December 30, 2010 - 6-K: Report of foreign issuer [Rules 13a-16 and 15d-16]

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

PURSUANT TO RULE 13a – 16 OR 15d – 16 OF

THE SECURITIES EXCHANGE ACT OF 1934

For the month of December 2010

Commission File No. 0-53646

Eagleford Energy Inc.

(Registrant’s name)

1 King Street West, Suite 1505

Toronto, Ontario, Canada M5H 1A1

(Address of principal executive office)

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40F

Form 20-F x Form 40-F ¨

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

TABLE OF CONTENTS

1. Eagleford Energy Inc. Audited Consolidated Financial Statements for the years ended August 31, 2010, 2009 and 2008 as filed on SEDAR on December 29, 2010.

2. Eagleford Energy Inc. Management’s Discussion and Analysis of Financial Condition and Operating Results for the year ended August 31, 2010 as filed on SEDAR on December 29, 2010.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Dated: December 30, 2010	EAGLEFORD ENERGY INC.

	By:	/s/ James Cassina
	Name:	James Cassina
	Title:	President

ITEM 1

Consolidated Financial Statements

For the years ended August 31, 2010, 2009 and 2008

(Expressed in Canadian Dollars)

Consolidated Financial Statements

For the years ended August 31, 2010, 2009 and 2008

(Expressed in Canadian Dollars)

Contents

Auditors' Report

Comments by Auditors for U.S. Readers on
Canada-U.S. Reporting Difference

Consolidated Financial Statements

Consolidated Balance Sheets as at August 31, 2010 and 2009		2

Consolidated Statements of Loss, Comprehensive Loss and Deficit
For the Years Ended August 31, 2010, 2009 and 2008		3

Consolidated Statements of Shareholders’ Equity
For the Years Ended August 31, 2010, 2009 and 2008		4

Consolidated Statements of Cash Flows
For the Years Ended August 31, 2010, 2009 and 2008		5

Notes to Consolidated Financial Statements		6 - 37

AUDITORS’ REPORT

To the Shareholders of

Eagleford Energy Inc.

We have audited the consolidated balance sheets of Eagleford Energy Inc. (the “Company”) as at August 31, 2010 and 2009 and the related consolidated statements of loss, comprehensive loss and deficit, shareholders’ equity and cash flows for each of the years in the three year period ended August 31, 2010. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance, about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at August 31, 2010 and 2009 and the results of its operations and its cash flows for each of the years in the three year period ended August 31, 2010 in accordance with Canadian generally accepted accounting principles which differ in certain respects from generally accepted accounting principles in the United States (refer to Note 17).

/s/ “SCHWARTZ LEVITSKY FELDMAN LLP”

Toronto, Ontario, Canada	Chartered Accountants
December 23, 2010	Licensed Public Accountant

COMMENTS BY AUDITORS FOR U.S. READERS

ON CANADA - - U.S. REPORTING DIFFERENCE

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when the consolidated financial statements are affected by conditions and events that cast substantial doubt on the Corporation’s ability to continue as a going concern, such as those described in the summary of significant accounting policies. Although we conducted our audits in accordance with both Canadian generally accepted auditing standards and the Standards of the Public Company Accounting Oversight Board (United States), our report to the shareholders dated December 23, 2010 is expressed in accordance with Canadian reporting standards, which do not permit a reference to such events and conditions in the auditors’ report when these are adequately disclosed in the consolidated financial statements.

/s/ “SCHWARTZ LEVITSKY FELDMAN LLP”

Toronto, Ontario, Canada	Chartered Accountants
December 23, 2010	Licensed Public Accountant

Consolidated Balance Sheets

(Expressed in Canadian Dollars)

August 31	2010			2009

Assets
Current
Cash and cash equivalents	$	43,776		$	172,905
Marketable securities (Note 6)		1			1
Accounts receivable		53,060			20,421
Due from related party (Note 10)		1,325			-
		98,162			193,327
Oil and gas interests (Note 7)
Developed		314,000			407,000
Undeveloped		5,695,290			-
		6,009,290			407,000
	$	6,107,452		$	600,327

Liabilities and Shareholders’ Equity
Current
Accounts payable (Note 10)	$	488,741		$	152,984
Income taxes payable (Note 16)		-			10,215
Secured note payable (Note 12)		186,183			-
Due to shareholder		57,500			-
Loan payable (Note 11)		110,000			167,500
		842,424			330,699
Long term
Secured note payable (Note 12)		1,021,344			-
Asset retirement obligations (Note 8)		3,907			3,634
		1,025,251			3,634
Total Liabilities		1,867,675			334,333

Shareholders’ Equity
Share capital (Note 9)		3,817,184			825,386
Warrants (Note 9)		2,096,078			431,134
Contributed Surplus (Note 9)		43,750			38,000
Deficit		(1,717,235	)		(1,028,526	)
		4,239,777			265,994
	$	6,107,452		$	600,327
Going Concern (Note 1)
Related Party Transactions and Balances (Note10)
Contractual Obligations and Commitments (Note 18)
Subsequent Events (Note 19)

On behalf of the Board:

(signed) “James Cassina” Director

(signed) “Milton Klyman” Director

The accompanying summary of significant accounting policies and notes are an integral part of these consolidated financial statements

Consolidated Statements of Loss, Comprehensive Loss and Deficit

(Expressed in Canadian Dollars)

For the years ended August 31	2010			2009			2008

Oil and Gas Operations
Revenue	$	105,374		$	56,199		$	292

Operating Costs		102,590			83,187			-
Depletion		38,370			26,638			24
		140,960			109,825			24

Income (loss) from oil and gas operations		(35,586	)		(53,626	)		268

Expenses
Management fees (Note10)		24,000			18,000			12,000
Office and general		2,474			5,150			253
Professional fees		152,844			106,770			26,608
Transfer and registrar costs		45,206			24,965			4,486
Head office services		41,738			16,125			14,625
Expense recovery		-			-			(7,718	)
Write down of oil and gas interests		54,630			105,805			528
Consulting fees		326,511			-			-
Imputed interest		5,750			-			-
		653,153			276,815			50,782

Operating loss for the year before under noted items		(688,739	)		(330,441	)		(50,514	)
Interest		30			1,580			-

Net loss and comprehensive loss for the year		(688,709	)		(328,861	)		(50,514	)

Deficit, beginning of year		(1,028,526	)		(699,665	)		(649,151	)

Deficit end of year	$	(1,717,235	)	$	(1,028,526	)	$	(699,665	)

Loss per share, basic and diluted	$	(0.028	)	$	(0.019	)	$	(0.006	)

Weighted average shares outstanding		24,687,130			17,646,295			7,955,482

The accompanying summary of significant accounting policies and notes are an integral part of these consolidated financial statements

Consolidated Statements of Shareholders’ Equity

(Expressed in Canadian Dollars)

For the years ended August 31, 2010, 2009 and 2008

												CONTRI-
	SHARE CAPITAL					WARRANTS						BUTED
	Number		Amount			Number			Amount			SURPLUS		DEFICIT			TOTAL
Balance August 31, 2007		6,396,739	$	166,291			-			-			-	$	(649,151	)	$	(482,860	)
Private placement		2,575,000		151,313			2,575,000		$	100,875			-		-			252,188
Forgiveness of debt, related party		-		-			-			-		$	38,000		-			38,000
Debt conversion		1,500,000		150,000			-			-			-		-			150,000
Net loss for the year		-		-			-			-			-		(50,514	)		(50,514	)
Balance August 31, 2008		10,471,739		467,604			2,575,000			100,875			38,000		(699,665	)		(93,186	)
Private placement		2,600,000		67,600			2,600,000			62,400			-		-			130,000
Private placement		1,000,256		26,007			1,000,256			24,006			-		-			50,013
Issuance of units on acquisition of 1354166 Alberta Ltd.		8,910,564		231,675			8,910,564			213,853			-		-			445,528
Debt settlement		1,250,000		32,500			1,250,000			30,000			-		-			62,500
Net loss for the year													-		(328,861	)		(328,861	)
Balance August 31, 2009		24,232,559		825,386			16,335,820			431,134			38,000		(1,028,526	)		265,994
Warrants exercised		2,100,000		197,400			(2,100,000	)		(50,400	)							147,000
Warrants issued							500,000			326,511								326,511
Issuance of units on acquisition of Dyami Energy LLC		3,418,467		2,829,979			1,709,233			1,388,833								4,218,812
Transaction costs				(35,581	)													(35,581	)
Imputed interest													5,750					5,750
Net loss for the year															(688,709	)		(688,709	)
Balance August 31, 2010		29,751,026	$	3,817,184			16,445,053		$	2,096,078		$	43,750	$	(1,717,235	)	$	4,239,777

The accompanying summary of significant accounting policies and notes are an integral part of these consolidated financial statements

Consolidated Statements of Cash Flows

(Expressed in Canadian Dollars)

For the years ended August 31	2010			2009			2008

Cash provided by (used in)
Operating activities
Net loss for the year	$	(688,709	)	$	(328,861	)	$	(50,514	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion		38,370			26,638			24
Accretion		273			130			-
Write-down of oil and gas interests		54,630			105,805			528
Imputed interest		5,750			-			-
Consulting fees		326,511			-			-
Changes in non-cash working capital balances:
Accounts receivable		(9,312	)		(9,297	)		2,482
Accounts payable		63,382			33,252			(2,934	)
Income taxes payable		(10,215	)		-			-
		(219,320	)		(172,333	)		(50,414	)
Investing activities
Oil and gas interests		(26,597	)		(10,000	)		-
Cash and cash equivalents acquired on acquisition
of 1354166 Alberta Ltd.		-			90,499			-
Cash and cash equivalents acquired on acquisition
of Dyami Energy LLC		5,369			-			-
		(21,228	)		80,499			-
Financing activities
Share issue costs on acquisition of Dyami Energy LLC		(35,581	)		-			-
Warrants exercised		147,000			-			-
Proceeds from private placements, net		-			180,013			252,188
Repayment to note holders pursuant to acquisition
of 1354166 Alberta Ltd.		-			(118,000	)		-
		111,419			62,013			252,188

Increase (decrease) in cash for the year		(129,129	)		(29,821	)		201,774

Cash and cash equivalents, beginning of year		172,905			202,726			952

Cash and cash equivalents, end of year	$	43,776		$	172,905		$	202,726

Supplemental cash flow information
Income taxes paid	$	10,215		$	-		$	-

Cash and cash equivalents consists of:
Cash	$	43,776		$	72,392		$	202,726
Guaranteed investment certificates		-			100,513			-
	$	43,776		$	172,905		$	202,726

Non-cash transactions (Note 20)

The accompanying summary of significant accounting policies and notes are an integral part of these consolidated financial statements

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

1. Nature of Business

Eagleford Energy Inc.’s (“Eagleford” or the “Company”) business focus consists of acquiring, exploring and developing oil and gas interests. The recoverability of the amount shown for these properties is dependent upon the existence of economically recoverable reserves, the ability of the Company to obtain the necessary financing to complete exploration and development, and future profitable production or proceeds from disposition of such property. In addition the Company holds a 0.3% net smelter return royalty on 8 mining claim blocks located in Red Lake, Ontario which is carried on the consolidated balance sheets at nil. The Company’s common shares trade on the NASD OTCBB under the symbol EFRDF.

Going Concern

These consolidated financial statements have been prepared on a going concern basis which contemplates the realization of assets and the payment of liabilities in the ordinary course of business. The Company plans to obtain additional financing by way of debt or the issuance of common shares or some other means to service its current working capital requirements, any additional or unforeseen obligations or to implement any future opportunities. Should the Company be unable to continue as a going concern, it may be unable to realize the carrying value of its assets and to meet its liabilities as they become due. These consolidated financial statements do not include any adjustments for this uncertainty.

The Company has accumulated significant losses and negative cash flows from operations in recent years which raises doubt as to the validity of the going concern assumption. As at August 31, 2010, the Company had a working capital deficiency of $744,262 and an accumulated deficit of $1,717,235. Management of the Company does not have sufficient funds to meet its liabilities for the ensuing twelve months as they fall due. In assessing whether the going concern assumption is appropriate, management takes into account all available information about the future, which is at least, but not limited to, twelve months from the end of the reporting period. The Company's ability to continue operations and fund its liabilities is dependent on management's ability to secure additional financing and cash flow. Management is pursuing such additional sources of financing and cash flow to fund its operations and while it has been successful in doing so in the past, there can be no assurance it will be able to do so in the future. Management is aware, in making its assessment, of material uncertainties related to events or conditions that may cast significant doubt upon the Company's ability to continue as a going concern. Accordingly, they do not give effect to adjustments that would be necessary should the Company be unable to continue as a going concern and therefore realize its assets and liquidate its liabilities and commitments in other than the normal course of business and at amounts different from those in the accompanying consolidated financial statements.

2. Significant Accounting Policies

These consolidated financial statements of Eagleford have been prepared in accordance with accounting principles generally accepted in Canada. The preparation of our consolidated financial statements in accordance with US GAAP have resulted in differences to the consolidated balance sheet and the consolidated statement of loss, comprehensive loss and deficit from the consolidated financial statements prepared using Canadian GAAP (see Note 17).

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

2. Significant Accounting Policies (cont’d)

Principles of Consolidation

On November 12, 2009, the Company’s wholly owned subsidiary 1406768 Ontario Inc., changed its name to Eagleford Energy Inc. On November 30, 2009 the Company amalgamated with Eagleford Energy Inc. and upon the amalgamation the entity's new name is Eagleford Energy Inc. The consolidated financial statements include the accounts of Eagleford, the legal parent, together with its wholly owned subsidiaries, 1354166 Alberta Ltd. an Alberta operating company and Dyami Energy LLC a Texas limited liability exploration stage company. All inter-company account transactions have been eliminated on consolidation (see Note 4).

Oil and Gas Interests

The Company follows the successful efforts method of accounting for its oil and gas interest. Under this method, costs related to the acquisition, exploration, and development of oil and gas interests are capitalized. The Company carries as an asset, exploratory well costs if a) the well found a sufficient quantity of reserves to justify its completion as a producing well and b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If a property is not productive or commercially viable, its costs are written off to operations. Impairment of non producing properties is assessed based on management's expectations of the properties.

Depletion and Depreciation

Depletion of petroleum and natural gas properties and depreciation of production equipment are calculated on the unit of production basis based on:

(a) total estimated proved reserves calculated in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities;

(b) total capitalized costs, excluding undeveloped lands and unproved costs, plus estimated future development costs of proved undeveloped reserves; and

(c) relative volumes of petroleum and natural gas reserves and production, before royalties, converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil.

Impairment Test

The Company performs a impairment test calculation in accordance with the Canadian Institute of Chartered Accountants’ successful efforts method guidelines, including an impairment test on undeveloped properties. The recovery of costs is tested by comparing the carrying amount of the oil and natural gas assets to the reserves report. If the carrying amount exceeds the recoverable amount, then impairment would be recognized on the amount by which the carrying amount of the assets exceeds the present value of expected cash flows using proved plus probable reserves and expected future prices and costs. At August 31, 2010 the Company recorded an impairment of $54,630 (2009 - $105,805).

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

2.	Significant Accounting Policies (cont’d)

Revenue Recognition

Revenues associated with the sale of crude oil and natural gas are recorded when the title passes to the customer, the customer has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the Company provide the customer with a right of return.

Royalties

As is normal to the industry, the Company's future production is subject to royalties. These amounts are reported net of related tax credits.

Transportation

Costs paid by the Company for the transportation of natural gas, crude oil and natural gas liquids from the wellhead to the point of title transfer are recognized when the transportation is provided.

Environmental and Site Restoration Costs

The Company recognizes an estimate of the liability associated with an asset retirement obligation (“ARO”) in the financial statements at the time the liability is incurred. The estimated fair value of the ARO is recorded as a long-term liability with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a straight-line basis over the estimated life of the asset. The liability amount is increased each reporting period due to the passage of time and the amount of accretion to operations in the period. The ARO can also increase or decrease due to changes in the estimates of timing of cash flows or changes in the original estimated undiscounted cost. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the liability recorded.

Foreign Currencies

Monetary assets and liabilities denominated in currencies other than Canadian dollars are translated at exchange rates in effect at the balance sheet date. Non-monetary items are translated at historical rates. Revenue and expense items are translated at the average rates of exchange for the year. Exchange gains and losses are included in the determination of net income for the year.

Marketable Securities

At each financial reporting period, the Company estimates the fair value of investments which are held-for-trading, based on quoted closing bid prices at the consolidated balance sheet dates or the closing bid price on the last day the security traded if there were no trades at the consolidated balance sheet dates and such valuations are reflected in the consolidated financial statements. The resulting values for unlisted securities whether of public or private issuers, may not be reflective of the proceeds that could be realized by the Company upon their disposition. The fair value of the securities at August 31, 2010 was $1 (2009 - $1) (see Note 6).

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

2.	Significant Accounting Policies (cont’d)

Financial Instruments

All financial instruments are recorded initially at estimated fair value on the balance sheet and classified into one of five categories: held for trading, held to maturity, available for sale, loans and receivables and other liabilities. Cash and cash equivalents, and marketable securities are classified as held for trading and measured at estimated fair value. Accounts receivable and due from related party are classified as loans and receivables and measured at amortized cost. Accounts payable, loan payable, Due to shareholder and Secured notes payable are classified as other liabilities and measured at amortized cost.

The Company does not enter into derivative contracts (commodity price, interest rate or foreign currency) in order to manage risk. The Company does not utilize derivative contracts for speculative purposes, has not designated any derivative contracts as hedges, and has not recorded any assets or liabilities as a result of embedded derivatives.

The estimated fair value of cash and cash equivalents, accounts receivable and accounts payable approximate their carrying amounts due to their short terms to maturity.

Cash and cash equivalents

Cash and cash equivalents include bank accounts, trust accounts, and term deposits with maturities of less than three months.

Accounting Estimates

The preparation of the consolidated financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, and the disclosures of revenues and expenses for the reported year. Actual results may differ from those estimates.

The amounts recorded for depletion and amortization of oil and gas properties and the valuation of these properties, are based on estimates of proved and probable reserves, production rates, oil and gas prices, future costs and other relevant assumptions. The effect on the consolidated financial statements of changes in estimates in future periods could be significant.

Income Taxes

The Company accounts for income taxes under the asset and liability method. Under this method, future income tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial reporting and tax bases of assets and liabilities and available loss carry forwards and are measured using the substantively enacted tax rates and laws that will be in effect when the differences are expected to be reversed. A valuation allowance is established to reduce tax assets if it is more likely than not that all or some portions of such tax assets will not be realized.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

2.	Significant Accounting Policies (cont’d)

Non-Monetary Transactions

Transactions in which shares or other non-cash consideration are exchanged for assets or services are measured at the fair value of the assets or services involved in accordance with Section 3831 (“Non-monetary Transactions”) of the Canadian Institute of Chartered Accountants Handbook (“CICA Handbook”).

Stock Based Compensation

The Company has a stock-based compensation plan. Any consideration received on the exercise of stock options or sale of stock is credited to share capital. The Company records compensation expense and credits contributed surplus for all stock options granted. Stock options granted during the year are accounted for in accordance with the fair value method of accounting for stock-based compensation. The fair value for these options is estimated at the date of grant using the Black-Scholes option pricing model.

Loss Per Share

Basic loss per share is calculated by dividing the loss for the year by the weighted average number of common shares outstanding during the year. Diluted loss per share is computed using the treasury stock method. Under this method, the diluted weighted average number of shares is calculated assuming the proceeds that arise from the exercise of stock options and other dilutive instruments are used to repurchase the Company’s shares at their weighted average market price for the period.

Warrants

When the Company issues Units under a private placement comprising common shares and warrants, the Company follows the relative fair value method of accounting for warrants attached to and issued with common shares of the Company. Under this method, the fair value of warrants issued is estimated using a Black-Scholes option price model. The fair value is then related to the total of the net proceeds received on issuance of the Common shares and the fair value of the warrants issued therewith. The resultant relative fair value is allocated to warrants from the net proceeds and the balance of the net proceeds is allocated to the Common shares issued.

3. Change in Accounting Policy and Future Accounting Changes

(a) EIC Credit Risk

In January 2009, the CICA’s EIC concluded that an entity’s own credit risk and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and financial liabilities, including derivative instruments. The application of incorporating credit risk into the fair value should result in entities re-measuring the financial assets and financial liabilities as at the beginning of the period of adoption. This abstract should be applied retrospectively without restatement of prior periods to all financial assets and liabilities measured at fair value in interim and annual financial statements for periods ending on or after January 20, 2009. Retrospective application with restatement of prior periods is also permitted. The adoption of this standard did not impact the financial position or results of operations of the Company.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

3.	Change in Accounting Policy and Future Accounting Changes (cont’d)

(b) Financial Instruments – Disclosures

In June 2009, the Canadian Accounting Standards Board (“AcSB”) issued the amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures, which reflect the corresponding amendments made by the International Accounting Standards Board to IFRS 7, Financial Instruments: Disclosures, in March 2009. The amendments require that all financial instruments measured at fair value be presented into one of the three hierarchy levels set forth below for disclosure purposes. Each level is based on the transparency of the inputs used to measure the fair value of assets and liabilities.

(i) Level 1: Inputs are unadjusted quoted prices of identical instruments in active markets.

(ii) Level 2: Valuation models which utilize predominately observable market inputs.

(iii) Level 3: Valuation models which utilize predominately non-observable market inputs.

The classification of a financial instrument in the hierarchy is based upon the lowest level of input that is significant to the measurement of fair value. The amendments to Section 3862 also require additional disclosure relating to the liquidity risk associated with financial instruments. The amendments improve disclosure of financial instruments specifically as it relates to fair value measurements and liquidity risk. The adoption of the amendments did not impact the Company’s financial position or results of operations.

All financial instruments of the Company are classified under level 1 of the financial instrument hierarchy.

During fiscal 2010 the Company adopted Section 3064, “Goodwill and Intangible Assets”. This section replaces Section 3062, “Goodwill and Other Intangible Assets” and Section 3450, “Research and Development Costs”. Various changes have made to other sections of the CICA Handbook for consistency purposes. Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill subsequent to its initial recognition and of intangible assets by profit-oriented enterprises. Standards concerning goodwill are unchanged from the standards included in the previous Section 3062. The adoption of this standard did not have an impact on the Company’s financial statements.

(d) General Standard of Financial Statement Presentation

During fiscal 2010, the Company adopted amended Section 1400, “General Standard of Financial Statement Presentation” which includes requirements to assess and disclose the Company’s ability to continue as a going concern. The adoption of this new section did not have an impact on the Company’s financial statements.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

3.	Change in Accounting Policy and Future Accounting Changes (cont’d)

(e) Future Accounting Changes

Business Combinations, Consolidated Financial Statements and Non-controlling Interests – The CICA issued three new accounting standards in January 2009: section 1582, Business Combinations, section 1601, Consolidated Financial Statements, and section 1602, Non-controlling interests. These new standards will be effective for fiscal years beginning on or after January 1, 2011. The Company is in the process of evaluating the requirements of the new standards.

Section 1582 replaces section 1581, and establishes standards for the accounting for a business combination. It provides the Canadian equivalent to International Financial Reporting Standard IFRS 3 – Business Combinations. The section applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after January 1, 2011.

Sections 1601 and 1602 together replace 1600 – Consolidated Financial Statements, Section 1601, establishes standards for the preparation of consolidated financial statements. Section 1601 applies to interim and annual consolidated financial statements relating to fiscal years beginning on or after January 1, 2011.

Section 1602 establishes standards for accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. It is equivalent to the corresponding provisions of International Financial Reporting Standard IAS 27 - Consolidated and Separate Financial Statements and applies to interim and annual consolidated financial statements relating to fiscal years beginning on or after January 1, 2011.

In December 2009, the CICA issued EIC 175 – “Multiple Deliverable Revenue Arrangements” replacing EIC 142 – “Revenue Arrangements with Multiple Deliverables”. This abstract was amended to: (1) provide updated guidance on whether multiple deliverables exist, how the deliverables in an arrangement should be separated, and the consideration allocated; (2) require, in situations where a vendor does not have vendor-specific objective evidence (“VSOE”) or third-party evidence of selling price, that the entity allocate revenue in an arrangement using estimated selling prices of deliverables; (3) eliminate the use of the residual method and require an entity to allocate revenue using the relative selling price method; and (4) require expanded qualitative and quantitative disclosures regarding significant judgments made in applying this guidance. The accounting changes summarized in EIC 175 are effective for fiscal periods beginning on or after January 1, 2011, with early adoption permitted. Adoption may either be on a prospective basis or by retrospective application. If the Abstract is adopted early, in a reporting period that is not the first reporting period in the entity’s fiscal period, it must be applied retrospectively from the beginning of the Company’s fiscal period of adoption. The Company expects to adopt EIC 175 effective January 1, 2011. The Company does not believe the standard will have a material impact on its consolidated financial statements.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

3.	Change in Accounting Policy and Future Accounting Changes (cont’d)

(e) Future Accounting Changes (cont’d)

In February 2008, the Accounting Standards Board “(AcSB)” confirmed that the use of IFRS will be required in 2011 for publicly accountable enterprises in Canada. In April 2008, the AcSB issued an IFRS Omnibus Exposure Draft proposing that publicly accountable enterprises be required to apply IFRS, in full and without modification, for fiscal years beginning on or after January 1, 2011. The Company will issue its initial audited consolidated financial statements under IFRS including comparative information for the year ending August 31, 2011.

The eventual changeover to IFRS represents changes due to new accounting standards. The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations.

The Company is assessing the potential impacts of this changeover and is developing its IFRS changeover plan, which will include project structure and governance, resourcing and training, analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential exemptions to the initial adoption of IFRS as permitted by IFRS Statement 1.

4.	Business Combinations

2010 Acquisition

On August 31, 2010, Eagleford acquired 100% the issued and outstanding membership interests of Dyami Energy LLC, a Texas limited liability company (“Dyami Energy”).The purchase price was satisfied by (i) the issuance of 3,418,467 units of the Company. Each unit is comprised of one common share and one-half a purchase warrant. Each full warrant is exercisable into one additional common share at US$1.00 per share on or before August 31, 2014 (the “Units”); and (ii) the assumption of US$960,000 of Dyami Energy debt by way of a secured promissory note. The note bears interest at 6% per annum, is secured by the Leases and is payable on December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000.

The members of Dyami Energy entered into lock up/escrow agreements on closing and placed into escrow 50% of the Units (1,709,234 common shares and 854,617 purchase warrants) until such time that Company receives a National Instrument 51-101 compliant report from an independent engineering firm indicating at least 100,000 barrels of oil equivalent of proven reserves on either the Murphy Lease or any formation below the San Miguel on the Matthews Lease (the “Report”). In the event the Report is not received by Dyami Energy within two years of the closing date of the acquisition, the escrow units are returned to the Company for cancellation. In addition, without Eagleford’s prior written consent, the members may not offer, sell, contract to sell, grant any option to purchase, hypothecate, pledge, transfer title to or otherwise dispose of any of the Units during the period commencing on August 31, 2010 and ending on August 31, 2011 (the “Lock-Up Period”). During the Lock-Up Period, the members may not effect or agree to effect any short sale or certain related transactions with respect to the Eagleford’s common shares.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

4.	Business Combinations (cont’d)

2010 Acquisition (cont’d)

In connection with the acquisition, the Company agreed to pay the Vice President of Operations of Dyami Energy an annual salary of US$75,000 for the first year, and issue 850,000 common share purchase warrants, exercisable on an earn-out basis, for the purchase of 850,000 common shares of Eagleford at a price of US$1.00 per share during a period of five years from the date of issuance as follows:

Event	Number of Warrants Earned
Enhanced Oil Recovery Pilot Project Commencement(1)		100,000

$10,000,000 in Gross Sales(2)		100,000

$25,000,000 in Gross Sales(2)		100,000

$100,000,000 in Gross Sales(2)		100,000

$250,000,000 in Gross Sales(2)		100,000

$500,000,000 in Gross Sales(2)		100,000

Enhanced Oil Recovery Phase 2 Project Commencement(3)		250,000

(1) Refers to the commencement of an enhanced oil recovery system on the Matthews Lease resulting in the production of oil from the San Miguel formation from a configuration of 3 wells or more through an injection operation utilizing hot water, steam, nitrogen, or other such enhanced oil recovery system (the EOR Pilot Project) while Vice President of Operations is an employee of the Dyami Energy.

(2) Refers to revenues generated from oil or gas produced on the Matthews Lease and Murphy Lease while Vice President of Operations is an employee of the Dyami Energy.

(3) Refers to the production of oil from the San Miguel formation from an expansion of the EOR Pilot Project on the Matthews Lease that results in the production of oil at a rate of no less than 500 barrels a day net to Dyami Energy and continues at such rate of production for no less than 180 consecutive days while Vice President of Operations is a full time employee of Dyami Energy.

All US monetary considerations were exchanged at the date of acquisition using the Bank of Canada noon rate of $1.0639. Eagleford accounted for the transaction using the purchase method of accounting and as a result, the share capital and deficit of Dyami Energy are eliminated.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

4.	Business Combinations (cont’d)

2010 Acquisition (cont’d)

The fair value of the Dyami Energy transaction is approximately $4,218,812 (US$3,965,422) paid through the issuance of 3,418,467 Eagleford Units and the assumption and issuance of a $1,021,344 (US$960,000) secured promissory note. The purchase price allocation to the fair values of the assets and liabilities of Dyami Energy acquired as at August 31, 2010 is as follows:

Consideration:
Issuance of 3,418,467 Eagleford	$	4,218,812
Total consideration	$	4,218,812
Allocated to:
Cash		5,369
Accounts receivable		11,371
Drilling advances		7,266
Prepaid expenses		16,060
Oil and gas interests		5,472,464
Accounts payable and accrued liabilities		(272,374	)
Note payable		(1,021,344	)
Net assets acquired	$	4,218,812
Incurred transaction costs:
Financial advisory, legal and other expenses	$	35,581

Transaction costs of $35,581 were recorded as a reduction in share capital.

2009 Acquisition

On February 27, 2009, Eagleford acquired the issued and outstanding shares of 1354166 Alberta Ltd. (“1354166 Alberta”) for total consideration of $445,528 satisfied by the issuance of 8,910,564 units of the Company at $0.05 per unit. Each unit consists of one common share and one common share purchase warrant exercisable at $0.07 to purchase one common share until February 27, 2014. Following the closing, the Company paid to note holders of 1354166 Alberta the amount of $118,000 by cash payment. The acquisition was accounted for using the purchase method of accounting where the Company is identified as the acquirer. The purchase price allocation to the fair values of the assets and liabilities acquired as at February 27, 2009 is as follows:

Consideration:
Issuance of 8,910,564 Eugenic units at $0.05 per unit	$	445,528
Transaction costs		10,000
Total consideration	$	455,528
Allocated to:
Oil and gas interests		538,995
Notes payable and working capital deficit		(79,963	)
Asset retirement obligation		(3,504	)
Net assets acquired	$	455,528
Incurred transaction costs:
Financial advisory, legal and other expenses	$	10,000

The results of operations from this acquisition are included effective February 27, 2009.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

5.	Segmented Information

The Company’s only segment is oil and gas exploration and production and includes two geographic areas, Canada and the United States. The accounting policies applied to Eagleford’s operating segments are the same as those described in the summary of significant accounting policies.

Geographic information:

The following is segmented information as at and for the year ended August 31, 2010:

	Year ended August 31, 2010					As at August 31, 2010
	Interest and other income		Net income (loss)			Oil and gas interests		Other assets
Canada	$	30	$	(688,709	)	$	314,000	$	68,141
United States		-		-			5,695,290		30,021
Total	$	30	$	(688,709	)	$	6,009,290	$	98,162

The following is segmented information as at and for the year ended August 31, 2009:

	Year ended August 31, 2009					As at August 31, 2009
	Interest and other income		Net income (loss)			Oil and gas interests		Other assets
Canada	$	1,580	$	(328,861	)	$	407,000	$	193,327
United States		-		-			-		-
Total	$	1,580	$	(328,861	)	$	407,000	$	193,327

6.	Marketable Securities

	2010		2009
Investments in quoted companies
(Market value $1 (2009 - $1) (see Note 2)	$	1	$	1

7.	Oil and Gas Interests

	2010			2009
Developed-Alberta, Canada
Net book value at September 1	$	407,000		$	448
Acquisition of oil and gas interest (1354166 Alberta)		-			538,995
Depletion		(38,370	)		(26,638	)
Write down of oil and gas interests		(54,630	)		(105,805	)
Total developed, Alberta Canada		314,000			407,000

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

7.	Oil and Gas Interests (cont’d)

Undeveloped-Texas USA
Acquisition of 10% oil and gas interests		212,780		-
Exploration expenditures		10,046		-
Acquisition of oil and gas interest (Dyami Energy)		5,472,464		-
Total undeveloped, Texas, USA		5,695,290		-

Total developed and undeveloped	$	6,009,290	$	407,000

Alberta, Canada

The Company has a 0.5% non convertible gross overriding royalty in a natural gas well located in the Haynes area of Alberta and a 5.1975% interest in a natural gas unit located in the Botha area of Alberta, Canada.

Mathews Lease, Zavala County, Texas, USA

On June 14, 2010, Eagleford acquired a 10% working interest before payout and a 7.5% working interest after payout of production revenue of $15 million in a mineral lease comprising approximately 2,629 gross acres of land in Zavala County, Texas (the “Matthews Lease”) for consideration of $212,780. During the year ended August 31, 2010 the Company incurred on its 10% working interest exploration expenditures of $10,046 on the Matthews Lease.

On August 31, 2010 the Company acquired all of the issued and outstanding membership interests of Dyami Energy an exploration stage company and as such its unproved properties are not included in the costs subject to depletion. The Company’s unproved oil and gas properties include its interests in the Matthews Lease and the Murphy Lease.

Dyami Energy holds a 75% working interest before payout and a 61.50% working interest after payout of production revenue of $12.5 million in the Matthews Lease.

The royalties payable under the Matthews Lease are 25%.

Dyami Energy acquired its interest in the Matthews Lease through a Purchase and Sale Agreement dated effective February 23, 2010 (the “Agreement”). Under the terms of the Agreement, Dyami Energy has the following commitments:

(a) On or before August 23, 2010 Dyami Energy shall commence operations to drill an Initial Test Well on Matthews Lease to a depth of not less than 3,000 feet below the surface or to the base of the San Miguel “D” formation.

(b) On or before July 8, 2011, Dyami Energy shall commence operations to perform an injection operation (by use of steam, nitrogen or other) in the San Miguel formation on the Initial Test Well or any other well located on the Matthews Lease or, all of the interest acquired by Dyami Energy in the Matthews Lease shall be forfeited without further consideration;

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

7.	Oil and Gas Interests (cont’d)

(c) On or before January 1, 2011, Dyami Energy shall commence a horizontal well to test the Eagle Ford Shale formation with a projected lateral length of not less than 2,500 feet (the “Second Test Well”).

(d) Dyami Energy’s 15% working interest partner in the Matthews Lease has an obligation to participate in each of the operations provided for in (a), (b) and (c) above and if the partner fails to bear its share of the costs of such operations, the partner shall forfeit its interest in and to the well and the applicable spacing unit.

In August 2010, Dyami Energy commenced operations to drill its Dyami/Matthews #1-H well on the Matthews Lease to a measured depth of 8,563 feet, of which 5,114 feet was vertical depth into the Del Rio formation. The well was whipstocked at the top of the Austin Chalk formation and drilled with an 800 foot curve and extended horizontaly,3,300 feet into the Eagle Ford shale formation and accordingly Dyami Energy has satisfied (a) and (c) above.

Dyami Energy is the designated operator under the provisions of the Matthews Lease Operating Agreement.

The Matthews Oil and Gas Lease has a primary term of three years commencing April 12, 2008, unless commercial production is established from a well or lands pooled therewith or the lessee is then engaged in actual drilling or reworking on any well within 90 days thereafter. The lease shall remain in force so long as the drilling or reworking is processed without cessation of more than 90 days. The lease requires that such operations be continuous, without cessation of more than ninety days, and if production is established, then the lease will continue. If the lessee has completed a well as a producer or abandoned a well within forty-five days prior to the expiration of the primary term, the lessee may extend the lease by commencing a well within ninety days following the end of the primary term.

Murphy Lease, Zavala County, Texas, USA

Dyami Energy holds a 100% working interest in a mineral lease comprising approximately 2,637 acres of land in Zavala County, Texas (the “Murphy Lease”) subject to a 10% carried interest on the drilling costs on the first well drilled from surface to base of the Austin Chalk formation, and a 3% carried interest on the drilling costs on the first well drilled from the top of the Eagle Ford shale formation to basement. Thereafter Dyami Energy’s working interests range from 90% to 97%. The royalties payable under the Murphy Lease are 25%.

Dyami Energy acquired its interest in the Murphy Lease through an Assignment Agreement dated effective February 3, 2010 (the “Assignment Agreement”). The Murphy Oil and Gas Mineral Lease (“Mineral Lease Agreement’) has a primary term of three years commencing on February 2, 2010. Under the terms of the Assignment Agreement and the Mineral Lease Agreement, Dyami Energy has the following commitments:

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

7.	Oil and Gas Interests (cont’d)

a) to commence drilling (spud) a well to a depth to sufficiently test the Eagle Ford Shale formation by August 3, 2010 or pay a lease delay payment of US $25 per acre or US$65,925 in the aggregate (paid July 28, 2010) to extend the period to commence drilling for 180 days to January 30, 2011 or Dyami Energy shall be required to release and re-assign its rights in the Murphy Lease.

b) During the development of the Murphy Lease, Dyami Energy is required to commence drilling a well within 180 days, or otherwise release and re-assign its rights to the Murphy Lease, but excluding the unit acreage area it has already drilled and earned. Likewise, if a producing well ceases to produce, and such well is not timely re-worked or re-drilled within a six month period, Dyami Energy shall also be required to release and re-assign its rights to the Murphy Lease.

c) Three years after the cessation of continuous drilling, all rights below the deepest producing horizon in each unit then being held by production, shall be released and re-assigned to the Lessor, unless the drilling of another well has been proposed on said unit, approved in writing by Lessor, and timely commenced.

As of August 31, 2010, all of Company’s investments in oil and gas properties located within the United States are contained in one cost center. As no proven reserves related to these properties have been identified, the properties are classified as “exploratory prospects” and are not currently subject to depletion and amortization.

The Company performed an impairment test calculation at August 31, 2010 using forecast prices and costs to assess the potential impairment of its oil and gas properties. The oil and gas future prices are based on the commodity price forecast of the Company’s independent reserve evaluators. The following table summarizes the benchmark prices used in the ceiling test calculation:

Year	WTI Cushing Oklahoma ($US/bbl)		Edmonton Par Price 40o API ($Cdn/bbl)		Cromer Medium 29.3o API ($Cdn/bbl)		Natural Gas AECO Gas Prices ($Cdn/MMBtu)		Pentanes Plus F.O.B. Field Gate ($Cdn/bbl)		Butanes F.O.B. Field Gate ($Cdn/bbl)		Inflation Rate (%/Yr)		Exchange Rate ($US/$Cdn)
2010		79.06		82.80		78.66		4.03		84.80		58.63		1.5		0.934
2011		82.38		86.34		81.16		4.50		88.42		61.13		1.5		0.934
2012		84.48		88.57		81.48		4.98		90.71		62.71		1.5		0.934
2013		86.48		90.69		82.53		6.00		92.88		64.22		1.5		0.934
2014		90.22		94.67		85.20		7.75		96.95		67.03		1.5		0.934
2015 and thereafter escalated at 1.5%

At August 31, 2010 the Company recorded an impairment of $54,630 (2009 - $105,805).

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

8. Asset Retirement Obligation

The Company’s asset retirement obligations result from net ownership interests in natural gas assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted amount of cash flows required to settle its asset retirement obligations at August 31, 2010 was approximately $8,568 which will be incurred between 2011 and 2026 (2009 - $8,840). A credit-adjusted risk-free rate of 7 percent and an annual inflation rate of 5 percent were used to calculate the future asset retirement obligation.

	2010		2009
Balance, beginning of period	$	3,634	$	-
Liabilities assumed on acquisition of 1354166 Alberta		-		3,504
Accretion expense		273		130
	$	3,907	$	3,634

9. Share Capital and Contributed Surplus

Authorized:

Unlimited number of common shares

Unlimited non-participating, non-dividend paying, voting redeemable preference shares

Issued:

Common Shares	Number		Amount
Balance at August 31, 2007		6,396,739	$	166,291
Private Placement (note a)		2,575,000		151,313
Debt conversion (note b)		1,500,000		150,000
Balance at August 31, 2008		10,471,739		467,604
February 5, 2009 private placement (note c)		2,600,000		67,600
February 25, 2009 private placement (note d)		1,000,256		26,007
February 27, 2009 acquisition (note e)		8,910,564		231,675
February 27, 2009 debt settlement (note f)		1,250,000		32,500
Balance at August 31, 2009		24,232,559		825,386
Exercise of warrants (note g)		2,100,000		197,400
August 31, 2010 acquisition, net of transaction costs (note h)		3,418,467		2,794,398
Balance August 31, 2010		29,751,026	$	3,817,184

(a) On April 14, 2008 the Company completed a non-brokered private placement of 2,575,000 units at a purchase price of $0.10 per unit for gross proceeds of $257,500 (proceeds net of issue costs $252,188). Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until April 14, 2011, to purchase one common share at a purchase price of $0.20 per share. The amount allocated to warrants based on relative fair value using Black Scholes model was $100,875.

(b) On April 14, 2008 the Company entered into agreements to convert debt in the amount of $150,000 through the issuance of 1,500,000 shares at an attributed value of $0.10 per share.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

9. Share Capital and Contributed Surplus (cont’d)

(c) On February 5, 2009, the Company completed a non-brokered private placement of 2,600,000 units at a purchase price of $0.05 per unit for gross proceeds of $130,000. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 5, 2014, to purchase one common share at a purchase price of $0.07 per share. The amount allocated to warrants based on relative fair value using Black Scholes model was $62,400.

(d) On February 25, 2009, the Company completed a non-brokered private placement of 1,000,256 units at a purchase price of $0.05 per unit for gross proceeds of approximately $50,013. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 25, 2014 to purchase one common share at a purchase price of $0.07 per share. The amount allocated to warrants based on relative fair value using Black Scholes model was $24,006.

(e) On February 27, 2009, the Company acquired the issued and outstanding shares of 1354166 Alberta for total consideration of $445,528 satisfied by the issuance of 8,910,564 units of the Company at $0.05 per unit. Each unit consists of one common share and one common share purchase warrant exercisable at $0.07 to purchase one common share until February 27, 2014. The amount allocated to warrants based on relative fair value using Black Scholes model was $213,853.

(f) On February 27, 2009, the Company entered into an agreement with a non-related party, to settle debt in the amount of $62,500 through the issuance of a total of 1,250,000 units at an attributed value of $0.05 per unit. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 27, 2014 to purchase one common share at a purchase price of $0.07 per share. The amount allocated to warrants based on relative fair value using Black Scholes model was $30,000.

(g) During the year ended August 31, 2010, 1,100,000 warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $77,000 and 1,000,000 warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $70,000. The amount allocated to warrants based on relative fair value using Black Scholes model was ($50,400).

(h) On August 31, 2010, the Company acquired all of the issued and outstanding membership interests of Dyami Energy and issued 3,418,467 units of the Company. Each unit consists of one common share and one half a common share purchase warrant. Each full warrant is exercisable at US$1.00 to purchase one common share until August 31, 2014. The fair value of the acquisition was estimated to be $4,218,812. Transaction costs of $35,581 were recorded as a reduction to share capital. The amount allocated to warrants based on relative fair value using Black Scholes model was $1,388,833.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

9. Share Capital and Contributed Surplus (cont’d)

(i) Effective June 10, 2010, the Company retained Gar Wood Securities, LLC (“Gar Wood”) to act as Investment Banker/Financial Advisor to the Company for a period of two years. Under the terms of the Gar Wood engagement, the Company agreed to pay a fee of 6% of the gross proceeds raised and issue 1,500,000 common share purchase warrants (the “Warrants”) as follows:

1,000,000 Warrants are exercisable at US$1.00 to purchase 1,000,000 common shares expiring on December 10, 2011 and issuable in three equal tranches on June 10, 2010, December 10, 2010 and June 10, 2011; and

500,000 Warrants are exercisable at US$1.50 to purchase 500,000 common shares expiring on June 10, 2012 and issuable in three equal tranches on June 10, 2010, December 10, 2010 and June 10, 2011. The fair value of the warrants was recorded as compensation expense.

The following table summarizes the changes in warrants for the years then ended:

	2010					2009				2008
Warrants	Number of Warrants			Weighted Average Price		Number of Warrants		Weighted Average Price		Number of Warrants		Weighted Average Price
Outstanding beginning of year		16,335,820		$	0.09		2,575,000	$	0.20		-		-
Issued		2,209,233			1.04		13,760,820		0.07		2,575,000	$	0.20
Exercised		(2,100,000	)		0.07		-		-		-		-
Outstanding end of year		16,445,053		$	0.22		16,335,820	$	0.09		2,575,000	$	0.20

The following table summarizes the outstanding warrants as at August 31, 2010:

Number of Warrants	Note	Exercise Price		Expiry Date	Warrant Value ($)
2,575,000	(note a)	$	0.20	April 14, 2011	$	100,875
500,000	(note c, g)	$	0.07	February 5, 2014		12,000
1,000,256	(note d)	$	0.07	February 25, 2014		24,006
10,160,564	(note e, f)	$	0.07	February 27, 2014		243,853
333,333	(note i)	US$	1.00	December 10, 2011		214,372
166,667	(note i)	US $	1.50	June 10, 2012		112,139
1,709,233	(note h)	US$	1.00	August 31, 2014		1,388,833
16,445,053					$	2,096,078

The fair value of the warrants issued during the year ended August 31, 2010 and 2009 were estimated on the date of issue using the Black-Scholes pricing model with the following assumptions:

Black-Scholes Assumptions used	2010
Risk-free interest rate		3	%
Expected volatility		234	%
Expected life (years)		4
Dividend yield		0	%
Fair value of the warrants issued on June 10, 2010	$	0.65
Fair value of the warrants issued on August 31, 2010	$	0.81

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

9. Share Capital and Contributed Surplus (cont’d)

Black-Scholes Assumptions used	2009
Risk-free interest rate		3	%
Expected volatility		170	%
Expected life (years)		4
Dividend yield		0	%
Fair value of the warrants issued on February 5, 2009	$	0.05
Fair Value of the warrants issued on February 25, 2009	$	0.05
Fair Value of the warrants issued on February 27, 2009	$	0.05

Black-Scholes Assumptions used	2008
Risk-free interest rate		3	%
Expected volatility		129	%
Expected life (years)		3
Dividend yield		0	%
Fair value of the warrants issued on April 14, 2008	$	0.06

Weighted Average Shares Outstanding	2010		2009		2008
Weighted average shares outstanding, basic		24,687,130		17,646,295		7,955,482
Dilutive effect of warrants		16,008,996		9,749,557		1,009,467
Weighted average shares outstanding, diluted		40,696,126		27,395,852		8,964,949

The effects of any potential dilutive instruments on loss per share related to the outstanding warrants are anti-dilutive and therefore have been excluded from the calculation of diluted loss per share.

Stock Option Plan

The Company has a stock option plan to provide incentives for directors, officers and consultants of the Company. The maximum number of shares, which may be set aside for issuance under the stock option plan, is 4,846,512 common shares. To date, no options have been issued.

Contributed Surplus

Contributed surplus transactions for the respective years are as follows:

	Amount
Balance, August 31, 2007	$	-
Debt Conversion		38,000
Balance, August 31, 2008 and 2009		38,000
Imputed interest (see Note 10)		5,750
Balance, August 31, 2010	$	43,750

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

10. Related Party Transactions and Balances

The following transactions with an individual related to the Company which arose in the normal course of business have been accounted for at the exchange amount being the amount agreed to by the related parties, which approximates the arm’s length equivalent value:

		2010				2009				2008
Management fees to the former President and Director of the Company		$	24,000			$	18,000			$	12,000

The following balances owing to an individual related to the Company are included in accounts payable and are unsecured, non-interest bearing and due on demand:

		2010				2009				2008
Management fees to the former President and Director of the Company		$	-			$	14,700			$	6,000

The following balances owing to an individual related to the Company are included in accounts payable are unsecured, non-interest bearing and due on demand:

Commencing May 1, 2009 the Company increased the management fee from $1,000 to $2,500 per month to the former President of the Company.

On February 5, 2009, a corporation in which the Company’s former President has voting and investment power, acquired 1,600,000 Units at a price of $0.05 per unit. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 5, 2014, to purchase one common share at a purchase price of $0.07 per share.

On February 25, 2009, the Company’s former President acquired 600,000 Units at a price of $0.05 per Unit. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 25, 2014 to purchase one common share at a purchase price of $0.07 per share.

On February 25, 2009, a director of the Company acquired 50,000 Units at a price of $0.05 per Unit. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 25, 2014 to purchase one common share at a purchase price of $0.07 per share.

On February 27, 2009, Eagleford acquired the issued and outstanding shares of 1354166 Alberta for total consideration of $445,528 satisfied by the issuance of 8,910,564 units of the Company at $0.05 per unit. Following the closing, the Company paid to note holders of 1354166 Alberta the amount of $118,000 by cash payment.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

10. Related Party Transactions and Balances (cont’d)

At August 31, 2010 the Company has a due from related party receivable from Source Re-Work Program Inc., (“Source”) in the amount of $1,325 (US$1,245) for expenditures relating to the Matthews Lease. In addition, the Company has a secured note payable to Source in the amount of $186,183 (US$175,000) (see Note 7 and 12). Eric Johnson is the President of Source, the Vice President of Operations for Dyami Energy and a shareholder of the Company.

At August 31, 2010 the Company has a secured promissory note in the amount of $1,021,044 (US$960,000) payable to Benchmark Enterprises LLC (``Benchmark``). At August 31, 2010 interest accrued on the Secured Note of $26,862 (US$25,249) is included in accounts payable. Benchmark is a shareholder of the Company (see Note 4 and 12).

At August 31, 2010 included in accounts payable is $82,154 due to Gottbetter & Partners LLP for legal fees. Gottbetter Capital Group, Inc. is a shareholder of the Company. Adam Gottbetter is sole owner of Gottbetter & Partners LLP and Gottbetter Capital Group, Inc.

The loan payable in the amount of $57,500 is due to a shareholder and is unsecured, non-interest bearing and repayable on demand. Interest was imputed at a rate of 10% per annum and interest in the amount of $5,750 was included in contributed surplus. On February 27, 2009, the Company entered into an agreement to settle $62,500 of the $120,000 loan through the issuance of a total of 1,250,000 units at an attributed value of $0.05 per unit. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 27, 2014 to purchase one common share at a purchase price of $0.07 per share.

11. Loan Payable

The loan payable in the amount of $110,000 is due to an arms’ length party and is unsecured, non-interest bearing and repayable on demand.

12. Secured Notes Payable

Current

On June 14, 2010 Eagleford entered into an agreement to acquire a 10% working interest before payout and a 7.5% working interest after payout in the Matthews Lease (the “Interest”). As consideration for the Interest the Company paid on closing August 31, 2010 $212,780 (US$200,000), satisfied by $26,597 (US$25,000) paid in cash on closing and $186,183 (US$175,000), 5% secured promissory note in favour of Source Re-Work Program Inc. US$100,000 of principal together with accrued interest is due and payable on February 28, 2011 and US$75,000 of principal together with accrued interest is due and payable on August 31, 2011. The Company may, in its sole discretion, prepay any portion of the principal amount. The note is secured by the interest in oil and gas properties.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

12. Secured Notes Payable (cont’d)

Long Term

On August 31, 2010 Eagleford assumed $1,021,344 (US$960,000) of Dyami Energy debt by way of a secured promissory note payable to Benchmark Enterprises LLC (the “Secured Note”). The Secured Note bears interest at 6% per annum, is secured by the Matthews and Murphy Leases and is payable on December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000. The Company may, in its sole discretion, prepay any portion of the principal amount. At August 31, 2010, the Matthews Lease and the Murphy Lease are carried on the books of the Company at $5,209,330 and $263,134 respectively.

13. Seasonality and Trend Information

The Company’s oil and gas operations is not a seasonal business, but increased consumer demand or changes in supply in certain months of the year can influence the price of produced hydrocarbons, depending on the circumstances. Production from the Company’s oil and gas properties is the primary determinant for the volume of sales during the year.

The level of activity in the oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and gas properties are located in areas that are inaccessible except during the winter months because of swampy terrain and other areas are inaccessible during certain months of year due to deer hunting season. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for the goods and services of the Company.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers conduct active exploration programs. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

World oil and gas prices are quoted in United States dollars and the price received by Canadian producers is therefore effected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. Material increases in the value of the Canadian dollar may negatively impact production revenues from Canadian producers. Such increases may also negatively impact the future value of such entities' reserves as determined by independent evaluators. In recent years, the Canadian dollar has increased materially in value against the United States dollar.

The economic impact that the Kyoto Protocol and other environmental initiatives will have on the sector and changes relating to Alberta government royalty programs implemented along with the New Royalty Framework will vary company to company and the amount and degree of these impacts have yet to be determined.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

14. Financial Instruments and Risk Factors

The Company is exposed to financial risk, in a range of financial instruments including cash, other receivables and accounts payable and income taxes payable and loans payable. The Company manages its exposure to financial risks by operating in a manner that minimizes its exposure to the extent practical. The main financial risks affecting the Company are discussed below.

The fair value of financial instruments at August 31, 2010 and 2009 is summarized as follows:

	2010				2009
	Amount		Fair Value		Amount		Fair Value
Financial assets

Held for trading
Cash and cash equivalents	$	43,776	$	43,776	$	172,905	$	172,905

Loans and receivables
Accounts receivables	$	53,060	$	53,060	$	20,421	$	20,421
Related party receivable	$	1,325	$	1,325		-		-

Financial liabilities
Accounts payable	$	488,741	$	488,741	$	152,984	$	152,984
Income taxes payable	$	-	$	-	$	10,215	$	10,215
Loan payable	$	110,000	$	110,000	$	167,500	$	167,500
Due to shareholder	$	57,500	$	57,500	$	-	$	-
Secured notes payable	$	1,207,527	$	1,145,289	$	-	$	-

Credit Risk

Credit risk is the risk of a financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligation and arises principally from joint venture partners and natural gas and oil marketers. The Company is exposed to credit risk in respect to its accounts receivable.

Cash and cash equivalents are held in operating accounts with highly rated Canadian banks and therefore the Company considers these assets to have negligible credit risk.

Receivables from petroleum and natural gas marketers are normally collected on the 25th day of the month following production. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers. Joint venture receivables are typically collected in one to three months of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to the expenditure. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, a further risk exists with joint venture partners, such as disagreements, that increase the potential for non-collection. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, the Company does have the ability to withhold information and production from joint venture partners in the event of non-payment.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

14. Financial Instruments and Risk Factors (cont’d)

As at August 31, 2010 the Company’s accounts receivable was $53,060 (2009 $20,421) of which $23,935 is due from government agencies (2009 $14,303), $5,797 is due from a gas marketer (2009 $6,118) $15,391 is due from a joint venture partner (2009 Nil) and the balance of $8,321 is due from other trade receivables.

The carrying amount of cash and cash equivalents and accounts receivable represents the Company’s maximum credit exposure

As at August 31, 2010 the Company’s accounts receivable is aged as follows:

Current (less than 90 days)	$	36,789
Past due (more than 90 days		16,271
	$	53,060

Liquidity Risk

Liquidity risk includes the risk that, as a result of the Company’s operational liquidity requirements:

- The Company will not have sufficient funds to settle their obligations or other transactions on the date they come due;

- The Company will be forced to sell financial assets at a value which is less than what they are worth; or

- The Company may be unable to settle or recover a financial asset at all.

The Company’s operating cash requirements including amounts projected to complete the Company’s existing capital expenditure program are continuously monitored and adjusted as input variables change. These variables include but are not limited to, shareholder loans, oil and natural gas production from existing wells, results from new wells drilled, commodity prices, cost overruns on capital projects and regulations relating to prices, taxes, royalties, land tenure, allowable production and availability of markets. These variables create liquidity risk which has necessitated the need to raise financing to meet capital and operating cash-flow needs. The Company has liquidity risk which necessitates the Company to obtain debt financing, enter into joint venture arrangements, or raise equity. There is no assurance the Company will be able to obtain the necessary financing in a timely manner.

The following table illustrates the contractual maturities of financial liabilities as at August 31, 2010.

	Payments Due by Period
	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable	$	488,741	$	488,741		-		-		-
Loan Payable		110,000		110,000		-		-		-
Secured notes payable (1)		1,207,527		186,183	$	1,021,344		-		-
Due to shareholder		57,500		57,500		-		-		-
Asset retirement obligation		3,907		-		-		-	$	3,907
Total contractual obligations	$	1,867,675	$	842,424	$	1,021,344		-	$	3,907

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

14. Financial Instruments and Risk Factors (cont’d)

(1) Translated at current exchange rate.

Market Risk

Market risk represents the risk of loss that may impact our financial position, results of operations, or cash flows due to adverse changes in financial market prices, including interest rate risk, foreign currency exchange rate risk, commodity price risk, and other relevant market or price risks. The Company does not have activities related to derivative financial instruments or derivative commodity instruments. The Company holds marketable securities which have been written down to $1 on our consolidated balance sheet.

The oil and gas industry is exposed to a variety of risks including the uncertainty of finding and recovering new economic reserves, the performance of hydrocarbon reservoirs, securing markets for production, commodity prices, interest rate fluctuations, potential damage to or malfunction of equipment and changes to income tax, royalty, environmental or other governmental regulations.

We mitigate these risks to the extent we are able by:

• utilizing competent, professional consultants as support teams to company staff.

• performing careful and thorough geophysical, geological and engineering analyses of each prospect.

• focusing on a limited number of core properties.

Market risk is the possibility that a change in the prices for natural gas, natural gas liquids, condensate and oil, foreign currency exchange rates, or interest rates will cause the value of a financial instrument to decrease or become more costly to settle.

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions worsened in 2008 and continued in 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and may impact the performance of the global economy going forward. Although economic conditions improved towards the latter portion of 2009, as anticipated, the recovery from the recession has been slow in various jurisdictions including in Europe and the United States and has been impacted by various ongoing factors including sovereign debt levels and high levels of unemployment which continue to impact commodity prices and to result in high volatility in the stock market.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

14. Financial Instruments and Risk Factors (cont’d)

(i) Commodity Price Risk

Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum and natural gas are impacted by world economic events that dictate the levels of supply and demand.

The Company believes that movement in commodity prices that are reasonably possible over the next twelve month period will not have a significant impact on the Company.

Commodity Price Sensitivity

The following table summarizes the sensitivity of the fair value of the Company’s risk management position for the year ended August 31, 2010 and 2009 to fluctuations in natural gas prices, with all other variables held constant. When assessing the potential impact of these price changes, the Company believes that 10 percent volatility is a reasonable measure. Fluctuations in natural gas prices potentially could have resulted in unrealized gains (losses) impacting net income as follows:

	2010						2009
	Increase 10%			Decrease 10%			Increase 10%			Decrease 10%
Revenue	$	115,911		$	94,837		$	61,819		$	50,579
Net loss	$	(678,172	)	$	(699,246	)	$	(323,241	)	$	(334,481	)

(ii) Foreign Exchange Risk

The Company is exposed to the financial risk related to the fluctuation of foreign exchange rates The prices received by the Company for the production of natural gas and natural gas liquids are primarily determined in reference to U.S. dollars but are settled with the Company in Canadian dollars. The Company’s cash flow for commodity sales will therefore be impacted by fluctuations in foreign exchange rates. The Company considers this risk to be limited.

The Company operates in Canada and the United States and a portion of its expenses are incurred in United States dollars. A significant change in the currency exchange rates between the CDN dollar relative to US dollar could have an effect on the Company’s results of operations, financial position or cash flows.

The Company is exposed to currency risk through the following assets and liabilities denominated in US$ at August 31, 2010 (2009 Nil):

Financial Instrument	US$
Cash and cash equivalents	$	5,046
Accounts receivable		21,926
Due from related party		1,245
Accounts payable		198,015
Secured notes payable		1,135,000
Total US$	$	1,361,232
CDN dollar equivalent at year end	$	1,448,215

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

14. Financial Instruments and Risk Factors (cont’d)

(ii) Foreign Exchange Risk (cont’d)

The Company acquired all of the issued membership shares of Dyami Energy, a Texas limited liability company on August 31, 2010 and accordingly its results from operations, denominated in US dollars are not included in the Company’s Financial Statements.

(iii) Interest Rate Risk

Interest rate risk refers to the risk that the value of a financial instrument or cash flows associated with the instrument will fluctuate due to changes in market interest rates. The majority of the Company’s debt is in fixed rate secured notes payable. As at August 31, 2010 the Company did not have any interest rate hedges.

Based on management's knowledge and experience of the financial markets, the Company believes that the movements in interest rates that are reasonably possible over the next twelve month period will not have a significant impact on the Company.

15. Capital Management

The Company’s objectives when managing capital is to safeguard the entity’s ability to continue as a going concern. The Company sets the amount of capital in proportion to risk. The Company manages the capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of any underlying assets. In order to maintain or adjust capital structure the Company may from time to time issue equity, issue debt, adjust its capital spending and sell assets to manage current and projected debt levels. The board of directors does not establish quantitative return on capital criteria for management, but rather relies on the expertise of the Company's management to sustain future development of the business.

As at August 31, 2010 the Company considers its capital structure to include the following:

	2010			2009
Shareholders’ equity	$	4,239,777		$	265,994
Long term debt		(1,025,251	)		(3,634	)
Working capital deficiency		(744,262	)		(137,372	)
	$	2,470,264		$	124,988

Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Company, is reasonable.

There were no changes in the Company’s capital management during the period ended August 31, 2010.

The Company is not subjected to any externally imposed capital requirements.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

16. Income Taxes

The Company has capital losses in the amount of approximately $195,852 (2009 - $195,852) which may be carried forward indefinitely to offset future capital gains, and non capital losses in the amount of approximately $794,304 (2009 - $525,825) available for carry forward purposes. The non capital losses expire as follows:

2014	$	46,501
2015		47,434
2026		55,415
2027		42,337
2028		49,166
2029		279,094
2030		274,357
	$	794,304

The Company has provided a full valuation allowance against future tax assets at August 31, 2010, due to uncertainties in the Company's ability to utilize its net operating losses.

A reconciliation between income taxes provided at actual rates and at the basic rate ranging from 28% to 31% (2009 – 25% to 29%) (2008 - 34.5%) for federal and provincial taxes is as follows:

	2010			2009			2008
Taxes at statutory rates	$	(203,169	)	$	(88,792	)	$	(17,427	)
Non-taxable items and others		154,677			47,326			-
Change in valuation allowance		48,492			41,466			17,427
	$	-		$	-		$	-

The significant components of the Company's future tax asset are summarized as follows:

	2010			2009
Operating loss carry forwards	$	198,576		$	149,197
Share issue costs		11,959			5,792
Marketable securities		1,467			1,701
Capital losses carry forwards		24,482			28,399
Oil and gas interests		17,939			20,594
Cumulative eligible capital		1,418			1,685
		255,861			207,368
Valuation allowance		(255,861	)		(207,368	)
	$	-		$	-

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

17. Reconciliation to Accounting Principles Generally Accepted in the United States

The Company's accounting policies do not differ materially from accounting principles generally accepted in the United States ("US GAAP") except for the following:

Oil and Gas Interests

In applying the successful efforts method under US GAAP (Regulation S-X Article 4-10), the Company performs a ceiling test based on the same calculations used for Canadian GAAP except the Company is required to discount future net revenues from proved reserves at 10% as opposed to utilizing the fair market value and probable reserves are excluded. During the year an impairment loss of $104,630 (2009 - $179,443) for US GAAP and an impairment loss of $54,630 (2009- $105,805) was recorded for Canadian GAAP.

If US GAAP was followed, the effect on the consolidated balance sheet would be as follows:

	2010			2009
Total assets according to Canadian GAAP	$	6,107,452		$	600,327
Additional impairment of oil and gas interests		(50,000	)		(73,638	)
Total assets according to US GAAP	$	6,057,452		$	526,689

	2010			2009
Total shareholders’ equity according to Canadian GAAP		4,239,777		$	265,994
Deficit adjustment per US GAAP
Additional impairment of oil and gas interests		(50,000	)		(73,638	)
Total shareholders’ equity according to US GAAP	$	4,189,777		$	192,356

If US GAAP was followed, the effect on the consolidated statements of loss and comprehensive loss would be as follows:

	2010			2009			2008
Net loss, comprehensive loss according to Canadian GAAP		688,709		$	328,861		$	50,514
Add: Additional impairment of oil and gas interests		50,000			73,638			-
Net loss, comprehensive loss according to US GAAP	$	738,709		$	402,499		$	50,514
Loss per share, basic and diluted	$	(0.030	)	$	(0.023	)	$	(0.006	)
Shares used in the computation of loss per share		24,687,130			17,646,295			7,955,482

Adoption of New Accounting Policies

Financial Accounting Standards Board’s Codification of US GAAP

On July 1, 2009, the FASB’s Codification of US GAAP (the “Codification”) was issued to create a consolidated reference source for all authoritative non-governmental US GAAP. The Codification was not intended to change US GAAP, but rather reorganize existing guidance by accounting topic to allow easier identification of applicable standards. References in the Company’s consolidated financial statements to US GAAP have been updated to reflect the Codification.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

17. Reconciliation to Accounting Principles Generally Accepted in the United States (cont’d)

Business combinations

In December 2007, the FASB issued ASC 805 — Business Combinations (“ASC 805”) (formerly referred to as FAS 141R) which is effective for fiscal years beginning after December 15, 2008. ASC 805, which will replace FAS 141, is applicable to business combinations consummated after the effective date of December 15, 2008. This Standard modifies the accounting of certain aspects of business combinations. The adoption of ASC 805 did not have a material impact on the Company’s consolidated financial statements.

Non-controlling interests

In December 2007, the FASB also issued ASC 810 - Non-controlling Interests in Consolidated Financial Statements (“ASC 810”). ASC 810 will change the accounting and reporting for minority interests, which will be re-characterized as non-controlling interests and classified as a component of equity. ASC 810 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008 and interim periods within those fiscal years. The adoption of ASC 810 did not have a material impact on the Company’s consolidated financial statements.

Derivative Instruments and Hedging Activities

In March 2008, the FASB issued ASC 815 “Disclosures about Derivative Instruments and Hedging Activities” (“ASC 815”). This Statement requires enhanced disclosures about an entity’s derivative and hedging activities and thereby improves the transparency of financial reporting. This Statement is effective for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. The adoption of ASC 815 did not have a material impact on the Company’s consolidated financial statements.

Subsequent events

In May 2009, the FASB issued ASC 855, “Subsequent Events” (“ASC 855”). This Statement established general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In particular, this Statement details the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occur after the balance sheet date. The adoption of ASC 855 did not have a material impact on the Company’s consolidated financial statements.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

17. Reconciliation to Accounting Principles Generally Accepted in the United States (cont’d)

The Fair Value Measurement of Liabilities

In August 2009, the FASB issued ASU 2009-05 “Measuring Liabilities at Fair Value” (“ASU 2009- 05”), which provides amendments to Subtopic 820-10 “Fair Value Measurements and Disclosures — Overall” and is effective prospectively for interim periods beginning after October 1, 2009 for the Company. ASU 2009-05 provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one of the valuation techniques that uses (a) the quoted price of the identical liability when traded as asset; (b) quoted prices for similar liabilities when traded as assets; or another valuation technique that is consistent with the principles of Topic 820 “Fair Value Measurements and Disclosures”. Therefore, the fair value of the liability shall reflect non-performance risk, including but not limited to a reporting entity’s own credit risk. ASU 2009-05 also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of liability. The adoption of ASU 2009-05 will not have a material impact on the Company’s consolidated financial statements.

Equity method investees

The Company adopted the FASB’s guidance on equity method investment accounting considerations which is included in ASC 323 — Investments — Equity Method and Joint Ventures and applicable for fiscal years beginning on or after December 15, 2008. The guidance indicates when investments accounted for using the equity method are impaired and the appropriate initial measurement and accounting for subsequent changes in ownership percentages. The adoption of this guidance did not result in a material impact to the Company’s consolidated financial statements.

Future U.S. Accounting Policy Changes

Accounting of Transfers of Financial Assets an amendment of FASB No. 140

In June 2009, FASB issued Statement No. 166, Accounting of Transfers of Financial Assets an amendment of FASB No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement is now known as ASC 860. This Statement improves the relevance, representational faithfulness, and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance, and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. The Board undertook this project to address (1) practices that have developed since the issuance of FASB Statement No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities that are not consistent with the original intent and key requirements of that Statement and (2) concerns of financial statement users that many of the financial assets (and related obligations) that have been derecognized should continue to be reported in the financial statements of transferors. This Statement must be applied as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period and for interim and annual reporting periods thereafter. Earlier application is prohibited. The Company does not believe that the new standard will have any material impact to the Company’s consolidated financial statements.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

17. Reconciliation to Accounting Principles Generally Accepted in the United States (cont’d)

Variable interest entities an Amendment to FASB Interpretation No.46(R)

In June 2009, FASB issued Statement No. 167, Amendment to FASB Interpretation No.46(R). This Statement improves financial reporting by enterprises involved with variable interest entities. The Board undertook this project to address (1) the effects on certain provisions of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, as a result of the elimination of the qualifying special-purpose entity concept in FASB Statement No. 166, Accounting for Transfers of Financial Assets, and (2) constituent concerns about the application of certain key provisions of Interpretation 46(R), including those in which the accounting and disclosures under the Interpretation do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. This Statement shall be effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. Earlier application is prohibited. The Company does not believe that the new standard will have any material impact to the Company’s consolidated financial statements.

In December 2008, the SEC published its final rule, (SAB 113) Modernization of Oil and Gas reporting requirements, to modernize and update oil and gas disclosure requirements and align them with current practice and change in technology. The Final Rule is effective for registration statements filed on or after January 1, 2010 and for annual reports on Forms 10-K and 20-F for fiscal years ending on or December 31, 2009. Adoption of this Rule on had no effect on the Company’s financial statements.

18. Contractual Obligations and Commitments

The Company has development commitments on its Mathews Lease and Murphy Lease in order to keep the leases in good standing (see Note 7).

19. Subsequent Events

During August 2010, Dyami Energy commenced operations to drill its Dyami/Matthews #1-H well on the Matthews Lease to a measured depth of 8,563 feet, of which 5,114 feet was vertical depth into the Del Rio formation. The well was whipstocked at the top of the Austin Chalk formation and drilled with an 800 foot curve and extended horizontaly, 3,300 feet into the Eagle Ford shale formation. The well reached total measured depth on October 15, 2010.

On September 17, 2010, 500,000 common share purchase warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $35,000.

On September 24, 2010 600,000 common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $42,000.

Subsequent to the year end, the Company received US$1,360,000 and CDN$149,000 and issued promissory notes to four shareholders. The notes are payable on demand and bear interest at 10% per annum. Interest is payable annually on the anniversary date of the notes.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the year ended August 31, 2010, 2009 and 2008

19. Subsequent Events (cont’d)

Subsequent to the year end the Company received US $300,000 and issued a promissory note to the President of the Company. The note is due on demand and bears interest at 10% per annum, Interest is payable annually on the anniversary date of the note.

On November 5, 2010 the Company terminated the agreement with Garwood dated June 10, 2010 and as a result 36,430 warrants exercisable at $1.00 expiring December 10, 2011 were cancelled and 18,215 warrants exercisable at $1.50 expiring June 10, 2012 were cancelled.

20. Non-Cash Transactions

The following table summarizes the non-cash transactions for the years then ended:

	2010			2009			2008
Acquisition of subsidiary		4,213,443		$	445,528			-
Issuance of units on acquisition of subsidiary		(4,213,443	)	$	(445,528	)		-
Transaction costs		35,581			-			-
Imputed interest		5,750			-			-
Warrants issued		326,511			-			-
Secured notes payable-Current		186,183			-			-
Secured notes payable-Long term		1,021,344			-			-
Shares issued to settle debt		-		$	62,500		$	150,000
Forgiveness of debt		-			-		$	38,000

21. Comparative Figures

Certain comparative figures have been reclassified to conform to the presentation adopted in 2010.

ITEM 2

Management’s Discussion and Analysis

of Financial Condition and Operating Results

For the year ended

August 31, 2010

1 King Street West, Suite 1505, Toronto, ON, Canada Telephone: 416 364 4039, Facsimile: 416 364-8244

The following Management’s Discussion and Analysis of Financial Condition and Operating Results of Eagleford Energy Inc. (“Eagleford” or the “Company”) should be read in conjunction with the Company’s Audited Consolidated Financial Statements for the years ended August 31, 2010 and 2009 and notes thereto stated in Canadian dollars. The results herein have been prepared in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). This Management’s Discussion and Analysis is dated December 19, 2010 and has been approved by the Board of Directors of the Company.

The following Management’s Discussion and Analysis (“MD&A”) may contain forward-looking statements. Forward-looking statements are based on current expectations that involve a number of risks and uncertainties, which could cause actual events or results to differ materially from those reflected herein. Forward-looking statements are based on the estimates and opinions of management of the Company at the time the statements were made. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek”, “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “project”, “predict”, “potential”, “targeting”, “intend”, “could”, “might”, “should”, “believe”, and similar expressions. Information concerning reserve estimates and capital cost estimates may also be deemed as forward-looking statements as such information constitutes a prediction of what might be found to be present and how much capital will be required if and when a project is actually developed. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements (see Risks and Uncertainties below).

Our Canadian public filings can be accessed and viewed via the System for Electronic Data Analysis and Retrieval (“SEDAR”) at www.sedar.com. Readers can also access and view our Canadian public insider trading reports via the System for Electronic Disclosure by Insiders at www.sedi.ca. Our U.S. public filings are available at the public reference room of the U.S. Securities and Exchange Commission (“SEC”) located at 100 F Street, N.E., Room 1580, Washington, DC 20549 and at the website maintained by the SEC at www.sec.gov.

GLOSSARY OF ABBREVIATIONS

Bbl	barrel
Bbl/d	barrels per day
Boe	barrels of oil equivalent (1)
Boe/d	barrels of oil equivalent per day
Mcf	1,000 cubic feet of natural gas
Mcf/d	1,000 cubic feet of natural gas per day

(1) Boe conversion ratio of 6 Mcf: 1Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Disclosure provided herein in respect of Boes may be misleading, particularly if used in isolation.

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of units (or metric units).

To Convert From	To	Multiply By

Mcf	Cubic metres		28.317
Cubic metres	Cubic feet		35.494
Bbls	Cubic metres		0.159
Cubic metres	Bbls		6.292
Feet	Metres		0.305
Metres	Feet		3.281
Miles	Kilometers		1.609
Kilometers	Miles		0.621
Acres (Alberta)	Hectares		0.405
Hectares (Alberta)	Acres		2.471

OVERVIEW

Eagleford Energy Inc. is incorporated under the laws of the Province of Ontario, and is registered as an extra-provincial company in Alberta. The Company is a reporting issuer with the United States Securities and Exchange Commission and the Company’s common shares trade on the Over-the-Counter Bulletin Board (OTCBB) under the symbol EFRDF.

The Company’s operations consist of a 0.5% Non Convertible Overriding Royalty in a natural gas well located in Haynes, Alberta, Canada a 5.1975% working interest in a natural gas unit located in Alberta, Canada, an 85% working interest before payout (69% working interest after payout) in Matthews lease comprising 2,629 gross acres of land in Zavala County, Texas. In addition, we hold a 100% working interest in the Murphy lease comprising approximately 2,637 acres of land in Zavala County, Texas subject to a 10% carried interest on the drilling costs on the first well drilled from surface to base of the Austin Chalk formation, and a 3% carried interest on the drilling costs on the first well drilled from the top of the Eagle Ford shale formation to basement.

In Addition, the Company also holds a 0.3% net smelter return royalty on eight mining claims located in Red Lake Ontario which is carried on the Consolidated Balance Sheets at $Nil.

The Company’s Audited Consolidated Financial Statements for the year ended August 31, 2010 and 2009 include the accounts of the Company, its wholly owned subsidiaries 1354166 Alberta Ltd. from the date of acquisition, February 27, 2009 and Dyami Energy from the date of acquisition August 31, 2010.

OVERALL PERFORMANCE

Revenue for the year ended August 31, 2010 was up $49,175 to $105,374 compared to $56,199 for the same period in 2009. The increase in revenue is attributed to a full twelve months of operations from 1354166 Alberta Ltd.

For the year ended August 31, 2010 the Company’s cash position decreased by $129,129 to $43,776 compared to cash of $172,905 at August 31, 2009. At August 31, 2010 the Company’s accounts receivable was $53,060 representing an increase of $32,639 compared to $20,421 at August 31, 2009. For the year ended August 31, 2010 current liabilities increased by $511,725 to $842,424 compared to $330,699 at August 31, 2009. The Company has working capital deficiency of $744,262 at August 31, 2010 compared to a working capital deficiency of $137,372 at August 31, 2009.

During the fiscal year ended August 31, 2010, 1,100,000 common share purchase warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $77,000 and 1,000,000 common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $70,000.

On August 31, 2010 the Company acquired a 10% working interest before payout and a 7.5% working interest after payout of production revenue of $15 million in a mineral lease comprising approximately 2,629 gross acres of land in Zavala County, Texas (the “Lease Interest”). As consideration for the Lease Interest the Company paid on closing $212,780 (US$200,000), satisfied by US$25,000 in cash and $186,183 (US$175,000), 5% secured promissory note.US$100,000 of principal together with accrued interest is due and payable on February 28, 2011 and US$75,000 of principal together with accrued interest is due and payable on August 31, 2011. The Company may, in its sole discretion, prepay any portion of the principal amount. The note is secured by the Lease Interest.

On August 31, 2010, the Company acquired 100% the issued and outstanding membership interests of Dyami Energy LLC, a Texas limited liability corporation for consideration of $4,218,812. (US$3,965,422) satisfied by (i) the issuance of 3,418,467 units of the Company. Each unit is comprised of one common share and one-half a purchase warrant. Each full warrant is exercisable into one additional common share at US$1.00 per share on or before August 31, 2014 (the “Units’) and (ii) the assumption of $1,021,344 (US$960,000) of Dyami Energy debt by way of a secured promissory note. The note bears interest at 6% per annum, is secured by the Leases and is payable on December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000. Dyami Energy holds a 75% working interest before payout and a 61.50% working interest after payout of production revenue of $12.5 million in the Matthews Lease comprising approximately 2,629 gross acres of land in Zavala County, Texas and a 100% working interest in the Murphy Lease comprising approximately 2,637 acres of land in Zavala County, Texas, subject to a 10% carried interest on the drilling costs on the first well drilled from surface to base of the Austin Chalk formation, and a 3% carried interest on the drilling costs on the first well drilled from the top of the Eagle Ford shale formation to basement collectively the “Leases’).

In August 2010, Dyami Energy commenced operations to drill its Initial Test well, theDyami/Matthews #1-H on the Matthews Lease. For the year ended August 31, 2010 the Company incurred $10,049 in exploration expenditures

The Company expects to apply additional capital to further enhance our property interests. As part of the Company’s oil and gas development program, management of the Company anticipates further expenditures to expand its existing portfolio of proved reserves. Amounts expended on future exploration and development is dependent on the nature of future opportunities evaluated by the Company. These expenditures could be funded through cash held by the Company or through cash flow from operations. Any expenditure which exceeds available cash will be required to be funded by additional share capital or debt issued by the Company, or by other means. The Company’s long-term profitability will depend upon its ability to successfully implement its business plan.

The Company’s past primary source of liquidity and capital resources has been loans and advances, cash flow from oil and gas operations and proceeds from the sale of marketable securities and from the issuance of common shares.

RISK AND UNCERTAINTIES

The Company’s producing wells are subject to normal levels of decline and unavoidable changes in operating conditions in facilities operated by third parties. There is an existing and available market for the oil and gas produced from the properties. However, the prices obtained for production are subject to market fluctuations, which are affected by many factors, including supply and demand. Numerous factors beyond our control, which could affect pricing include:

·	volatility in market prices for oil and natural gas;

·	the level of consumer product demand;

·	weather conditions;

·	the foreign supply of oil and gas;

·	the price of foreign imports; and

·	ability to raise financing;

·	reliance on third party operators;

·	ability to find or produce commercial quantities of oil and natural gas;

·	liabilities inherent in oil and natural gas operations;

·	dilution of interests in oil and natural gas properties;

·	general business and economic conditions;

·	the ability to attract and retain skilled staff;

·	uncertainties associated with estimating oil and natural gas reserves;

·	competition for, among other things, financings, acquisitions of reserves, undeveloped lands and skilled personnel; and

·	government regulation and environmental legislation.

The Company cautions that the foregoing list of important factors is not exhaustive. Investors and others who base themselves on the Company’s forward-looking statements should carefully consider the above factors as well as the uncertainties they represent and the risk they entail. The Company also cautions readers not to place undue reliance on these forward-looking statements. Moreover, the forward-looking statements may not be suitable for establishing strategic priorities and objectives, future strategies or actions, financial objectives and projections other than those mentioned above. (For additional risk factors, please see the Company’s Annual Information Form filed on Form 20F).

Financial Instruments and Risk Factors

The Company is exposed to financial risk, in a range of financial instruments including cash, accounts receivable and accounts payable and income taxes payable and loans payable. The Company manages its exposure to financial risks by operating in a manner that minimizes its exposure to the extent practical.

The main financial risks affecting the Company are discussed below.

The fair value of financial instruments at August 31, 2010 and 2009 is summarized as follows:

	2010				2009
	Amount		Fair Value		Amount		Fair Value
Financial assets

Held for trading
Cash and cash equivalents	$	43,776	$	43,776	$	172,905	$	172,905

Loans and receivables
Accounts receivable	$	53,060	$	53,060	$	20,421	$	20,421
Related party receivable	$	1,325	$	1,325		-		-

Financial liabilities
Accounts payable	$	488,741	$	488,741	$	152,984	$	152,984
Income taxes payable	$	-	$	-	$	10,215	$	10,215
Loans payable	$	110,000	$	110,000	$	167,500	$	167,500
Due to shareholder	$	57,500	$	57,500	$	-	$	-
Secured notes payable	$	1,207,527	$	1,145,289	$	-	$	-

Credit Risk

Cash and cash equivalents are held in operating accounts with highly rated Canadian banks and therefore the Company considers these assets to have negligible credit risk.

Receivables from petroleum and natural gas marketers are normally collected on the 25thday of the month following production. The Company historically has not experienced any collection issues with its petroleum and natural gas marketers. Joint venture receivables are typically collected in one to three months of the joint venture bill being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval of significant capital expenditures prior to the expenditure. However, the receivables are from participants in the petroleum and natural gas sector, and collection of the outstanding balances is dependent on industry factors such as commodity price fluctuations, escalating costs and the risk of unsuccessful drilling. In addition, a further risk exists with joint venture partners, such as disagreements, that increase the potential for non-collection. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, the Company does have the ability to withhold information and production from joint venture partners in the event of non-payment.

As at August 31, 2010 the Company’s accounts receivable was $53,060 (2009 $20,421) of which $23,935 is due from government agencies (2009 $14,303), $5,797 is due from a gas marketer (2009 $6,118) $15,391 is due from a joint venture partner (2009 $Nil) and the balance of $7,937 is due from other trade receivables.

The carrying amount of cash and cash equivalents and accounts receivable represents the Company’s maximum credit exposure

As at August 31, 2010 the Company’s accounts receivable is aged as follows:

Current (less than 90 days)	$	36,789
Past due (more than 90 days)		16,271
Total	$	53,060

Liquidity Risk

Liquidity risk includes the risk that, as a result of the Company’s operational liquidity requirements:

The Company will not have sufficient funds to settle their obligations or other transactions on the date they come due;

The Company will be forced to sell financial assets at a value which is less than what they are worth; or

The Company may be unable to settle or recover a financial asset at all.

The following table illustrates the contractual maturities of financial liabilities as at August 31, 2010.

	Payments Due by Period
	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Accounts payable	$	488,741	$	488,741		-		-		-
Loan payable		110,000		110,000		-		-		-
Secured notes payable (1)		1,207,527		186,183	$	1,021,344		-		-
Due to shareholder		57,500		57,500		-		-		-
Asset retirement obligation		3,907		-		-		-	$	3,907
Total contractual obligations	$	1,867,675	$	842,424	$	1,021,344		-	$	3,907

(1)

Translated at current exchange rate.

Market Risk

Market risk represents the risk of loss that may impact our financial position, results of operations, or cash flows due to adverse changes in financial market prices, including interest rate risk, foreign currency exchange rate risk, commodity price risk, and other relevant market or price risks. We do not have activities related to derivative financial instruments or derivative commodity instruments. We hold equity securities which have been written down to $1 on our consolidated balance sheet.

We mitigate these risks to the extent we are able by:

• utilizing competent, professional consultants as support teams to company staff.

• performing careful and thorough geophysical, geological and engineering analyses of each prospect.

• focusing on a limited number of core properties.

(i)	Commodity Price Risk

The Company believes that movement in commodity prices that are reasonably possible over the next twelve month period will not have a significant impact on the Company.

Commodity Price Sensitivity:

	2010						2009
	Increase 10%			Decrease 10%			Increase 10%			Decrease 10%
Revenue	$	115,911		$	94,837		$	61,819		$	50,579
Net loss	$	(678,172	)	$	(699,246	)	$	(323,241	)	$	(334,481	)

(ii)	Foreign Exchange Risk

The Company is exposed to currency risk through the following assets and liabilities denominated in US$ at August 31, 2010 (2009 $Nil):

Financial Instrument	US$
Cash and cash equivalents	$	5,046
Accounts receivable		21,926
Due from related party		1,245
Accounts payable		198,015
Secured notes payable		1,135,000
Total US$	$	1,361,232
CDN dollar equivalent at year end	$	1,448,215

(iii)

Interest Rate Risk

CAPITAL MANAGEMENT

As at August 31, 2010 the Company considers its capital structure to include the following:

	2010			2009
Shareholders’ equity	$	4,239,777		$	265,994
Long term debt		(1,025,251	)		(3,634	)
Working capital deficiency		(744,262	)		(137,372	)
	$	2,470,264		$	124,988

Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Company, is reasonable.

There were no changes in the Company’s capital management during the period ended August 31, 2010.

The Company is not subjected to any externally imposed capital requirements.

SELECTED ANNUAL INFORMATION

The following table reflects the summary of results for the years set out.

For the years ended August 31,	2010			2009			2008
Revenue	$	105,374		$	56,199		$	292
Net loss and comprehensive loss for the year	$	(688,709	)	$	(328,861	)	$	(50,514	)
Loss per share basic and diluted	$	(0.028	)	$	(0.019	)	$	(0.006	)
Assets	$	6,107,452		$	600,327		$	208,486
Long term liabilities	$	1,025,251		$	3,634		$	-

August 31, 2010 - 2009

For the year ended August 31, 2010 revenue increased substantially compare to revenue in the prior period as a result of a full twelve months of operations of 1354166 Alberta compared to six months of operations in 2009. The net loss and comprehensive loss for the year ended August 31, 2010 was $688,709 up $359,848 compared to a net loss of $328,861 in 2009. The increase in loss for fiscal 2010 was primarily attributed to a consulting fee of $326,511 recorded upon the issuance of warrants versus $Nil in the prior period, an increase of $46,074 in professional fees, an increase of $25,613 in head office costs, an increase of $20,241 in transfer and register costs all of which were offset by higher revenues and a reduction of $51,175 in the write down of oil and gas interests. For the year ended August 31, 2010 assets increased significantly up $5,507,125 to $6,107,452 compared to $600,327 for the same period in 2009. The increase in assets is attributed to the acquisition of a 10% working interest in the Matthews lease, Zavala County, Texas and the acquisition of 100% of the membership shares of Dyami Energy.

August 31, 2009-2008

For the year ended August 31, 2009 revenue increased substantially compared to revenue in the comparable period in 2008 as a result of the acquisition of 1354166 Alberta Ltd. The net loss comprehensive loss for the year ended August 31, 2009 was $328,861 compared to a net loss of $50,514 in 2008. The increase in net loss and comprehensive loss for the year ended August 31, 2009 was primarily a result of the write-down of oil and gas interests of $105,805, an increase in professional fees of $80,162, an increase in transfer agent and registrar costs of $20,479, an increase management fees of $6,000 and increase in general and office of $4,897. In addition the Company incurred higher operating costs and depletion for the year ended August 31, 2009. For the year ended August 31, 2009 assets increased by $391,841 to $600,327 compared to assets of $208,486 for the same period in 2008. The increase in assets for the year ended August 31, 2008 was primarily attributed to acquisition of 1354166 Alberta Ltd.

August 31, 2008 – 2007

For the year ended August 31, 2008 revenue decreased compared to revenue in the comparable period in 2007 primarily a result of decreased natural gas sales volumes. The net loss comprehensive loss for the year ended August 31, 2008 was $50,514 compared to a net loss of $39,945 in 2007. The increase in net loss and comprehensive loss for the year ended August 31, 2008 was primarily attributed to an increase in professional fees of $9,635 and an increase in transfer and registrar costs of $2,401. For the year ended August 31, 2008 assets increased by $198,740 to $208,486 compared to assets of $9,746 for the same period in 2007. The increase in assets for the year ended August 31, 2008 was primarily attributed to an increase in cash from the issuance of common shares.

RESULTS OF OPERATIONS

	For the Years Ended
Historical	August 31
Production	2010			2009			2008
Natural gas – mcf/d		68			45			-
Historical Prices
Natural Gas - $/mcf	$	4.22		$	3.42		$	9.23
Royalties costs - $/mcf	$	0.98		$	0.63		$	-
Production costs - $/mcf	$	2.62		$	3.28		$	-
Net back - $/mcf	$	0.62		$	(0.49	)	$	9.23
Operations
Revenue	$	105,374		$	56,199		$	292
Net loss and comprehensive loss for the year	$	(688,709	)	$	(328,861	)	$	(50,514	)
Loss per share	$	(0.028	)	$	(0.019	)	$	( 0.006	)

Production Volume

For the year ended August 31, 2010 average natural gas sales volumes increased to 68 mcf/d compared to 45 mcf/d in the comparable twelve month period in 2009. Total production volume for the year ended August 31, 2010 was 24,950 mcf compared to 16,412 mcf for the same period in 2009. The increase in average sales volume and total production volume for the year ended August 31, 2010 was a result of a full year of operations from 1354166 Alberta versus six months of operations from 1354166 Alberta in 2009.

For the year ended August 31, 2009 average natural gas sales volumes increased to 45mcf/d compared to Nil mcf/d for the comparable period in 2008. The increase in average sales volumes was primarily attributed to the acquisition of 1354166 Alberta. Total production volume for the year ended August 31, 2009 was 16,412 mcf compared to 32 mcf for the comparable period in 2008.

Commodity Prices

For the year ended August 31, 2010 average natural gas prices received per mcf increased by 23% to $4.22 compared to $3.42 for the twelve months ended August 31, 2009. The increase in average natural gas prices received was attributed to higher commodity prices for natural gas for the year ended August 31, 2010.

For the year ended August 31, 2009 average natural gas prices received per mcf decreased 63% to $3.42 compared to $9.23 per mcf for the same period ending August 31, 2008. The decreased in average natural gas prices received was attributed to lower commodity prices for natural gas during the period.

Revenue

Revenue for the year ended August 31, 2010 was up $49,175 to $105,374 compared to $56,199 for the same period in 2009. The increase in revenue for the year ended August 31, 2010 is attributed to a full twelve months of operations of 1354166 Alberta versus six months of operations from 1354166 Alberta for the same period in 2009.

For the year ended August 31, 2009 revenue increased by $55,907 to $56,199 compared to $292 for the same period in 2008. The increase in revenue for the year ended August 31, 2009 was primarily attributed to an increase in production volume as a result of the acquisition of 1354166 Alberta. The results of operations from this acquisition are included effective February 27, 2009. Revenue from the Company’s Haynes property decreased by $202 during the current period compared to revenue of $292 in 2008.

Operating Costs

For the year ended August 31, 2010 operating costs were $102,590 up $19,403 compared to operating costs of $83,187 for the year ended August 31, 2009. The increase in operating costs for the year ended August 31, 2010 was attributed to a full twelve months of operations of 1354166 Alberta. For the year ended August 31, 2009 the Company incurred repair and maintenance costs of $22,111 due to a ruptured pipeline.

For the year ended August 31, 2009 operating costs were $83,187 compared to operating costs of $Nil for the year ended August 31, 2008. In the increase in operating costs for the year ended August 31, 2009 were primarily attributed to the increased operations from the acquisition of 1354166 Alberta Ltd. Also, during the current period the Company incurred higher repair and maintenance costs of $22,111 due to a rupture in a pipeline.

Depletion

Depletion for the year ended August 31, 2010 increased by $11,732 to $38,370 compared to $26,638 for the year ended August 31, 2009. The increase in depletion for the year ended August 31, 2010 was a result of higher production volume attributed to a full twelve months of operations of 1354166 Alberta.

Depletion for the year ended August 31, 2009 increased by $26,614 to $26,638 compared to $24 for the same period in 2008. The increase in depletion for the year ended August 31, 2009 was attributed to increased production volume from the acquisition of 1354166 Alberta Ltd.

Administrative Expenses

Administrative expenses for the year ended August 31, 2010 were $653,153 compared to $276,815 for the year ended August 31, 2009. The increase in expenses during fiscal 2010 was primarily attributed to a consulting fee of $326,511 recorded upon the issuance of warrants versus $Nil in the prior period in 2009, an increase in professional fees of $46,074 to $152,844 compared to $106,770 in 2009, an increase in head office costs of $25,613 to $41,738 compared to $16,125 in 2009, and an increase in transfer and register costs of $20,241 to $45,206 compared to $24,965 in 2009. In addition the Company recorded imputed interest of $5,750 versus $Nil in the prior period in 2009.These higher costs in 2010 were partially offset by a reduction in the write down of oil and gas interests of $51,175 to $54,630 when compared to $105,805 during fiscal 2009 and a reduction of general and office costs of $2,676 to $2,474 when compared to $5,150 in fiscal 2009. Higher administrative expenses during the fiscal 2010 are attributed to increased operations and the acquisition of Dyami Energy.

Administrative expenses for the year ended August 31, 2009 were $276,815 compared to $50,782 for the year ended August 31, 2008. The increase in expenses during fiscal 2009 was primarily attributed to a write down of oil and gas interests in the amount of $105,805, compared to $528 in the prior period in 2008, an increase in professional fees of $80,162 to $106,770 compared to $26,608 in 2008, an increase in transfer agent and registrar costs of $20,479 to 24,965 compared to $4,486 in 2008, an increase in management fees of $6,000 to $18,000 compared to $12,000 in the prior period and an increase in general and office costs of $4,897 to $5,150 compared to $253 for the year ended August 31, 2008. Higher administrative expenses during the fiscal 2009 were partially attributed to the Company becoming a reporting issuer with the United States Securities and Exchange Commission and increased operations resulting from the acquisition of 1354166 Alberta Ltd. In fiscal 2008 the Company recorded an expense recovery of $7,718 compared to $Nil in the current fiscal year 2009.

Interest Income

For the year ended August 31, 2010 interest income was $30 compared to$1,580 for the comparable period in 2009. The decrease in interest income during 2010 is attributed to the decrease in cash held by the Company.

For the year ended August 31, 2009 interest income was $1,580 compared to $Nil for the comparable period in 2008.

Net loss and comprehensive loss for the period

Net loss and comprehensive loss for year ended August 31, 2010 was $688,709 up $359,848 or 109% compared to a net loss of $328,861 for year ended August 31, 2009. The increase in net loss and comprehensive loss for the year ended August 31, 2010 was primarily related to increased administrative costs which included a consulting fee of $326,511 recorded upon the issuance of warrants.

Net loss and comprehensive loss for year ended August 31, 2009 was $328,861 up 551% compared to a net loss of $50,514 for the prior period in 2008. The increase in net loss and comprehensive loss for the year ended August 31, 2009 was related to an increase in operating costs and depletion, increased administrative costs as well as a write-down of oil and gas interests.

Net loss per share

The net loss per share for the year ended August 31, 2010 was $0.028 compared to a net loss per share of $0.019 for the same twelve month period in 2009.

The net loss per share for the year ended August 31, 2009 was $0.019 compared to a net loss per share of $0.006 for the same period in 2008.

SUMMARY OF QUARTERLY RESULTS

The following tables reflect the summary of quarterly results for the periods set out.

	2010			2010			2010			2009
For the quarter ending	August 31			May 31			February 28			November 30
Revenue	$	23,363		$	19,291		$	36,461		$	26,259
Net loss and comprehensive loss for the period	$	(496,520	)	$	(75,144	)	$	(36,746	)	$	(80,299	)
Loss per share	$	(0.020	)	$	(0.003	)	$	(0.002	)	$	(0.014	)

Revenue for the four quarters in 2010 fluctuated as a result of changes in production volume and commodity prices received. The increase in net loss and comprehensive loss for the quarter ending August 31, 2010 was primarily attributed to the Company recording a consulting fee of $326,511 upon the issuance of warrants and higher administrative expenses due increased operations and the acquisition of Dyami Energy. During the fourth quarter the Company incurred an increase in professional fees for year-end audit costs and costs associated with the evaluation of the Company’s reserves.

	2009			2009			2009			2008
For the quarter ending	August 31			May 31			February 28			November 30
Revenue	$	23,078		$	32,796		$	260		$	65
Net loss and comprehensive loss for the period	$	(249,967	)	$	(62,554	)	$	(9,721	)	$	(6,619	)
Loss per share	$	(0.014	)	$	(0.005	)	$	(0.001	)	$	(0.001	)

Revenue for the quarters for the May and August 2009 increased as a result of the acquisition of 1354166 Alberta Ltd. The increase in net loss and comprehensive loss for the quarter ending August 31, 2009 was primarily attributed to a write down of oil and gas interests, an increase in professional fees including year-end audit costs, transfer and registrar costs, office and general expenses, management fees and head office services, and costs associated with the evaluation of the Company’s reserves.

FOURTH QUARTER RESULTS

Production Volume

For the three months ended August 31, 2010 average natural gas sales volumes were 68 mcf/d compared to 84 mcf/d for the comparable period in 2009. Total production volume for the three months ended August 31, 2010 was 6,227 mcf compared to 7,728 mcf for the same three month period ending August 31, 2009. The decrease in production volume in 2010 is primarily related to natural production declines from the Company’s Botha, Alberta gas unit.

Commodity Prices

For the three months ended August 31, 2010 average natural gas sales prices received per mcf increased to $3.75 compared to $2.99 for the three month period ended August 31, 2009.

Revenue

Revenue increased by $286 to $23,363 for the three months ending August 31, 2010 compared to $23,078 for the three months ending August 31, 2009. Higher commodity prices received was responsible for the increase in revenue.

Operating Costs

Operating costs were $50,102for the three months ending August 31, 2010 representing a slight decrease compared to $51,876 for the three months ending August 31, 2009.

Depletion

Depletion for the three months ending August 31, 2010 was $12,526 compared to depletion of $18,374 for the three months ending August 31, 2009. The decrease in depletion for the three months ending August 31, 2010 was a result of lower production volume.

Administrative Expenses

For the three months ending August 31, 2010 administrative expenditures were up $274,393 to $477,330 compared to $202,937 for the same period in 2009. The primary increase in administrative expenses for the three months ending August 31, 2010 relate to expense consulting fee of $326,511 recorded upon the issuance of warrants versus $Nil for the three month period in 2009 partially offset by a write-down of oil and gas interest of $54,630 compared to a write-down of oil and gas interests in the prior three month period in 2009 of $105,805.

Interest

For the three months ending August 31, 2010 interest income was $Nil compared to interest income of $142 during the comparable three month period in 2009.

Net loss and comprehensive loss for the period

Net loss and comprehensive loss for the three months ending August 31, 2010 was $496,520 up $246,553 compared to $249,967 for the prior period in 2009.

Loss per share

The loss per share for the three months ending August 31, 2009 was $0.020 compared to $0.014 for the comparative same three month period in 2009.

CAPITAL EXPENDITURES

For the year ended August 31, 2010, the Company incurred costs of approximately $222,823 on its oil and gas interest in the Matthews Lease, Zavala County, Texas, USA. Of this amount $212,780 was incurred to acquire the interest and $10,046 was expended on drilling costs.

The Company expects that its capital expenditures will increase in future reporting periods as the Company incurs capital expenditures to exploration and develop its oil and gas properties.

FINANCING ACTIVITIES

During the year ended August 31, 2010 the Company received $147,000 for the exercise of 2,100,000 common share purchase warrants at $0.07 per share. In addition, the Company issued 333,333 compensation warrants entitling the holder to purchase one common share at US$1.00 expiring December 11, 2011 and 166,667 compensation warrants entitling the holder to purchase one common share at US $1.50 expiring June 10, 2012.

LIQUIDITY AND CAPITAL RESOURCES

Cash as of August 31, 2010 was $43,776 compared to cash of $172,905 at August 31, 2009. During the year ended August 31, 2009 the Company received proceeds from the exercise of warrants of $147,000 and cash of $5,369 acquired on the acquisition of Dyami Energy. During the year ended August 31, 2010 the primary use of funds was related to general and administrative expenditures. The Company paid a cash payment of $$26,597 related to acquiring a 10% working interest in Zavala County, Texas and incurred exploration expenditures of $10,046. In addition, the Company paid income tax of $10,215. The Company’s working capital deficiency at August 31, 2010 is $744,262 compared to a working capital deficiency of $$137,372 at August 31, 2009.

Our current assets of $98,162 as at August 31, 2010 ($193,327 as of August 31, 2009) include the following items: cash $43,776 ($172,905 as of August 31, 2009); marketable securities $1 ($1 as of August 31, 2009); accounts receivable- $53,060 ($20,421 as of August 31, 2009) and due from related party $1,325 ($Nil as of August 31, 2009).

Our current liabilities of $842,424 as of August 31, 2010 ($330,699 as of August 31, 2009) include the following items: accounts payable of $488,741 ($152,984 as of August 31, 2009); income taxes payable of $Nil ($10,215 as of August 31, 2009); and due to shareholder and loan payable of $167,500 ($167,500 as of August 31, 2009).

At August 31, 2010 the Company had outstanding 2,575,000 common share purchase warrants exercisable at $0.20 per share, 10,760,820 common share purchase warrants exercisable at $0.07 per share, 333,333 common share purchase warrants exercisable at US$1.00 per share, 166,667 common share purchase warrants exercisable at US$1.50 per share and 1,709,233 common share purchase warrants exercisable at US$1.00 per share. If any of these common share purchase warrants are exercised it would generate additional capital for us.

In August 2010, Dyami Energy commenced operations to drill its 85% working interest Initial Test well, the Dyami/Matthews #1-H on the Matthews Lease, Texas. Net estimated costs for drilling and the initial completion of the well are approximately US$1,700,000. Subsequent to the year end the Company received CDN $77,000 upon the exercise of warrants and raised debt financing in the amount of US $1,660,000 and CDN $149,000.

Management of the Company recognizes that cash flow from operations is not sufficient to expand its oil and gas operations and reserves or meet its working capital requirements. The Company has liquidity risk which necessitates the Company to obtain debt financing, enter into joint venture arrangements, or raise equity. There is no assurance the Company will be able to obtain the necessary financing in a timely manner.

The Company’s past primary source of liquidity and capital resources has been loans and advances, cash flow from oil and gas operations, proceeds from the sale of marketable securities and the issuance of common shares.

If the Company issued additional common shares from treasury it would cause the current shareholders of the Company dilution.

OFF-BALANCE SHEET ARRANGEMENTS

The Company has no off-balance sheet arrangements.

SEGMENTED INFORMATION

Geographic information:

The following is segmented information as at and for the year ended August 31, 2010:

	Year ended August 31, 2010					As at August 31, 2010
	Interest and other income		Net income (loss)			Oil and gas interests		Other assets
Canada	$	30	$	(688,709	)	$	314,000	$	68,141
United States		-		-			5,695,290		30,021
Total	$	30	$	(688,709	)	$	6,009,290	$	98,162

The following is segmented information as at and for the year ended August 31, 2009:

	Year ended August 31, 2009					As at August 31, 2009
	Interest and other income		Net income (loss)			Oil and gas interests		Other assets
Canada	$	1,580	$	(328,861	)	$	407,000	$	193,327
United States		-		-			-		-
Total	$	1,580	$	(328,861	)	$	407,000	$	193,327

SEASONALITY AND TREND INFORMATION

RELATED PARTY TRANSACTIONS AND BALANCES

		2010				2009				2008
Management fees to the former President and Director of the Company		$	24,000			$	18,000			$	12,000

The following balances owing to an individual related to the Company are included in accounts payable and advances payable and are unsecured, non-interest bearing and due on demand:

		2010				2009				2008
Management fees to the former President and Director of the Company		$	-			$	14,700			$	6,000

Commencing May 1, 2009 the Company increased the management fee from $1,000 to $2,500 per month to the former President of the Company.

At August 31, 2010 the Company has a due from related party receivable from Source Re-Work Program Inc., (“Source”) in the amount of $1,325 (US$1,245) for expenditures relating to the Matthews Lease. In addition, the Company has a secured note payable to Source in the amount of $186,183 (US$175,000). Eric Johnson is the President of Source, the Vice President of Operations for Dyami Energy and a shareholder of the Company.

The loan payable in the amount of $57,500 is due to a shareholder and is unsecured, non-interest bearing and repayable on demand. Interest was imputed at a rate of 10% per annum and imputed interest of $5,750 was included in contributed surplus. On February 27, 2009, the Company entered into an agreement to settle $62,500 of the $120,000 loan through the issuance of a total of 1,250,000 units at an attributed value of $0.05 per unit. Each unit was comprised of one common share and one common share purchase warrant. Each warrant is exercisable until February 27, 2014 to purchase one common share at a purchase price of $0.07 per share.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The Company has development commitments on its Mathews Lease and Murphy Lease in order to keep the leases in good standing.

(a)

On or before August 23, 2010 Dyami Energy shall commence operations to drill an Initial Test Well on Matthews Lease to a depth of not less than 3,000 feet below the surface or to the base of the San Miguel “D” formation.

(b)

On or before July 8, 2011, Dyami Energy shall commence operations to perform an injection operation (by use of steam, nitrogen or other ) in the San Miguel formation on the Initial Test Well or any other well located on the Matthews Lease or, all of the interest acquired by Dyami Energy in the Matthews Lease shall be forfeited without further consideration;

(c)

On or before January 1, 2011, Dyami Energy shall commence a horizontal well to test the Eagle Ford Shale formation with a projected lateral length of not less than 2,500 feet (the “Second Test Well”).

(d)

Dyami Energy’s 15% working interest partner in the Matthews Lease has an obligation to participate in each of the operations provided for in (a), (b) and (c) above and if the partner fails to bear its share of the costs of such operations, the partner shall forfeit its interest in and to the well and the applicable spacing unit.

Dyami Energy is the designated operator under the provisions of the Matthews Lease Operating Agreement.

Murphy Lease, Zavala County

to commence drilling (spud) a well to a depth to sufficiently test the Eagle Ford Shale formation by August 3, 2010 or pay a lease delay payment of US $25 per acre or US$65,925 in the aggregate (paid July 28, 2010) to extend the period to commence drilling for 180 days to January 30, 2011 or Dyami Energy shall be required to release and re-assign its rights in the Murphy Lease.

During the development of the Murphy Lease, Dyami Energy is required to commence drilling a well within 180 days, or otherwise release and re-assign its rights to the Murphy Lease, but excluding the unit acreage area it has already drilled and earned. Likewise, if a producing well ceases to produce, and such well is not timely re-worked or re-drilled within a six month period, Dyami Energy shall also be required to release and re-assign its rights to the Murphy Lease.

Three years after the cessation of continuous drilling, all rights below the deepest producing horizon in each unit then being held by production, shall be released and re-assigned to the Lessor, unless the drilling of another well has been proposed on said unit, approved in writing by Lessor, and timely commenced.

Loan Payable

The loan payable in the amount of $110,000 is due to an arms’ length party and is unsecured, non-interest bearing and repayable on demand.

Secured Notes Payable

Current

On June 14, 2014 the Eagleford entered into an agreement to acquire a 10% working interest before payout and a 7.5% working interest after payout in the Matthews Lease (the “Interest”). As consideration for the Interest the Company paid on closing August 31, 2010 $212,780 (US$200,000), satisfied by $26,597 (US$25,000) paid in cash on closing and $186,183 (US$175,000), 5% secured promissory note in favour of Source Re-Work Program Inc. US$100,000 of principal together with accrued interest is due and payable on February 28, 2011 and US$75,000 of principal together with accrued interest is due and payable on August 31, 2011. The Company may, in its sole discretion, prepay any portion of the principal amount. The note is secured by the Interest. At August 31, 2010 the Interest is carried on the books of the Company at $222,826.

Long Term

On August 31, 2010 Eagleford assumed $1,201,344 (US$960,000) of Dyami Energy debt by way of a secured promissory note payable to Benchmark Enterprises LLC (the “Secured Note”). The Secured Note bears interest at 6% per annum, is secured by the Matthews and Murphy Leases and is payable on December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000. The Company may, in its sole discretion, prepay any portion of the principal amount. At August 31, 2010 the Matthews Lease - and the Murphy Lease are carried on the books of the Company at $5,209,330 and $263,134 respectively.

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Going Concern

Principles of Consolidation

On November 12, 2009, the Company’s wholly owned subsidiary 1406768 Ontario Inc. changed its name to Eagleford Energy Inc. On November 30, 2009 the Company amalgamated with Eagleford Energy Inc. and upon the amalgamation the entity's new name is Eagleford Energy Inc. The consolidated financial statements include the accounts of Eagleford, the legal parent, together with its wholly-owned subsidiaries, 1354166 Alberta Ltd. an Alberta operating company and Dyami Energy LLC a Texas limited liability exploration stage company. All inter-company accounts transactions have been eliminated on consolidation.

Oil and Gas Interests

The Company follows the successful efforts method of accounting for its oil and gas interest. Under this method, costs related to the acquisition, exploration, and development of oil and gas interests are capitalized. The Company carries as an asset, exploratory well costs if a) the well found a sufficient quantity of reserves to justify its completion as a producing well and b) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If a property is not productive or commercially viable, its costs are written off to operations. Impairment of non-producing properties is assessed based on management's expectations of the properties.

Depletion and Depreciation

Depletion of petroleum and natural gas properties and depreciation of production equipment are calculated on the unit of production basis based on:

(a) total estimated proved reserves calculated in accordance with National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities;

(b) total capitalized costs, excluding undeveloped lands and unproved costs, plus estimated future development costs of proved undeveloped reserves; and

Impairment Test

Revenue Recognition

Revenues associated with the sale of crude oil and natural gas are recorded when the title passes to the customer. The customer has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the Company provide the customer with a right of return.

Royalties

As is normal to the industry, the Company's future production is subject to crown royalties. These amounts are reported net of related tax credits.

Transportation

Costs paid by the Company for the transportation of natural gas, crude oil and natural gas liquids from the wellhead to the point of title transfer are recognized when the transportation is provided.

Joint venture operations

Substantially all of the Company's oil and gas activities are conducted jointly with others. These financial statements reflect only the Company's proportionate interest in such activities.

Environmental and Site Restoration Costs

Foreign Currencies

Assets and liabilities denominated in currencies other than Canadian dollars are translated at exchange rates in effect at the balance sheet date. Revenue and expense items are translated at the average rates of exchange for the year. Exchange gains and losses are included in the determination of net income for the year

Marketable Securities

Financial Instruments

All financial instruments are recorded initially at estimated fair value on the balance sheet and classified into one of five categories: held for trading, held to maturity, available for sale, loans and receivables and other liabilities. Cash and cash equivalents, and investments are classified as held for trading and measured at estimated fair value. Accounts receivable and due from related party are classified as loans and receivables and measured at amortized cost. Accounts payable, loan payable, Due to shareholder and Secured notes payable are classified as other liabilities and measured at amortized cost.

The estimated fair value of cash and cash equivalents, accounts receivable and accounts payable approximate their carrying amounts due to their short terms to maturity.

Cash and cash equivalents

Cash and cash equivalents include bank accounts, trust accounts, and term deposits with maturities of less than three months.

Accounting Estimates

Income Taxes

Non-Monetary Transactions

Stock-Based Compensation

Loss Per Share

Change in Accounting Policy and Future Accounting Changes

(a) EIC Credit Risk

(b) Financial Instruments – Disclosures

In June 2009, the Canadian Accounting Standards Board (“AcSB”) issued the amendments to CICA Handbook Section 3862, Financial Instruments - Disclosures, which reflect the corresponding amendments made by the International Accounting Standards Board to IFRS 7, Financial Instruments: Disclosures, in March 2009. The amendments require that all financial instruments measured at fair value be presented into one of the three hierarchy levels set forth below for disclosure purposes (see note 5). Each level is based on the transparency of the inputs used to measure the fair value of assets and liabilities.

(i) Level 1: Inputs are unadjusted quoted prices of identical instruments in active markets.

(ii) Level 2: Valuation models which utilize predominately observable market inputs.

(iii) Level 3: Valuation models which utilize predominately non-observable market inputs.

The classification of a financial instrument in the hierarchy is based upon the lowest level of input that is significant to the measurement of fair value. The amendments to Section 3862 also require additional disclosure relating to the liquidity risk associated with financial instruments (see note 14). The amendments improve disclosure of financial instruments specifically as it relates to fair value measurements and liquidity risk. The adoption of the amendments did not impact the Company’s financial position or results of operations.

(d) General Standard of Financial Statement Presentation

(e) Future Accounting Changes

Sections 1601 and 1602 together replace 1600 – Consolidated Financial Statements. Section 1601, establishes standards for the preparation of consolidated financial statements. Section 1601 applies to interim and annual consolidated financial statements relating to fiscal years beginning on or after January 1, 2011.

RECONCILIATION TO ACCOUNTING PRINCIPLES GENERALLY ACCEPTED IN THE UNITED STATES

The Company's accounting policies do not differ materially from accounting principles generally accepted in the United States ("US GAAP") except for the following:

Oil and Gas Interests

If US GAAP was followed, the effect on the consolidated balance sheet would be as follows:

	2010			2009
Total assets according to Canadian GAAP	$	6,107,452		$	600,327
Additional impairment of oil and gas interests		(50,000	)		(73,638	)
Total assets according to US GAAP	$	6,057,452		$	526,689

	2010			2009
Total shareholders’ equity according to Canadian GAAP		4,239,777		$	265,994
Deficit adjustment per US GAAP
Additional impairment of oil and gas interests		(50,000	)		(73,638	)
Total shareholders’ equity according to US GAAP	$	4,189,777		$	192,356

If US GAAP was followed, the effect on the consolidated statements of loss and comprehensive loss would be as follows:

	2010			2009			2008
Net loss, comprehensive loss according to Canadian GAAP		688,709		$	328,861		$	50,514
Add: Additional impairment of oil and gas interests		50,000			73,638			-
Net loss, comprehensive loss according to US GAAP	$	738,709		$	402,499		$	50,514
Loss per share, basic and diluted	$	(0.030	)	$	(0.023	)	$	(0.006	)
Shares used in the computation of loss per share		24,687,130			17,646,295			7,955,482

DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

Adoption of New Accounting Policies

Financial Accounting Standards Board’s Codification of US GAAP

Business combinations

Non-controlling interests

Derivative Instruments and Hedging Activities

Subsequent events

The Fair Value Measurement of Liabilities

In August 2009, the FASB issued ASU 2009-05 “Measuring Liabilities at Fair Value” (“ASU 2009- 05”), which provides amendments to Subtopic 820-10 “Fair Value Measurements and Disclosures — Overall” and is effective prospectively for interim periods beginning after October 1, 2009 for the Company. ASU 2009-05 provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one of the valuation techniques that uses (a) the quoted price of the identical liability when traded as asset; (b) quoted prices for similar liabilities when traded as assets; or another valuation technique that is consistent with the principles of Topic 820 “Fair Value Measurements and Disclosures”. Therefore, the fair value of the liability shall reflect nonperformance risk, including but not limited to a reporting entity’s own credit risk. ASU 2009-05 also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of liability. The adoption of ASU 2009-05 will not have a material impact on the Company’s consolidated financial statements.

Equity method investees

Future U.S. Accounting Policy Changes

Accounting of Transfers of Financial Assets an amendment of FASB No. 140

Variable interest entities an Amendment to FASB Interpretation No.46(R)

INTERNATIONAL FINANCIAL REPORTING STANDARDS

Transition to International Financial Reporting Standards

In February 2008, the Accounting Standards Board confirmed that the transition date to International Financial Reporting Standards (“IFRS”) from Canadian GAAP will be January 1, 2011 for publicly accountable enterprises. The Company will issue its initial unaudited consolidated financial statements under IFRS including comparative information for the quarter ending February 28, 2011.

The transition from current Canadian GAAP to IFRS is a significant undertaking that may materially affect the Company's reported financial position and results of operations. The Company is assessing the potential impacts of this changeover and has commenced the development of an IFRS implementation plan to prepare for this transition, which will include project structure and governance, resourcing and training, analysis of key GAAP differences and a phased plan to assess accounting policies under IFRS as well as potential exemptions to the initial adoption of IFRS as permitted by IFRS Statement 1.

The table below summarizes the key elements of the transition plan and the expected timing of activities related to the Company’s transition:

Initial analysis of key areas for which changes to accounting policies may be required		Completed

Detailed analysis of all relevant IFRS requirements and identification of area requiring accounting policy changes or those with accounting policy alternatives		Throughout fiscal 2010 and 2011

Assessment of first-time adoption (IFRS 1) requirements and alternatives		Throughout fiscal 2010 and 2011

Final determination of changes to accounting policies and choices to be made with respect to first-time adoption alternatives		Q2, Q3 (August 31, 2011)

Resolution of the accounting policy change implications on information technology, internal controls and contractual arrangements		Q2, Q3 (August 31, 2011)

Management and employee training		Throughout the transition period

Quantification of the Financial Statement impact of changes in accounting policies		Throughout fiscal 2011

The Company is in the process of analyzing key areas where changes to current accounting policies may be required. While an analysis will be required for all accounting policies, the initial key areas of assessment include:

• Property, Plant and Equipment

Pre-exploration costs

Exploration and evaluation costs

Depletion, depreciation and amortization

• Impairment testing

• Decommissioning liabilities (known as “asset retirement obligations” under Canadian GAAP)

• Stock-based compensation

• Income taxes

Each of these significant impact areas is discussed in more detail below.

Property, Plant and Equipment

IFRS and Canadian GAAP contain the same basic principles for property, plant, and equipment; however, there are some differences. Specifically, IFRS requires property, plant and equipment to be measured at cost in accordance with IFRS, breaking down material items into components and amortizing each one separately. In addition, unlike Canadian GAAP, IFRS permits property, plant and equipment to be measured at fair value or amortized cost. The Company’s initial analysis is that no further componentization was necessary in property, plant, and equipment.

In moving to IFRS, the Company will be required to adopt different accounting policies for pre-exploration activities, exploration and evaluation costs and depletion, depreciation and accretion.

Pre-exploration costs are costs incurred before the Company obtains the legal right to explore an area. Under Canadian GAAP, these costs are capitalized, while under IFRS, these costs must be expensed. At this time, the Company does not anticipate that this accounting policy difference will have a significant impact on the financial statements.

During the Exploration and Evaluation phase, the Company capitalizes costs incurred for these projects under Canadian GAAP. Under IFRS, the Corporation has the alternative to either continue capitalizing these costs until technical feasibility and commercial viability of the project is determined, or to expense these costs as incurred. The Company does not currently have any Exploration and Evaluation assets.

Under Canadian GAAP, the Company calculates its depletion, depreciation and amortization rate at the country cost centre level. Under IFRS, this rate will be calculated at a lower unit of account level. At this time, the Company has not finalized its policy in this regard, and therefore the impact of this difference in accounting policy is not reasonably determinable.

Impairment Testing

For the first step of the impairment test under Canadian GAAP, future cash flows are not discounted. Under IFRS, the future cash flows are discounted. In addition, for Property, Plant and Equipment, impairment testing is currently performed at the country cost centre level, while under IFRS, it will be performed at a lower level, referred to as a cash-generating unit. The impairment calculations will be performed using either total proved or proved plus probable reserves. Canadian GAAP prohibits reversal of impairment losses. Under IFRS if the conditions giving rise to impairment have reversed, impairment losses previously recorded would be partially or fully reversed to eliminate write-downs recorded. The Company expects to adopt these changes in accounting policy prospectively. At this time, the impact of accounting policy differences related to impairment testing is not reasonably determinable.

Asset Retirement Obligation

Under Canadian GAAP, the Company recognizes a liability for the estimated fair value of the future retirement obligations associated with Property, Plant and Equipment. The fair value is capitalized and amortized over the same period as the underlying asset. The Company estimates the liability based on the estimated costs to abandon and reclaim its net ownership interest in wells and facilities, including an estimate for the timing of the costs to be incurred in future periods. These cash outflows are discounted using a credit-adjusted rate. Changes in the net present value of the future retirement obligation are expensed through accretion as part of depletion, depreciation and accretion. Under IFRS, these liabilities are known as “decommissioning liabilities” and are included in the scope of IAS 37 Provisions, Contingent Liabilities and Contingent Assets. Decommissioning liabilities are calculated at each reporting period by estimating the risk-adjusted future cash outflows which are discounted using a risk-free rate. Changes in the net present value of the future retirement obligation are expensed through accretion as part of depletion, depreciation and accretion. Due to the change in the discount rate from a credit-adjusted rate to a risk-free rate, the Company expects there will be an increase in the value of the decommissioning liability under IFRS as compared to Canadian GAAP.

Stock-based Compensation

IFRS 2 Share-Based Payments requires the expense related to share-based payments to be recognized as the options vest; that is, for options that vest over a period of time, each tranche must be treated as a separate option grant which accelerates the expense recognition in comparison to Canadian GAAP which allows the expense to be recognized on a straight-line basis over the period the options vest. While the carrying value for each reporting period will be different under IFRS, the cumulative expense recognized over the life of the instrument under both methods will be the same. Going forward under IFRS, stock-based compensation is expected to be higher because the graded vesting requirements of IFRS result in accelerated expense recognition.

Accounting for Income Tax

In transitioning to IFRS, the carrying amount of the Company’s tax balances will be directly impacted by the tax effects resulting from changes required by the above IFRS accounting policy differences. Due to the recent withdrawal of the exposure draft on IAS 12 Income Taxes in November 2009, the Company is still determining the impact of the revised standard on its IFRS transition. Therefore, at this time the income tax impacts of the differences are not reasonably determinable.

As the analysis of each of the key areas progress, other elements of the Company’s IFRS transition plan will also be addressed, including the implication of changes to accounting policies and processes, financial statement note disclosures on information technology, internal controls, contractual arrangements and employee training.

Changes to IFRS Accounting Standards

The Company’s analysis of accounting policy differences specifically considers the current IFRS standards that are in effect. The Corporation will continue to monitor any new or amended accounting standards that are issued by the IASB.

Internal Controls over Financial Reporting

The Company does not anticipate that the transition to IFRS will have a significant impact on either its internal controls over financial reporting, or its disclosure controls and procedures. As the review of the Company’s accounting policies is completed, an assessment will be made to determine changes necessary for internal controls over financial reporting. This will be an ongoing process throughout fiscal 2010 and 2011 to ensure that all changes in accounting policies include the appropriate additional controls and procedures for future IFRS reporting requirements.

Education and Training

The Company will involve its management and board of directors in the IFRS transition throughout fiscal 2010 and 2011.

Impacts to our Business

The Company does not expect that the adoption of IFRS in 2011 will have a significant impact or influence on its business activities.

OTHER MD&A REQUIREMENTS

(a) Additional Information

Additional information relating to the Company may be obtained or viewed from the System for Electronic Data Analysis and Retrieval (SEDAR) at www.sedar.com and via the Electronic Data Gathering Analysis and Retrieval System (EDGAR) at www.sec.gov.

(b) Share Capital and Contributed Surplus

Authorized:

Unlimited number of common shares

Unlimited non-participating, non-dividend paying, voting redeemable preference shares

Issued:

Common Shares	Number		Amount
Balance at August 31, 2007		6,396,739	$	166,291
Private Placement (note a)		2,575,000		151,313
Debt conversion (note b)		1,500,000		150,000
Balance at August 31, 2008		10,471,739		467,604
February 5, 2009 private placement (note c)		2,600,000		67,600
February 25, 2009 private placement (note d)		1,000,256		26,007
February 27, 2009 acquisition (note e)		8,910,564		231,675
February 27, 2009 debt settlement (note f)		1,250,000		32,500
Balance at August 31, 2009		24,232,559		825,386
Exercise of warrants (note g)		2,100,000		197,400
August 31, 2010 acquisition, net of transaction costs (note h)		3,418,467		2,794,398
Balance August 31, 2010		29,751,026	$	3,817,184

(b) On April 14, 2008 the Company entered into agreements to convert debt in the amount of $150,000 through the issuance of 1,500,000 shares at an attributed value of $0.10 per share.

The following table summarizes the changes in warrants for the years then ended:

	2010					2009				2008
Warrants	Number of Warrants			Weighted Average Price		Number of Warrants		Weighted Average Price		Number of Warrants		Weighted Average Price
Outstanding beginning of year		16,335,820		$	0.09		2,575,000	$	0.20		-		-
Issued		2,209,233			1.04		13,760,820		0.07		2,575,000	$	0.20
Exercised		(2,100,000	)		0.07		-		-		-		-
Outstanding end of year		16,445,053		$	0.22		16,335,820	$	0.09		2,575,000	$	0.20

The following table summarizes the outstanding warrants as at August 31, 2010:

Number of Warrants		Note	Exercise Price		Expiry Date	Warrant Value ($)
	2,575,000	(note a)	$	0.20	April 14, 2011	$	100,875
	500,000	(note c, g)	$	0.07	February 5, 2014		12,000
	1,000,256	(note d)	$	0.07	February 25, 2014		24,006
	10,160,564	(note e, f)	$	0.07	February 27, 2014		243,853
	333,333	(note i)	US$	1.00	December 10, 2011		214,372
	166,667	(note i)	US$	1.50	June 10, 2012		112,139
	1,709,233	(note h)	US$	1.00	August 31, 2014		1,388,833
	16,445,053					$	2,096,078

The fair value of the warrants issued during the year ended August 31, 2010 and 2009 were estimated on the date of issue using the Black-Scholes pricing model with the following assumptions:

Black-Scholes Assumptions used	2010
Risk-free interest rate		3	%
Expected volatility		234	%
Expected life (years)		4
Dividend yield		0	%
Fair value of the warrants issued on June 10, 2010	$	0.65
Fair value of the warrants issued on August 31, 2010	$	0.81

Black-Scholes Assumptions used	2009
Risk-free interest rate		3	%
Expected volatility		170	%
Expected life (years)		4
Dividend yield		0	%
Fair value of the warrants issued on February 5, 2009	$	0.05
Fair Value of the warrants issued on February 25, 2009	$	0.05
Fair Value of the warrants issued on February 27, 2009	$	0.05

Black-Scholes Assumptions used	2008
Risk-free interest rate		3	%
Expected volatility		129	%
Expected life (years)		3
Dividend yield		0	%
Fair value of the warrants issued on April 14, 2008	$	0.06

Weighted Average Shares Outstanding	2010		2009		2008
Weighted average shares outstanding, basic		24,687,130		17,646,295		7,955,482
Dilutive effect of warrants		16,008,996		9,749,557		1,009,467
Weighted average shares outstanding, diluted		40,696,126		27,395,852		8,964,949

Stock Option Plan

Contributed Surplus

Contributed surplus transactions for the respective years are as follows:

	Amount
Balance, August 31, 2007	$	-
Debt Conversion		38,000
Balance, August 31, 2008 and 2009		38,000
Imputed interest (see Note 10)		5,750
Balance, August 31, 2010	$	43,750

In connection with National Instrument 52-109 (Certificate of Disclosure in Issuer’s Annual and Interim Filings) (“NI 52-109”) the Chief Executive Officer and Chief Financial Officer of the Company have filed a Venture Issuer Basic Certificate with respect to the financial information contained in the Audited Consolidated Financial Statements for the year ended August 31, 2010 and this accompanying MD&A. In contrast to the full certificate under NI 52-109, the Venture Issuer Basic Certificate does not include representations relating to the establishment and maintenance of disclosure controls and procedures and internal control over financial reporting, as defined in NI 52-109. For further information the reader should refer to the Venture Issuer Basic Certificates filed by the Company with the Annual Filings on SEDAR at www.sedar.com.

SUBSEQUENT EVENTS

On September 17, 2010, 500,000 common share purchase warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $35,000.

On September 24, 2010 600,000 common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $42,000.