora has agreed to provide a $1 million unsecured line of credit. Interest accrues at the rate of eight percent (8% per annum) and is payable monthly. Principal and unpaid interest is due on or before July 8, 2008.

On July 30, 2007, the Company entered into an Agreement of Purchase and Sale with LANXESS Inc. (“LANXESS”) wherein LANXESS agreed to sell approximately 30 acres of land located in Sarnia, Ontario to the Company for C$450,000 ($421,822) by June 30, 2008, at the latest. The Agreement is conditional upon the Company’s satisfaction with its physical inspection of the land, zoning and permitting, the Company entering into an Engineering, Procurement and Construction contract for the construction of an ethanol plant, the Company obtaining financing for the land purchase and plant construction and the Company and LANXESS entering into an agreement with TransAlta Energy Corporation (“TransAlta”) in respect of relief for LANXESS’s obligations under its steam supply contract with TransAlta. If the Company’s closing conditions are waived, in addition to the payment of the land purchase price of C$450,000 ($421,822), it will pay LANXESS an amount of C$100,000 ($93,738) immediately, C$325,000 ($304,649) when the construction of the ethanol plant begins and C$325,000 ($304,649) when the ethanol plant commences operation for a total of C$750,000 ($703,036) as compensation for LANXESS’s costs to re-engineer existing infrastructure presently located on the land. If after closing of the purchase, the Company has not commenced construction of the ethanol plant under an Engineering, Procurement and Construction contract by December 31, 2008, LANXESS has the option to reacquire the land for C$450,000 ($421,822). The Company paid a refundable interest bearing deposit amount of C$10,000 ($9,374) on execution of the Agreement.

F-26

ITEM 2.

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” company for 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 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.

RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS

Subsequent to the issuance of our consolidated financial statements for the year ended December 31, 2006, the consolidated interim financial statements for the three month period ended March 31, 2007 and for the three and six month period ended June 30, 2007, we determined that the accounting for the foreign currency translation of our Canadian subsidiaries was not in accordance with SFAS No. 52 and required revisions. In addition we have reclassified bank indebtedness separate from cash and cash equivalents and have also reclassified deferred financing costs as a separate long-term asset from prepaid expenses and deposits. The effects of the restatement and reclassifications on the consolidated balance sheet as of December 31, 2006 and the consolidated statement of operations and the consolidated statement of cash flows for the year ended December 31, 2006 are as follows:

Consolidated balance sheet as at December 31, 2006		As previously reported			Restatement			As restated
ASSETS
Cash and cash equivalents	$	561,715		$	5,534		$	567,249
Deposits		402,308			(200,000	)		202,308
Property under development and equipment		438,467			(12,581	)		425,886
Assets under capital lease		17,233,707			(707,627	)		16,526,080
Deferred financing costs		—			200,000			200,000
LIABILITIES AND STOCKHOLDERS’ EQUITY
Bank indebtedness		—			5,534			5,534
Deficit accumulated during the development stage		(3,276,873	)		(2,543	)		(3,279,416	)
Accumulated other comprehensive income		654,498			(717,665	)		(63,167	)

Consolidated statement of operations for the year ended December 31, 2006		As previously reported			Restatement			As restated

OPERATING EXPENSES
Foreign exchange loss	$	—		$	2,536		$	2,536
Depreciation		22,063			7			22,070

NET LOSS	$	(3,245,400	)	$	(2,543	)	$	(3,247,943	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.03	)	$	—		$	(0.03)

Consolidated statement of cash flows for the year ended December 31, 2006		As previously reported			Restatement			As restated

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(3,245,400	)	$	(2,543	)	$	(3,247,943	)
Items not involving cash:
Depreciation		22,063			7			22,070
Changes in non-cash working capital balances:
Deposits		(402,308	)		200,000			(202,308	)
Other		(52,972	)		52,972			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		—			(200,000	)		(200,000	)
Bank indebtedness		—			5,534			5,534
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of property under development and equipment		(460,530	)		(105	)		(460,635	)
Effect of exchange rate changes on cash		—			(50,331	)		(50,331	)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS		548,325			5,534			553,859
CASH AND CASH EQUIVALENTS:
End of period	$	561,715		$	5,534		$	567,249

There are no current and deferred income tax implications to this restatement.

Consolidated balance sheet as at June 30, 2007		As previously reported			Restatement			As restated
ASSETS
Deposits	$	202,056		$	(200,000	)	$	2,056
Prepaid expenses		627,465			(123,104	)		504,361
Property under development and equipment		1,246,869			77,564			1,324,433
Assets under capital lease		18,719,139			903,220			19,622,359
Deferred financing costs		—			320,473			320,473
Other assets		5,506			518			6,024
LIABILITIES AND STOCKHOLDERS’ EQUITY
Deficit accumulated during the development stage		(5,340,348	)		27,645			(5,312,703	)
Accumulated other comprehensive income		(870,242	)		951,026			80,784

Consolidated statement of operations for the three months ended June 30, 2007		As previously reported			Restatement			As restated

OPERATING EXPENSES
General and administrative	$	353,101		$	142		$	353,243
Foreign exchange loss (gain)		—			(32,289	)		(32,289	)
Depreciation		9,861			270			10,131

NET LOSS	$	(1,080,539	)		31,877			(1,048,662	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.01	)	$	—		$	(0.01)

Consolidated statement of operations for the six months ended June 30, 2007		As previously reported			Restatement			As restated

OPERATING EXPENSES
General and administrative	$	625,895		$	(1,288	)	$	624,607
Foreign exchange loss (gain)		—			(28,872	)		(28,872	)
Depreciation		19,200			(28	)		19,172

NET LOSS	$	(2,063,475	)	$	30,188		$	(2,033,287	)

BASIC AND DILUTED LOSS PER SHARE	$	(0.02	)	$	—		$	(0.02	)

Consolidated statement of cash flows for the three months ended June 30, 2007		As previously reported			Restatement			As restated

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,080,539	)	$	31,877		$	(1,048,662	)
Items not involving cash:
Depreciation		9,861			270			10,131
Unrealized foreign exchange loss		—			25,834			25,834
Changes in non-cash working capital balances:
Accounts receivable		(80,672	)		13,621			(67,051	)
Deposits		274			5,571			5,845
Prepaid expenses		(69,514	)		85,407			15,893
Accounts payable		506,930			(314,400	)		192,530
Accrued liabilities		60,404			(2,861	)		57,543
Other		(35,171	)		35,171			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		—			(43,576	)		(43,576	)
Bank indebtedness		474,424			(585	)		473,839
Due to related party		98,000			(5,998	)		92,002
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property under development and equipment		(213,781	)		177,851			(35,930	)
Effect of exchange rate changes on cash		—			(8,182	)		(8,182	)
SUPPLEMENTAL CASH FLOW INFORMATION
Assets acquired under capital lease		772,556			(34,885	)		737,671

Consolidated statement of cash flows for the six months ended June 30, 2007		As previously reported			Restatement			As restated

CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(2,063,475	)	$	30,188		$	(2,033,287	)
Items not involving cash:
Depreciation		19,200			(28	)		19,172
Unrealized foreign exchange loss		—			25,834			25,834
Changes in non-cash working capital balances:
Accounts receivable		(61,526	)		13,621			(47,905	)
Deposits		200,252			5,571			205,823
Prepaid expenses		(146,579	)		166,469			19,890
Accounts payable		1,059,470			(719,757	)		339,713
Accrued liabilities		27,298			(2,861	)		24,437
Other		(42,105	)		42,105			—
CASH FLOWS FROM FINANCING ACTIVITIES:
Deferred financing costs		—			(43,576	)		(43,576	)
Bank indebtedness		470,775			(585	)		470,190
Due to related party		98,000			(5,998	)		92,002

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property under development and equipment	(827,602	)	729,290		(98,312	)
Assets under capital lease	—		(237,530	)	(237,530	)
Effect of exchange rate changes on cash	—		(2,743	)	(2,743	)
SUPPLEMENTAL CASH FLOW INFORMATION
Assets acquired under capital lease	1,485,432		(272,415	)	1,213,017

There are no current and deferred income tax implications to this restatement.

RESULTS OF OPERATIONS

Comparison of Results of Operations for the three months ended June 30, 2007 and 2006

During the three-month periods ended June 30, 2007 and 2006, we did not generate any revenues.

During the three-month period ended June 30, 2007, we incurred costs and expenses totaling $1,048,662, including $659,885 in salaries and benefits, $353,243 in general and administrative expense, $44,965 in occupancy costs, a foreign exchange gain of $32,289, $10,131 in depreciation expense and $12,727 in interest expense.

The general and administrative expense of $353,243 included legal and accounting fees of $157,303, consulting fees of $83,874, travel related costs of $28,058 and other miscellaneous costs totaling $84,008. Occupancy costs of $44,965 are the costs of rent, utilities, insurance and maintenance for our head office location that we began leasing on April 20, 2006. The foreign exchange gain of $32,289 in 2007 occurred due to the impact of the weakening of the US$ dollar against the C$ dollar during the year on the C$ dollar expenses of our Canadian subsidiaries. Total interest costs of $12,727 arose in the three-month period ended June 30, 2007, with the drawdown of $469,192 on the Union Capital Trust line of credit during the period at an interest rate of 12% per annum and with the drawdown of $98,000 on the Aurora Beverage Corporation line of credit at an interest rate of 8% per annum.

During the three-month period ended June 30, 2006, our total expenses were $926,954, including $755,352 in salaries and benefits, $152,410 in general and administrative expense, $13,905 in occupancy costs and $5,887 in depreciation expense. Salaries and benefits declined $95,467 in the three-month period ended June 30, 2007 from the same period last year as a $338,951 decline in stock based compensation expense more than offset a $243,484 increase in wage and benefit costs associated with increased staff levels. General and administrative expenses rose $200,833 from the same period last year due to a $89,198 increase in legal and accounting costs primarily associated with our due diligence costs incurred of $79,043 on the aborted Quad County Corn Processors acquisition in the current period, a $41,815 increase in consulting costs with the growth of our business development activities, a $11,965 increase in travel and a $57,855 increase in other miscellaneous costs attributed to additional staff levels. Occupancy costs increased $31,060 in the current period from the same period last year as the first month’s rent on the head office location under the April 20, 2006 lease did not begin until June 2006. There were no foreign exchange gains or losses and no interest costs in three-month period ended June 30, 2006, as the exchange rate between the US$ and the C$ was stable and as we were not borrowing funds.

As a result, we incurred a net loss of $1,048,662 for the three-month period ended June 30, 2007 ($0.01 per share), compared to a net loss of $926,954 for three-month period ended June 30, 2006 ($.01 per share).

Comparison of Results of Operations for the six months ended June 30, 2007 and 2006

During the six-month periods ended June 30, 2007 and 2006, we did not generate any revenues.

During the six-month period ended June 30, 2007, we incurred costs and expenses totaling $2,033,287, including $1,320,182 in salaries and benefits, $624,607 in general and administrative expense, $85,471 in occupancy costs, a foreign exchange gain of $28,871, $19,172 in depreciation expense and $12,727 in interest expense.

The general and administrative expense of $624,607 included legal and accounting fees of $248,829, consulting fees of $164,701, travel related costs of $79,194 and other miscellaneous costs totaling $131,883. Occupancy costs of $85,471 are the costs of rent, utilities, insurance and maintenance for our head office location that we began leasing on April 20, 2006. During the six-month period ended June 30, 2006, our total expenses were $936,402. This significant increase in operating expenses from the same period in 2006 is a direct result of our commencement of our new business plan in April 2006, described herein.

As a result, we incurred a net loss of $2,033,287 for the six-month period ended June 30, 2007 ($0.02 per share), compared to a net loss of $936,402 for six-month period ended June 30, 2006 ($.01 per share). Because we do not expect to begin generating revenues until such time as our ethanol plants described herein under “Plan of Operation” become operational, which is not expected to occur until mid 2009, or we successfully acquire an operating ethanol plant, following is our Plan of Operation.

PLAN OF OPERATION

In April 2006 we adopted a new business plan to initially construct and operate twoethanol plants. Our goal is to produce ethanol in Ontario, Canada 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 plants that we intend to build will be dry mill plants. The reason for selecting this method of milling over a wet mill process is that a majority of ethanol plants in North America use the dry mill process and have found that this method of milling is reliable and runs well with fewer problems than the wet mill process. The ethanol technology provider process that we will select will utilize dry milling and will also provide us with performance guarantees in the engineering, procurement and construction (“EPC”) contracts for Barrie and Sarnia. 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 secured 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 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 9.6% interest.

•

Sarnia, Ontario, Canada; 108 million gallons. Effective July 30, 2007, we entered into an Agreement of Purchase and Sale (the “Lanxess Agreement”) with Lanxess, Inc., a Canadian corporation (“Lanxess”), to acquire approximately 30 acres of land located in Sarnia, Ontario, Canada where we intend to build an ethanol plant. The Lanxess Agreement replaced a July 2006 non-binding letter of intent with Lanxess for this location that provided for a 99-year lease on the property. The cost of this acquisition is C$450,000 (C$15,000 per acre), subject to adjustment upon the issuance of a surveyor’s certificate confirming the actual acreage of the property. The Lanxess Agreement is conditional, among other things, upon Lanxess obtaining the consent of its Board of Directors. This consent was received August 14, 2007 and the Lanxess Agreement is now effective. Closing of this acquisition is to take place no later than June 30, 2008.

The Lanxess Agreement is also conditional, among other things, upon our satisfaction with our physical inspection of the land, zoning and permitting, our entering into an Engineering, Procurement and Construction contract (the “EPC Contract”) for the construction of our ethanol plant, our obtaining financing for the land purchase our ethanol plant construction, execution of an acceptable Remediation and Indemnity Agreement once Lanxess completes certain remediation actions to bring the land into compliance with existing environmental laws and our reaching an agreement with Lanxess and TransAlta Energy Corporation (“TransAlta”) in respect of relief for Lanxess’s obligations under its existing steam supply contract with TransAlta requiring the purchase of a minimum of 900,000 MMBTU of steam per year. The Lanxess Agreement also requires for us to enter into a Services Agreement with Lanxess, whereby Lanxess will provide us with water intake and output facilities as reasonably required to allow for the construction, operation and maintenance of our proposed ethanol plant

The Agreement also provides for additional payments to Lanxess of C$750,000 in consideration for Lanxess’ efforts to undertake significant efforts to re-engineer existing infrastructure presently located on the property as required to allow for the construction of our ethanol plant, as well as support necessary for technical interfaces with our development of the land. The Lanxess Agreement provides for us to partially compensate Lanxess for these efforts by payment of the aggregate sum of C$750,000, with C$100,000 of this amount to be paid upon our satisfaction and waiver of the conditions discussed above. The remaining C$650,000 shall be paid in two equal installments of C$325,000. The first such installment shall be paid on or before the date which is the date the contractor under the EPC Contract begins construction of our ethanol plant and the second such installment shall be paid on or before commencement of the operation of our proposed ethanol plant. If after closing of the Lanxess Agreement we have not commenced construction of our ethanol plant under the EPC Contract by December 31, 2008, Lanxess has the option to reacquire the land for C$450,000. We paid the refundable interest bearing deposit amount of C$10,000 on execution of the Lanxess Agreement. On Closing, this deposit amount shall be credited to the purchase price.

The Agreement also provides us with an option to acquire certain additional adjacent property owned by Lanxess if it elects to sell or otherwise transfer this property in the future on terms to be agreed in the future.

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

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. See “RISK FACTORS.” We believe that this will be offset by the reduced cost of transporting ethanol because of proximity to the end use market.

Based on the target price range of $180 million to $200 million stated in the EPC term sheet we executed March 9, 2007 with Aker Kvaerner Songer Canada Ltd. (“AKSC”) for our Barrie plant, discussions with other EPC contractors and ethanol plant technology providers, preliminary engineering estimates and our indicative term sheet executed December 13, 2006 with WestLB AG, (“WestLB”), each discussed below, we estimate that the Barrie and Sarnia plants will cost $454 million combined as per the following table:

Items	Barrie		Sarnia		Total
Fixed Price EPC Contract Costs:

EPC Price Materials	$	124,000,000	$	120,000,000	$	244,000,000
EPC Price Labor		66,000,000		70,000,000		136,000,000
Total EPC Costs		190,000,000		190,000,000		380,000,000

Owner’s Costs:

Project Management		745,000		710,000		1,455,000
Infrastructure Upgrades		1,627,000		805,000		2,432,000
Permitting (Environmental and Building)		143,000		134,000		277,000
Insurance During Construction		662,000		659,000		1,321,000
Owners Engineer		219,000		202,000		421,000
Startup Materials & Labor		658,000		640,000		1,298,000
Spare Parts		570,000		552,000		1,122,000
Lenders Engineer		319,000		319,000		638,000
Other Miscellaneous Costs		368,000		368,000		736,000
Total Owners Costs		5,311,000		4,389,000		9,700,000

SubTotal Costs		195,311,000		194,389,000		389,700,000

Contingency		15,625,000		15,551,000		31,176,000
Interest During Construction		16,601,000		16,523,000		33,124,000
Total Costs	$	227,537,000	$	226,463,000	$	454,000,000

The actual costs of construction may vary from these cost estimates as we will not be able to confirm the EPC price until we negotiate and enter into a contract with an EPC contractor and the owner’s costs estimates are subject to change depending on the actual construction start date, length of construction and receipt of final supplier invoices. The final cost of construction could be 10% to 15% higher or lower than these estimates.

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 whereby WestLB has conditionally agreed to provide arrangement, placement and underwriting services on 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 WestLB 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 us. 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 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 of the engagement letter and indicative term sheets using funds from the net proceeds of $3,846,500 received from our September 2006 private placement. 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 $10,000,000. 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 5% 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 also agreed to pay WestLB’s costs and expenses in connection with the financing. As of the date of this Report, we have paid $87,378 for costs incurred by WestLB’s legal and engineering advisors from funds borrowed under a Line of Credit Agreement with Union Capital Trust. There is no termination date to the WestLB engagement letter.

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, there are no assurances that it will be on terms that we have anticipated or that are otherwise acceptable to us. See “RISK FACTORS.”

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 agreed to 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. We have not paid the $30,000 balance as of the date of this Report as we did not wish to incur the cost of applying to the Ministry of Environment of Ontario for an air permit until we had secured the Sarnia property. 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 the Delta Agreements is limited to the non-refundable fees of $170,000 paid under the Delta Agreements. The

relationship between Delta and us is deemed exclusive during the five-year term of the Delta Agreements. We have 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 other ethanol plants in the United States.

On March 9, 2007, we executed a term sheet with AKSC for the development of an EPC contract for the Barrie site. We have not paid the non-refundable fee of $500,000 to AKSC for executing the term sheet and as of the date of this Report we are reviewing our options on ethanol plant technology providers and engineering procurement and construction contractors. As we have not paid this fee, AKSC is under no obligation to provide a fixed price contract. We are in discussions with other ethanol plant technology providers and we may pursue offers from them. In the event that we accept another ethanol plant technology provider’s offer, Delta has a 60 day first right of refusal to assume any agreements made with other ethanol plant technology vendors. If we continue with Delta, we expect to pay the non-refundable fee of $500,000 to AKSC for executing the term sheet and to pay AKSC a further non-refundable fee of $500,000 on receipt of the fixed EPC contract price for our Barrie plant. If Delta decides not to assume our agreement with another ethanol plant technology provider, we will engage an EPC contractor acceptable to the other ethanol plant technology provider and establish an EPC contract price. Providing the EPC contract price is acceptable and financing is obtained, we expect to execute the EPC contract within 60 days of receiving the fixed EPC contract price and commence construction at the Barrie site immediately thereafter. We are also reviewing our options on ethanol plant technology providers and engineering procurement and construction contractors for our Sarnia location. 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 marketing 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.

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 loner 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 also had plans to develop a third ethanol facility located in Upstate New York. We were in negotiations with a 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 New York State.

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 intend to continue to pursue opportunities in the Caribbean Basin to develop ethanol dehydration plants using hydrous ethanol, if and when such opportunities become available.

On March 27, 2007, we entered into a non-binding letter of intent with Quad County Corn Processors Cooperative, Galva, Iowa (“Quad”), wherein we agreed in principle to acquire most of the assets and liabilities of Quad, including its existing ethanol plant, for the purchase price of $105 million. Effective May 11, 2007, the parties terminated the letter of intent. We do not intend to proceed with this proposed transaction.

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 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 June 30, 2007, we had $2,759, 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 $469,192 on this line of credit. The trustee of the Union Capital Trust Line of Credit is Ronald Wyles. Ronald Wyles owns 10,000,000 shares of the Company’s outstanding Common Stock or 9.6% interest.

Also on July 9, 2007, we entered into a Line of Credit Agreement with Aurora Beverage Corporation, (“Aurora”) wherein Aurora has agreed to provide us with a $1 million unsecured line of credit. Interest accrues at the rate of eight percent (8% per annum) and is payable monthly. Principal and unpaid interest is due on or before July 8, 2008. As of the date of this Report, we have drawn down an aggregate of $348,000 on this line of credit. Aurora is 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. We believe that this Union and Aurora lines of credit will provide sufficient monies to fund the expected $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 and draw on the proposed WestLB line of credit described above herein. 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 whereby WestLB has conditionally agreed to provide arrangement, placement and underwriting services on 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 WestLB 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 us. Among other things, the provision of the 75% financing in accordance with engagement letter and the indicative term sheets is conditional on our obtaining subordinate debt or equity investment for the remaining 25% of construction costs.

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 $10,000,000. 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 5% 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 Office Lease		Total
Balance of 2007	$	1,065,329	$	84,475	$	1,149,804
2008		2,130,659		168,951		2,299,610
2009		2,130,659		168,951		2,299,610
2010		2,130,659		168,951		2,299,610
2011		2,130,659		70,396		2,201,055
Thereafter		47,121,666		—		47,121,666
Total minimum lease payments	$	56,709,631	$	661,724	$	57,371,355

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 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 six-month period ended June 30, 2007.

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.

Assets under capital lease - Assets under capital lease consist of land and buildings located in Barrie, Ontario to be developed for ethanol producing operations. We 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. We 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. We used our 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, we consider that the assets are not available for their intended use. Specifically, we expect 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. Our 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, we will use the findings of an engineering study that will be performed, with detailed recommendations on the usefulness of individual assets. We will write-off any portion of the buildings that may be demolished.

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.

Deferred financing costs – Deferred financing costs are costs and all related fees incurred to obtain debt financing and will be amortized as interest expense over the term of the related financing using the effective interest rate method.

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 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 September2006, 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 our consolidated financial statements issued for fiscal years beginning after November15, 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 or results of operations.

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 June 30, 2007, we had an accumulated deficit of $5,312,704. For the six-month period ended June 30, 2007, we incurred a net loss of $2,033,287, and for the year ended December 31, 2006, we incurred a net loss of $3,247,943. 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.

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-20^th 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 in 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 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 “PLAN OF OPERATION,” above. 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 WestLB AG (“WestLB”) whereby WestLB has conditionally agreed to provide arrangement, placement and underwriting services on senior debt and subordinate debt 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, WestLB 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 , bear an annual interest cost of approximately $24.2 million at current rates when fully drawn and would be repaid in quarterly installments over 6 years following completion of construction. The subordinate financing would amount to $68,100,000, bear an annual interest cost of approximately $10.5 million at current rates when fully drawn and would be repaid over 8 years from advance, with repayment terms to be negotiated. Among other things, the provision of the WestLB 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 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. (See a complete description of the terms under “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 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:

•	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.

If we are unable to raise the required senior debt and subordinate debt financing with WestLB, we will lose our non-refundable retainer deposit and we may be liable to pay significant termination fees. In December 2006, we paid a non-refundable retainer deposit of $200,000 to WestLB on execution of the engagement letter and indicative term sheets. We also agreed to pay all of WestLB’s expenses in connection with arrangement, placement and underwriting of the financing. As of the date of this Report, we have paid $87,378 for costs incurred by WestLB’s legal and engineering advisors. If WestLB is unable to secure adequate financing, or financing on acceptable terms is unavailable for any reason, we will lose the $200,000 non-refundable retainer deposit and we will not be able to recover expenses paid. 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 be required to pay WestLB a termination fee of $10,000,000.

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 terminates April 30, 2009. We expect to renew this agreement upon termination, but there are no assurances that the parties will reach an agreement. 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 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.

US Ethanol Production 1999-2006

January 1999

January 2000

January 2001

January 2002

January 2003

January 2004

January 2005

January 2006

Total Ethanol Plants

Ethanol 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 mgy

Plants Under Construction

Capacity 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.

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. Recently wholesale gasoline and ethanol prices have moved in the same range, trading at approximately $1.99 and $1.86 per gallon, respectively, as of August 15,2007. If the price of gasoline and petroleum declines, 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 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. 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 in Ontario as well 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. 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 existing fire 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 August 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. In March 2007, we applied for this permit for the Barrie plant and expect to receive the final permit in July 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 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:

Based on Ontario Ministry of Environment guidelines and communications, receive Ontario Ministry of Environment permit in September 2007.

Based on consulting engineer’s experience, receive City of Barrie site plan approval in September 2007.

Based on EPC term sheet signed March 9, 2007 with AKSC and discussions with other EPC contractor and ethanol plant technology providers, develop and negotiate EPC contract and receive EPC pricing from EPC contractor and ethanol plant technology provider in October 2007.

If another EPC contractor and ethanol plant technology provider selected, allow 60 days for Delta to decide whether to assume agreement. Sign an EPC contract with AKSC and Delta or another combination of EPC contractor and ethanol plant technology provider by December 2007.

Based on requirements of WestLB indicative term sheets dated December 13, 2006, close debt and or equity financing in December 2007.

With financing closed, give EPC contractor full notice to proceed with detailed engineering work in December 2007.

Based on discussions with AKSC and other EPC contractors, completion of site preparation work in February 2008.

Based on discussions with AKSC and other EPC contractors, EPC contractor mobilizes to site in February 2008.

Based on discussions with AKSC and other EPC contractors, first pour of concrete in March 2008.

10.

Based on discussions with AKSC and other EPC contractors, start of plant commissioning in March 2009.

11.

Based on EPC term sheet signed March 9, 2007 with AKSC and discussions with other EPC contractor and ethanol plant technology providers, full operations of plant in June 2009.

We expect the Sarnia plant start up will follow the Barrie timeline by approximately 3 months.

Any significant increase in the final construction costs of our proposed facilities will adversely affect our capital resources. Based upon discussions that we have had with AKSC, with other EPC contractor and ethanol plant technology providers and WestLB, all of whom are experienced in constructing ethanol plants, 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 on discussions with other EPC contractor and ethanol plant technology providers, engineering estimates, and on WestLB’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 or other EPC contractor and ethanol plant technology providers for our Barrie Plant in August 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 intend to seek additional funding to deal with any adverse contingencies that may arise before construction is completed, or at the very least have such potential sources of funding in place if this situation occurs, 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 Northern Ethanol as we would be negatively affected by increases in transportation costs.¹

These freight costs may be higher than expected in the event of severe winter weather conditions. The locations chosen for our plants present a weather risk to Northern Ethanol 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 ways to transport corn (via truck, rail, and freighter on the Great Lakes) will help reduce the risk of weather-related delays.²

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.

_________________________

¹SOURCES: http://www.statcan.ca/Daily/English/061207/d061207a.htm

Muse Stancil & Co., Corn and Distillers Grains Report – pg 3

²SOURCES: http://www.theweathernetwork.com/weather/stats/pages/C02022.htm?CAON0040

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.

RISKS RELATED TO OUR COMMON STOCK

There is no 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. 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. Because we do not have significant financial reporting experience, we may experience delays in filing required reports with the Securities and Exchange Commission (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 Securities and Exchange Commission 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 ensure 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 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, 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 ceased and these holders are 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;

•	changing conditions in the ethanol and fuel markets;

•	changes in market valuations of similar companies;

•	stock market price and volume fluctuations generally;

•	regulatory developments;

•	fluctuations in our quarterly or annual operating results;

•	additions or departures of key personnel; 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 3.

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 June 30, 2007, management has identified the following weaknesses:

•

Segregation of Duties – Given our limited staff level, certain duties within the accounting and finance department cannot be properly segregated resulting in a weakness in the area of segregation of duties which could result in a material misstatement in our financial statements. This weakness is considered to be a common area of deficiencies for many smaller listed companies.

•

Financial Reporting Process – A weakness existed in regard to our financial reporting process as it related to accounting for foreign currency translations beginning in 2006 that necessitated the restatement of results for the year ended December 31, 2006 and for the three month period ended March 31, 2007 and June 30, 2007. The spreadsheet used to prepare our consolidated financial statements has been improved and is expected to be replaced with a multi-currency, multi-site accounting software in 2008.

We rely on certain compensating controls, including substantive periodic review of the financial statements by our Chief Executive Officer and Audit Committee.

On December 7, 2006 and as amended on December 26, 2006, we filed Forms 8-K, and 8-K/A1to advise that our Form 10Q-SB 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 (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.

On April 23, 2007, we filed a Form 8-K/A2 advising that all outstanding issues have been resolved with KPMG LLP, our independent registered public accountants, and that investors may rely upon our 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 (inception) to September 30, 2006, and the related Management’s Discussion and Analysis contained in our Form 10-QSB filed on November 21, 2006.

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 six-month period ended June 30, 2007.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS - None

ITEM 2.

CHANGES IN SECURITIES - None

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES - None

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

On June 6, 2007, we conducted our annual meeting of shareholders in Toronto, Ontario, Canada. At that meeting our shareholders re-elected our current Board of Directors, to hold office until the next annual meeting of our shareholders, their resignation or removal, whichever comes first. Our shareholders also approved the appointment of KPMG LLP as our independent auditors for our fiscal year ended December 31, 2007.

ITEM 5.

OTHER INFORMATION - None

ITEM 6.

EXHIBITS AND REPORTS ON FORM 8-K -

(a)

Exhibits

Exhibit No.	Description

31.1	Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	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

(b)

Reports on Form 8-K.

On April 23, 2007 we filed a report on Form 8-K/A2, advising that all outstanding issues between ourselves and KPMG LLP relating to our Form 10-QSB for the nine month period ended September 30, 2006 had been resolved and investors may rely upon said report.

SUBSEQUENT EVENTS

On August 1, 2007 we filed a report on Form 8-K, advising that we entered into a Line of Credit Agreement with Aurora Beverage Corporation, (“Aurora”) wherein Aurora has agreed to provide us with a $1 million unsecured line of credit.

On August 20, 2007 we filed a report on Form 8-K, advising that we entered into a Purchase and Sale Agreement with Lanxess Inc., (“LANXESS”) wherein LANXESS has agreed to sell us approximately 30 acres of land in Sarnia, Ontario for an amount of C$450,000.

SIGNATURES

Pursuant to the requirements of Section 12 of the Securities and Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: August 15, 2008

NORTHERN ETHANOL, INC.

(Registrant)

By:s/Gordon Laschinger______________

Gordon Laschinger,

Chief Executive Officer & President

Northern Ethanol (NOET) Inactive 10QSB/AQuarterly report (small business) (amended)