December 29, 2011 - 6-K: Report of foreign issuer [Rules 13a-16 and 15d-16]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN PRIVATE ISSUER

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

THE SECURITIES EXCHANGE ACT OF 1934

For the month of December, 2011

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 if the registrant submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ¨

Indicate by check mark if the registrant submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ¨

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, 2011, 2010 and 2009 as filed on SEDAR on December 23, 2011.

2. Eagleford Energy Inc. Management’s Discussion and Analysis of Financial Condition and Operating Results for the year ended August 31, 2011 as filed on SEDAR on December 23, 2011

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 29, 2011	EAGLEFORD ENERGY INC.

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

Item 1

	Consolidated Financial Statements

	For the years ended August 31, 2011, 2010 and 2009

	(Expressed in Canadian Dollars)

Consolidated Financial Statements

For the years ended August 31, 2011, 2010 and 2009

(Expressed in Canadian Dollars)

Contents

Management Report

Independent Auditors' Report

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

Consolidated Financial Statements

Consolidated Balance Sheets	2

Consolidated Statements of Operations Comprehensive Loss and Other Accumulated Comprehensive Loss	3

Consolidated Statements of Cash Flows	4

Consolidated Statements of Shareholders’ Equity	5

Notes to Consolidated Financial Statements	6 - 34

MANAGEMENT REPORT

To the Shareholders of Eagleford Energy Inc.:

Management is responsible for the preparation and presentation of the accompanying consolidated financial statements, including responsibility for significant accounting judgments and estimates in accordance with Canadian generally accepted accounting principles. This responsibility includes selecting appropriate accounting principles and methods, and making decisions affecting the measurement of transactions in which objective judgment is required.

In discharging its responsibilities for the integrity and fairness of the financial statements, management designs and maintains the necessary accounting systems and related internal controls to provide reasonable assurance that transactions are authorized, assets are safeguarded and financial records are properly maintained to provide reliable information for the preparation of financial statements.

The Board of Directors is responsible for overseeing management in the performance of its financial reporting responsibilities. The Board fulfils these responsibilities by reviewing the financial information prepared by management and discussing relevant matters with management and external auditors. The Board is also responsible for recommending the appointment of the Company’s external auditors.

Schwartz Levitsky Feldman llp, an independent firm of Chartered Accountants, is appointed by the shareholders to audit the financial statements and report directly to the shareholders; their report follows. The external auditors have full and free access to, and are available to meet periodically and separately with, the Audit Committee of the Board and management to discuss their audit findings. The Board of Directors approved the consolidated financial statements.

(signed) “James Cassina”		(signed) “Milton Klyman”

James Cassina, President		Milton Klyman, Director

December 22, 2011

Schwartz Levitsky Feldman llp

CHARTERED ACCOUNTANTS

LICENSED PUBLIC ACCOUNTANTS

TORONTO · MONTREAL

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Eagleford Energy Inc.

We have audited the accompanying consolidated financial statements of Eagleford Energy Inc., which comprise the consolidated balance sheets as at August 31, 2011 and 2010 and the consolidated statements of operations, comprehensive loss, shareholders’ equity and cash flows for each of the three years ended August 31, 2011, 2010 and 2009 and summary of significant accounting policies and other explanatory information.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with Canadian generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

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 comply with ethical requirements and plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditors’ judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Eagleford Energy Inc. as at August 31, 2011 and 2010, and its financial performance and its consolidated cash flows for the years ended August 31, 2011, 2010 and 2009 in accordance with Canadian generally accepted accounting principles.

Emphasis of Matter

Without qualifying our opinion, we draw your attention to Note 1 in the consolidated financial statements which indicates that the Company incurred a net loss of $752,557 during the year ended August 31, 2011 and, as of that date the Company’s current liabilities exceeded its current assets by $4,870,621. These conditions, along with other matters as set forth in Note 1 describes matters indicate the existence of a material uncertainty that may cast significant doubt about the Company’s ability to continue as going concern.

“SCHWARTZ LEVITSKY FELDMAN LLP”

Toronto, Ontario, Canada	Chartered Accountants
December 22, 2011	Licensed Public Accountants
2300 Yonge Street, Suite 1500
Toronto, Ontario M4P 1E4
Tel: 416 785 5353
Fax: 416 785 5663

Consolidated Balance Sheets

(Expressed in Canadian Dollars)

August 31,	2011			2010

Assets
Current
Cash and cash equivalents	$	165,266		$	43,776
Marketable securities (Note 6)		1			1
Accounts receivable (Note 5)		127,546			53,060
Prepaid expenses and deposits (Note 9(i))		44,285			-
Due from related party (Note 10)		-			1,325
		337,098			98,162
Oil and gas interests (Note 7)
Developed		243,000			314,000
Undeveloped		8,898,128			5,695,290
		9,141,128			6,009,290
	$	9,478,226		$	6,107,452

Liabilities
Current
Accounts payable and accrued liabilities	$	1,258,839		$	488,741
Secured notes payable (Note 12)		1,012,644			186,183
Shareholder loans (Note 10)		2,936,236			57,500
Loan payable (Note 11)		-			110,000
		5,207,719			842,424
Long term
Secured notes payable (Note 12)		-			1,021,344
Asset retirement obligations (Note 8)		50,208			3,907
		50,208			1,025,251
		5,257,927			1,867,675

Shareholders’ Equity
Share capital (Note 9)		4,635,556			3,817,184
Warrants (Note 9)		1,969,516			2,096,078
Contributed surplus (Note 9)		85,019			43,750
Deficit		(2,469,792	)		(1,717,235	)
		4,220,299			4,239,777
	$	9,478,226		$	6,107,452

Going Concern (Note 1)

Related Party Transactions and Balances (Note10)

Commitments and Contingencies (Note 18)

Subsequent Events (Note 19)

On behalf of the Board:

(signed) “James Cassina” Director

(signed) “Milton Klyman” Director

The accompanying notes are an integral part of these consolidated financial statements

Consolidated Statements of Operations and Comprehensive Loss

(Expressed in Canadian Dollars)

For the years ended August 31	2011			2010			2009

Oil and Gas Operations
Revenue	$	71,786		$	105,374		$	56,199

Operating Costs		67,611			102,590			83,187
Depletion		23,136			38,370			26,638
		90,747			140,960			109,825

Loss from oil and gas operations		(18,961	)		(35,586	)		(53,626	)

Expenses
Management fees (Note10)		56,250			24,000			18,000
Office and general		16,142			2,474			5,150
Professional fees		210,633			152,844			106,770
Transfer and registrar costs		61,560			45,206			24,965
Head office services		113,828			41,738			16,125
Write down of oil and gas interests		49,464			54,630			105,805
Interest		265,889			5,750			-
Salaries and wages		44,061			-			-
Marketing and public relations		88,569			-			-
Gain on foreign exchange		(164,800	)		-			-
Consulting fees		-			326,511			-
		741,596			653,153			276,815

Operating loss for the year before under noted		(760,557	)		(688,739	)		(330,441	)
items
Gain on disposal of marketable securities		8,000			-			-
Interest		-			30			1,580

Net loss and comprehensive loss	$	(752,557	)	$	(688,709	)	$	(328,861	)

Loss per share, basic and diluted	$	(0.024	)	$	(0.028	)	$	(0.019	)

Weighted average shares outstanding (Note 9)		31,927,228			24,687,130			17,646,295

The accompanying 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,	2011			2010			2009

Cash provided by (used in)
Operating activities
Net loss for the year	$	(752,557	)	$	(688,709	)	$	(328,861	)
Adjustments for non-cash items:
Depletion		23,136			38,370			26,638
Accretion of asset retirement obligations		551			273			130
Write-down of oil and gas interests		49,464			54,630			105,805
Imputed interest		5,750			5,750			-
Asset retirement obligations		45,750			-			-
Shares and warrants issued for services (Note 20)		88,569			326,511			-
Gain on disposal of marketable securities		(8,000	)		-			-
Unrealized foreign exchange gain		(96,443	)		-			-
Net change in non-cash working capital (Note 20)		696,937			43,855			23,955
		53,157			(219,320	)		(172,333	)
Investing activities
Oil and gas interests, net		(3,204,438	)		(26,597	)		(10,000	)
Proceeds on disposal of marketable securities		8,000			-			-
Acquisition of 1354166 Alberta Ltd.		-			-			90,499
Acquisition of Dyami Energy LLC		-			5,369			-
		(3,196,438	)		(21,228	)		80,499
Financing activities
Warrants exercised		594,475			147,000			-
Shareholder loans		2,878,736			-			-
Secured notes payable, net		(98,440	)		-			-
Repayment of loan payable		(110,000	)		-			-
Share issue costs on acquisition of Dyami Energy LLC		-			(35,581	)		-
Proceeds from private placements, net		-			-			180,013
Repayment to note holders pursuant to acquisition
of 1354166 Alberta Ltd.		-			-			(118,000	)
		3,264,771			111,419			62,013

Net increase (decrease) in cash for the year		121,490			(129,129	)		(29,821	)

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

Cash and cash equivalents, end of year	$	165,266		$	43,776		$	172,905
Cash and cash equivalents consists of:
Cash	$	165,266		$	43,776		$	72,392
Guaranteed investment certificates		-			-			100,513
	$	165,266		$	43,776		$	172,905

Supplemental Cash Flow Information and Non-cash Transactions (Note 20)

The accompanying 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, 2011, 2010 and 2009

	(Note 9)					(Note 9)						(Note 9)
												CONTRI-
	SHARE CAPITAL					WARRANTS						BUTED SURPLUS
	Number		Amount			Number			Amount			BUTED SURPLUS		DEFICIT			TOTAL
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 for services							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
Warrants exercised		3,710,346		722,572			(3,710,346	)		(128,097	)							594,475
Units issued as compensation		100,000		95,800			50,000			37,054								132,854
Warrants cancelled							(54,645	)		(35,519	)		35,519					-
Imputed interest													5,750					5,750
Net loss and comprehensive loss for the year															(752,557	)		(752,557	)
Balance August 31, 2011		33,561,372	$	4,635,556			12,730,062		$	1,969,516		$	85,019	$	(2,469,792	)	$	4,220,299

The accompanying notes are an integral part of these consolidated financial statements

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

1. Nature of Operations and Going Concern

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.

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 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, 2011, the Company had a working capital deficiency of $4,870,621 and an accumulated deficit of $2,469,792. 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 obligations 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.

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.

2. Significant Accounting Policies

These consolidated financial statements of Eagleford have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”). The preparation of these consolidated financial statements in accordance with generally accepted accounting principles in United States (“US GAAP”) have resulted in differences to the consolidated balance sheets and the consolidated statements of operations and comprehensive loss and consolidated statements of shareholders’ equity from the consolidated financial statements prepared using Canadian GAAP (see Note 17).

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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 continued operations as 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.

Oil and Gas Interests

The Company follows the successful efforts method of accounting for its oil and gas interests. 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 has 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.

Developed oil and gas reserves - Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction means is by not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expect to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)	Reserves on any undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at great distances;

(ii)	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedules to be drilled within five years, unless the specific circumstances justify a longer time; and

(iii)

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

2. Significant Accounting Policies (cont’d)

Depletion and Depreciation

Depletion of oil and 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 oil and 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 of Long-Lived Assets

The carrying values of property and equipment are reviewed for impairment whenever events or circumstances indicate that the recoverable amount may be less than the carrying value. The determination of when to recognize an impairment loss for a long-lived asset to be held and used is made when its carrying value exceeds the total undiscounted cash flows expected from its use and eventual disposition. When impairment is indicated, the amount of the impairment loss is determined as the excess of the carrying value of the amount over its fair value based on estimated discounted cash flows from use or disposition.

Revenue Recognition

Revenues from the production of oil and gas properties in which the Company has an interest with joint partners, are recognize, on the basis of the Company’s working interest in those properties (the entitlement method), on receipt of a statement of account from the operators of the properties.

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.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

2. Significant Accounting Policies (cont’d)

Foreign Currencies

The functional and reporting currency of the Company is the Canadian dollar. Monetary assets and liabilities are translated at exchange rates in effect at the balance sheet date. Non-monetary assets are translated at exchange rates in effect when they were acquired. Revenue and expenses are translated at the approximate average rate of exchange for the year, except that amortization is translated at the rates used to translate related assets.

One of the Company’s subsidiaries uses the US Dollar as the functional currency. However, this subsidiary is considered integrated to Eagleford Energy Inc’s operations since it relies on the Company to fund its operations. Hence translation gains and losses of this subsidiary are charged to the consolidated statement of operations.

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, 2011 was $1 (2010 - $1) (see Note 6).

Financial Instruments

All financial instruments are measured at fair value on initial recognition of the instrument. Measurement in subsequent periods depends on whether the financial instrument has been classified as “held-for-trading”, “available-for-sale”, “held-to-maturity”, “loans and receivables”, or “other financial liabilities” as defined by the applicable accounting standards.

Cash and cash equivalents are designated as “held-for-trading” and is measured at fair value, which approximates carrying value.

Marketable securities are designated as “held-for-trading” and measured at fair value with unrealized gains and losses recorded in net income until the security is sold or if an unrealized loss is considered other than temporary, the unrealized loss is expensed. Unrealized gains and losses represent the net difference between the total average costs of short term assets on hand and their fair value based on quoted market prices for the marketable securities.

Accounts receivable are designated as “loans and receivable” and are carried at amortized cost. Accounts payable and accrued liabilities, secured notes payable and shareholder loans are designated as ”other financial liabilities” and are carried at amortized cost.

The CICA Handbook Section 3862 – “Financial Instruments – Disclosure”, requires an entity to classify fair value measurements in accordance with an established hierarchy that prioritizes the inputs in valuation techniques used to measure fair value. The levels and inputs which may be used to measure fair value are as follows:

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

2. Significant Accounting Policies (cont’d)

Financial Instruments (cont’d)

Level 1 – fair values are based on quoted prices in active markets for identical assets or liabilities;

Level 2 – fair values are based on inputs other than quoted prices that are observable for the asset or liability, either directly (as prices) or indirectly (derived from prices); or

Level 3 – applies to assets and liabilities for inputs that are not based on observable market data, which are unobservable inputs.

Cash Equivalents

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

Estimates and Measurement Uncertainty

The preparation of the consolidated financial statements in accordance with Canadian GAAP requires management to make estimates and assumptions that affect the values and presentation of assets, liabilities, revenues, expenses and disclosures of contingencies and commitments. Such estimates primarily relate to unsettled transactions and events at the balance sheet date which are based on information available to management at each financial statement date. Actual results may differ from those estimated.

Areas where management is required to make significant estimates are as follows:

Depletion and impairment of Oil and Gas Interests are determined using estimates for resource reserves, and the impairment assessment of Oil and Gas Interests requires further assumptions for future commodity prices, royalties, operating costs, development costs, abandonment costs, and the fair value of unproven properties, all of which are inherently uncertain. To mitigate the risk that inappropriate assumptions are used, estimates are evaluated by independent reserve evaluators.

ii.

The provision for asset retirement obligations requires management to estimate the timing and amount of cash flows required to retire its Oil and Gas Interests.

iii.

The Company uses the Black-Scholes option pricing model to determine the fair value of stock options and common share purchase warrants granted. This model requires management to estimate the volatility of the Company’s future share price, expected lives of stock options and warrants and future dividend yields.

iv.

The recognition of future income tax assets requires judgment as to whether future taxable income will be sufficient to realize the benefit of these tax assets.

By their nature, these estimates are subject to measurement uncertainty and the effect of changes in such estimates on the consolidated financial statements for current and future periods could be significant.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on temporary differences between financial reporting and tax bases of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes. Future income tax assets and liabilities are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. Future income tax assets are recognized in the financial statements if realization is considered more likely than not. A valuation allowance against future tax assets is provided to the extent that the realization of these future tax assets is not more likely than not.

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 follows a fair value based method of accounting for all Stock-based Compensation and Other Stock-based Payments to employees and non-employees. The fair value of all share purchase options is expensed over their vesting period with a corresponding increase to contributed surplus. Upon exercise of share purchase options, the consideration paid by the option holder, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital. The Company uses the Black-Scholes option valuation model to calculate the fair value of share purchase options at the date of grant.

The quoted market price of the Company’s shares on the date of issuance under any stock compensation plan is considered as fair value of the shares issued.

Loss Per Share

Basic loss per share is calculated by dividing net loss (the numerator) by the weighted average number of common shares outstanding (the denominator) during the period. Diluted loss per share reflects the dilution that would occur if outstanding stock options and share purchase warrants were exercised or converted into common shares using the treasury stock method and are calculated by dividing net loss applicable to common shares by the sum of the weighted average number of common shares outstanding and all additional common shares that would have been outstanding if potentially dilutive common shares had been issued.

The inclusion of the Company’s stock options and share purchase warrants in the computation of diluted loss per share would have an anti-dilutive effect on loss per share and are therefore excluded from the computation. Consequently, there is no difference between basic loss per share and diluted loss per share.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

2. Significant Accounting Policies (cont’d)

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 Policies and Future Accounting Pronouncements

Change in Accounting Policies

Business Combinations

In January 2009, the CICA issued Section 1582, “Business Combinations”, Section 1601, “Consolidations”, and Section 1602, “Non-Controlling Interests”. These sections replace the former Section 1581, “Business Combinations”, and Section 1600, “Consolidated Financial Statements”, and establish a new section for accounting for a non-controlling interest in a subsidiary.

Sections 1582 and 1602 will require net assets, non-controlling interests and goodwill acquired in a business combination to be recorded at fair value and non-controlling interests will be reported as a component of equity. In addition, the definition of a business is expanded and is described as an integrated set of activities and assets that are capable of being managed to provide a return to investors or economic benefits to owners. Acquisition costs are not part of the consideration and are to be expensed when incurred. Section 1601 establishes standards for the preparation of consolidated financial statements. The company will adopt these standards concurrently with IFRS.

Future Accounting Pronouncements

Adoption of International Financial Accounting Standards (“IFRS”)

Public companies in Canada were required to adopt IFRS for the years beginning on or after January 1, 2011. For the company, the adoption date is September 1, 2011

Consequently, effective September 1, 2011, the Company adopted IFRS as the basis for preparing its consolidated financial statements.. The company will prepare its consolidated financial statements for the first quarter ending November 30, 2011 in accordance with IFRS, which will include comparative data for the prior year also prepared in accordance with IFRS as well as an opening IFRS balance sheet at September 1, 2010

The initial phase of implementation included conceptual application of the new rules, analysis of the Company’s accounting data and assessment of key areas that may be impacted and a consideration of the exemptions allowed under IFRS1, first-time adoption of IFRS. In this phase, Property, Plant and Equipment, Exploration and Evaluation Assets, Impairment Testing and Asset Retirement Obligations were identified as key areas.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

4. Business Acquisitions

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 Murphy and Matthews leases and is payable on the earlier of 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.

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.

The fair value of the Dyami Energy transaction was 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 was as follows:

Consideration:
Issuance of 3,418,467 Eagleford units	$	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

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

4. Business Combinations (cont’d)

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 was as follows:

Consideration:
Issuance of 8,910,564 Eagleford 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

5. Accounts Receivable

The Company’s accounts receivable balances at August 31, 2011 and 2010 are as follows:

	August 31, 2011		August 31, 2010
Trade receivables	$	11,739	$	55,797
HST receivable		43,275		23,935
Other receivables (1)		72,532		23,328
Allowance for doubtful accounts		-		-
Balance	$	127,546	$	53,060

(1)

Included in other receivables are amounts due from joint interest partners.

6. Marketable Securities

	August 31, 2011		August 31, 2010
Investments in quoted companies
(Fair value $1 (2010 - $1)	$	1	$	1

The Company holds securities of entities whose shares are listed on an exchange for trading. Accordingly, in prior years, management has written down the investments to a nominal value of $1. During the year, the Company sold one of its previously written down securities for gross proceeds of $8,000 (see Note 2).

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

7. Oil and Gas Interests

	August 31, 2011			August 31, 2010
Developed – Canada
Net book value at	$	314,000		$	407,000
Change in asset retirement obligations estimate		1,600			-
Depletion		(23,136	)		(38,370	)
Impairment		(49,464	)		(54,630	)
Total developed, Alberta Canada		243,000			314,000

Undeveloped - USA
Acquisition of a 10% interest in the Matthews Lease		212,780			212,780
Acquisition of oil and gas interests (Dyami Energy)		5,472,464			5,472,464
Exploration expenditures		10,046			10,046
Net book value at		5,695,290			5,695,290
Exploration expenditures		3,158,688
Asset retirement obligation		44,150			-

Total undeveloped, Texas, USA		8,898,128			5,695,290
Total developed and undeveloped	$	9,141,128		$	6,009,290

Developed -Canada

The Company has a 5.1975% interest in a producing natural gas unit located in the Botha area of Alberta, Canada. In addition the Company holds a 0.5% non convertible gross overriding royalty in a natural gas well located in the Haynes area of Alberta to which no reserves were assigned.

The Company performed an impairment test calculation at August 31, 2011 and 2010 using forecast prices and costs to assess the potential impairment of its developed oil and gas interests located in Canada. The oil and gas future prices are based on the commodity price forecast of the Company’s independent reserve evaluators. At August 31, 2011 the Company recorded an impairment of $49,464 (2010 - $54,630).

Undeveloped – USA

The undeveloped properties have been excluded from the depletion base and have been assessed separately for impairment. No impairment allowance has been made during the year ended August 31, 2011 or 2010, based on management’s best estimate of the fair value of the properties. Due to subjectivity related to their fair value assessments, by their nature such assessments are subject to measurement uncertainty.

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 for consideration of $212,780.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

7. Oil and Gas Interests (cont’d)

On August 31, 2010 the Company acquired all of the issued and outstanding membership interests of Dyami Energy, an exploration stage company. 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, subject to the San Miguel formation farmout agreement noted below. 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 February 8, 2010 and amended October 15, 2010 (the “Agreement”). Under the terms of the Agreement, Dyami Energy had 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; and

(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”).

Dyami Energy’s 15% working interest partner 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 Matthews/Dyami #1-H well to a measured depth of 8,563 feet including 3,300 horizontal feet into the Eagle Ford shale formation and accordingly Dyami Energy satisfied (a) and (c) above. The well has been logged and cored and the Company is formulating a detailed frac design and completion plan.

In order to satisfy (b) above on March 29, 2011 the Company spud the Matthews/Dyami #3 well and drilled to a vertical depth of approximately 3,500 feet to the base of the San Miguel formation. The Company completed a nitrified acid injection operation and the well has been placed on production testing.

On March 31, 2011 the Company entered into a Farmout Agreement (the “Farmout”) from surface to the base of the San Miguel formation (the “San Miguel”) on the Matthews Lease. Under the Farmout, the farmee may spend up to US$1,050,000 on exploration and development of the San Miguel to earn a maximum of 42.50% working interest (31.875% net revenue interest). Under the terms of the Farmout, the farmee may earn an initial 25% of the Company’s working interest in the San Miguel by paying 100% of the costs to drill, complete, equip and perform an injection operation on a vertical test well to a depth of approximately 3,500 feet (the “Initial Test Well”). After the performance of the Initial Test Well, the farmee may increase its working interest to 50% of the Company’s working interest by spending the entire $1,050,000 on additional operations on the San Miguel in a good faith effort to produce hydrocarbons. During the year ended August 31, 2011, the Company incurred $744,837 in costs related to the Matthews/Dyami #3 well and $71,871 is included in accounts receivable. As of August 31, 2011 the Company had not assigned any interest to the farmee in the San Miguel formation.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

7. Oil and Gas Interests (cont’d)

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 and is now being held under a continuous drilling program provision which requires a well to be drilled every 180 days. Upon cessation of timely drilling, rights for further drilling expire on all acreage not included in a production unit which shall be re-assigned (see Note 19).

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 from surface to base of the Austin Chalk formation, and a 3% carried interest on the drilling costs from the top of the Eagle Ford shale formation to basement on the first well drilled into a serpentine plug and for the first well drilled into a second serpentine plug, if discovered. 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”). 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 and the Mineral Lease Agreement, Dyami Energy had a commitment to 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 totaling US$65,925 in the aggregate (paid July 28, 2010) to extend the period to commence drilling for 180 days to January 30, 2011. On January 20, 2011, Dyami Energy spud its Murphy/Dyami #1 test well and drilled to a vertical depth of approximately 4,588 feet and accordingly satisfied this commitment.

Dyami Energy is required to drill a well every six months in order to maintain the Murphy Lease. Upon cessation of timely drilling, rights for further drilling expire on all acreage not included in a production unit which shall be re-assigned (see Note 19).

On July 30, 2011 Dyami Energy spud its second test well the Murphy/Dyami #2 and drilled to a vertical depth of approximately 4,415 feet. The Company is formulating completion programs for the Murphy/Dyami #1 and Murphy/Dyami #2 wells.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

8. Asset Retirement Obligations

The Company’s asset retirement obligations result from net ownership interests in oil and 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, 2011 was approximately $102,974 which will be incurred between 2022 and 2030 (2010 - $8,568). A credit-adjusted risk-free rate of 7% and an annual inflation rate of 3.9% were used to calculate the future asset retirement obligation.

	2011		2010
Balance, beginning of year	$	3,907	$	3,634
Additions		44,150		-
Accretion expense		551		273
Change in estimates		1,600		-
	$	50,208	$	3,907

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, 2008		10,471,739	$	467,604
February 5, 2009 private placement (note a)		2,600,000		67,600
February 25, 2009 private placement (note b)		1,000,256		26,007
February 27, 2009 acquisition (note c)		8,910,564		231,675
February 27, 2009 debt settlement (note d)		1,250,000		32,500
Balance at August 31, 2009		24,232,559		825,386
Exercise of warrants (note e)		2,100,000		197,400
August 31, 2010 acquisition, net of transaction costs (note f)		3,418,467		2,794,398
Balance August 31, 2010		29,751,026		3,817,184
Exercise of warrants (note h)		3,710,346		722,572
Issued as compensation (note i)		100,000		95,800
Balance August 31, 2011		33,561,372	$	4,635,556

(a) 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.

(b) 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.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

(c) 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.

(d) 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.

(e) 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.

(f) 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.

(g) 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 amount allocated to warrants based on relative fair value using the Black Scholes model was $214,372 and $112,139 respectively and the total, $326,511 was recorded as compensation expense.

On November 5, 2010, the Company terminated the agreement dated June 10, 2010 with Gar Wood. As a result 36,430 warrants exercisable at $1.00 expiring December 10, 2011 were cancelled and 18,215 warrants were exercisable at $1.50 expiring June 10, 2012 were cancelled. The amount allocated to warrants based on relative fair value using the Black Scholes model was $23,315 and $12,204 respectively and the total, $35,519 was recorded as an increase to contributed surplus.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

(h) During the year ended August 31, 2011, 500,000 common share purchase warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $35,000. The amount allocated to warrants based on relative fair value using the Black Scholes model was $12,000; 600,000 common share purchase warrants were exercised at $0.07 expiring February 25, 2014 for proceeds of $42,000. The amount allocated to warrants based on relative fair value using the Black Scholes model was $14,400; 35,346 common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $2,475. The amount allocated to warrants based on relative fair value using the Black Scholes model was $822; and 2,575,000 common share purchase warrants were exercised at $0.20 expiring April 14, 2011 for proceeds of $515,000. The amount allocated to warrants based on relative fair value using the Black Scholes model was $100,875.

(i) On April 29, 2011, the Company entered into a consulting agreement with a service provider to provide corporate marketing and public relations to the Company for a period of six months. As compensation, the Company agreed to issue 100,000 common shares and 50,000 common share purchase warrants exercisable at US $1.25 per common share expiring May 4, 2012. The amount allocated to common shares was based on the share price at the time of issuance, amounting to $95,800 and $37,054 for the warrants based on the estimated fair value using the Black Scholes pricing model. $88,569 was recorded as marketing and public relations expense and $44,285 was recorded as prepaid expenses at August 31, 2011.

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

	2011					2010					2009
Warrants	Number of Warrants			Weighted Average Price		Number of Warrants			Weighted Average Price		Number of Warrants		Weighted Average Price
Outstanding beginning of year		16,445,053		$	0.22		16,335,820		$	0.09		2,575,000	$	0.20
Issued		50,000			1.25		2,209,233			1.04		13,760,820		0.07
Exercised		(2,575,000	)		0.20		(2,100,000	)		0.07		-		-
Exercised		(1,113,346	)		0.07		-			-		-		-
Cancelled		(36,430	)		1.00		-			-		-		-
Cancelled		(18,215	)		1.50		-			-		-		-
Outstanding end of year		12,730,062		$	0.24		16,445,053		$	0.22		16,335,820	$	0.09

The following table summarizes the outstanding warrants as at August 31, 2011:

Number of Warrants	Note	Exercise Price		Expiry Date	Warrant Value ($)
1,000,000	(note a, e, h)	$	0.07	February 5, 2014	$	24,000
400,256	(note b, h)	$	0.07	February 25, 2014		9,606
9,125,218	(note c, d, e, h)	$	0.07	February 27, 2014		219,031
296,903	(note g)	US$	1.00	December 10, 2011		191,057
148,452	(note g)	US$	1.50	June 10, 2012		99,935
1,709,233	(note f)	US$	1.00	August 31, 2014		1,388,833
50,000	(note i)	US$	1.25	May 4, 2012		37,054
12,730,062					$	1,969,516

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

The fair value of the warrants issued during the year ended August 31, 2011, 2010 and 2009 were estimated on the date of issue using the Black-Scholes pricing model with the following assumptions:

Black-Scholes Assumptions used	2011
Risk-free interest rate		1.7	%
Expected volatility		254	%
Expected life (years)		1
Dividend yield		0	%
Fair value of the warrants issued on May 4, 2011	$	0.74

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

The weighted average basic and diluted shares outstanding at August 31, 2011, 2010 and 2009 is as follows:

Weighted Average Shares Outstanding	2011		2010		2009
Weighted average shares outstanding, basic		31,927,228		24,687,130		17,646,295
Dilutive effect of warrants		13,273,114		16,008,996		9,749,557
Weighted average shares outstanding, diluted		45,200,342		40,696,126		27,395,852

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 6,170,205 common shares. To date, no options have been issued.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

Contributed Surplus

Contributed surplus transactions for the respective years are as follows:

	Amount
Balance, August 31, 2008 and 2009	$	38,000
Imputed interest		5,750
Balance, August 31, 2010		43,750
Cancellation of warrants (note g)		35,519
Imputed interest (see Note 10)		5,750
Balance, August 31,2011	$	85,019

10. Related Party Transactions and Balances

The following transactions with an individual related to the Company 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.

		2011				2010 (1)				2009 (1)
Management fees to the President and Director of the Company		$	56,250			$	24,000			$	18,000

(1)

Management fees to the former President of the Company.

At August 31, 2011 included in accounts payable are management fees payable to the President of $56,250 (2010 – Nil).

At August 31, 2011 the amount of directors’ fees included in accounts payable was $8,800 (2010 - $6,700).

On February 5, 2009, a corporation in which the Company’s former President has voting and significant investment interest, 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.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

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.

At August 31, 2010 the Company issued a US$175,000, 5% per annum secured promissory note to Source Re Work Program, Inc. (“Source”). On March 18, 2011 the Company re-paid to Source US$100,000 of the promissory note. Eric Johnson is the President of Source, a shareholder of the Company and was the Vice President of Operations for Dyami Energy until April 13, 2011. During the year ended August 31, 2011, the Company paid to Eric Johnson expenses of US$5,506 and salary of US$43,750 (see Note 12 and Note 19).

At August 31, 2011 the Company has a US$960,000, 6% per annum secured promissory note payable to Benchmark Enterprises LLC (“Benchmark”). Benchmark is a shareholder of the Company. For the year ended August 31, 2011 interest of $55,356 was recorded and included in accounts payable (August 31, 2010 - $26,863) (see Note 12).

At August 31, 2011 included in accounts payable is $68,918 due to Gottbetter & Partners LLP for legal fees (August 31, 2010 - $82,154). 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 of $57,500 is due to a shareholder and is unsecured, non-interest bearing and repayable on demand. For the year ended August 31, 2011 interest was imputed at a rate of 10% per annum and interest of $5,750 was recorded and included in contributed surplus (August 31, 2010 - $5,750).

During the year ended August 31, 2011, the Company received US$2,490,000 and $149,000 and issued promissory notes to seven 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. At August 31, 2011 accrued interest of $171,640 is included in accounts payable.

During the year ended August 31, 2011, 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. For the year ended August 31, 2011 interest of $26,135 was recorded and included in accounts payable (see Note 19).

11. Loan Payable

The loan payable in the amount of $110,000 was due to an arms’ length 3rd party and was unsecured, non-interest bearing and repayable on demand. On May 4, 2011 the Company repaid the demand loan in full.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

12. Secured Notes Payable

On August 31, 2010 the Company issued a US$175,000, 5% per annum secured promissory note to Source Re Work Program, Inc. (“Source”). The note was secured by the Eagleford’s interest in the Matthews Lease, Zavala County, Texas. US$100,000 of the note was due on February 28, 2011 and was repaid on March 18, 2011. The balance of US$75,000 (CDN $73,380) of the note together with accrued interest is due and payable on August 31, 2011. For the year ended August 31, 2011 interest of $6,115 was recorded and included in accounts payable (see Note 19).

At August 31, 2011 the Company has a US$960,000 (2011 CDN $939,264), 6% per annum secured promissory note payable to Benchmark Enterprises LLC (August 31, 2010 $US$960,000). The note is payable on the earlier of December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000. For the year ended August 31, 2011 interest of $56,356 was recorded and included in accounts payable (August 31, 2010 $26,863). The note is secured by Dyami Energy’s interest in the Matthews and Murphy Leases, Zavala County, Texas. The Company may, in its sole discretion, repay any portion of the principal amount (see Note 10).

13. 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, 2011:

	Year ended August 31, 2011					As at August 31, 2011
	Interest and other income		Net (loss)			Oil and gas interests		Other assets
Canada	$	71,786	$	(696,643	)	$	243,000	$	264,611
United States		-		(55,914	)		8,898,128		72,487
Total	$	71,786	$	(752,557	)	$	9,141,128	$	337,098

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 (loss)			Oil and gas interests		Other assets
Canada	$	105,404	$	(688,709	)	$	314,000	$	68,141
United States		-		-			5,695,290		30,021
Total	$	105,404	$	(688,709	)	$	6,009,290	$	98,162

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

14. Financial Instruments and Concentration of Risks

The Company is exposed in varying degrees of risks arising from financial its instruments. The Company does not participate in the use of derivative financial instruments to mitigate these risks and has no designated hedging transactions. The Board approves and monitors the risk management processes. The Board’s main objectives for managing risks are to ensure liquidity, the fulfillment of obligations and limited exposure to credit and market risks while ensuring greater returns on any surplus funds -. There were no changes to the objectives or the process from the prior year. Cash and cash equivalents and marketable securities are the only financial instruments and are classified as level 1 financial instruments in the fair value hierarchy.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

Effective April 1, 2009, the Company adopted the recommendations of the Emerging Issues Committee Abstract EIC -173, “Credit Risk and the Fair Value of Financial Assets and Financial Liabilities” which states that an entity’s own credit and the credit risk of the counterparty should be taken into account in determining the fair value of financial assets and financial liabilities. These recommendations were particularly applied in evaluating the fair values of the Company’s marketable securities.

The types of risk exposure and the ways in which such exposures are managed are as follows:

Credit Risk

Concentration risks exist in cash and cash equivalents because significant balances are maintained with one financial institution and a brokerage firm. The risk is mitigated because the financial institution is an international bank and the brokerage firm is a reputable Canadian brokerage firm.

Liquidity Risk

The Company monitors its liquidity position regularly to assess whether it has the funds necessary to fulfill planned exploration commitments on its oil and gas properties or that viable options are available to fund such commitments from new equity issuances or alternative sources such as farm-out agreements. However, as an exploration company at an early stage of development and without significant internally generated cash flow, there are inherent liquidity risks, including the possibility that additional financing may not be available to the Company, or that actual exploration expenditures may exceed those planned. The current uncertainty in global markets and ongoing litigations could have an impact on the Company’s future ability to access capital on terms that are acceptable to the Company. The Company has so far been able to raise the required financing to meet its obligation on time.

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 use derivative financial instruments or derivative commodity instruments to mitigate this risk.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

14. Financial Instruments and Concentration of Risks (cont’d)

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.

Market events and conditions in recent years 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 caused a loss of confidence in the broader U.S. and global credit and financial markets. 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.

The Company mitigates these risks by:

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

•	performing geophysical, geological or engineering analyses of prospects.

•	focusing on a limited number of core properties.

(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, 2011 and 2010 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:

	2011						2010
	Increase 10%			Decrease 10%			Increase 10%			Decrease 10%
Revenue	$	78,965		$	64,607		$	115,911		$	94,837
Net loss	$	(745,378	)	$	(759,736	)	$	(678,172	)	$	(699,246	)

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

14. Financial Instruments and Concentration of Risks (cont’d)

(ii) Currency Risk

The Company is exposed to the fluctuations in 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 United States 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 operates in Canada and a portion of its expenses are incurred in U.S. 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 dollars at August 31, 2011 and 2010:

Financial Instruments	2011		2010
Cash and cash equivalents	$	117,383	$	5,046
Accounts receivable		72,487		21,926
Due from related party		-		1,245
Accounts payable		656,401		198,015
Shareholder loans		2,790,000		-
Secured notes payable		1,035,000		1,135,000
Total US$	$	4,671,271	$	1,361,232
CDN dollar equivalent at year end (1)	$	4,570,372	$	1,448,215

(1)

Translated at the exchange rate in effect at August 31, 2011 $0.9784 (August 31, 2010 - $1.0639)

For the year ended August 31, 2011 the Company had a foreign exchange gain of $164,800 due to the fluctuations in the CDN dollar compared to the US dollar. For the year ended August 31, 2011 a 1% increase/decrease in the exchange rate is estimated to give rise to a change in net loss and comprehensive loss of approximately $1,904. The Company does not use derivative financial instruments to reduce its foreign exchange exposure.

(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 short-term in nature with fixed rates.

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.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

15. Capital Management

The Company’s objectives when managing capital are to ensure the Company will have sufficient financial capacity, liquidity and flexibility to funds its operations, growth and ongoing exploration and development commitments on its oil and gas interests. The Company is dependent on funding these activities through debt and equity financings. Due to long lead cycles of the Company’s exploration activities, the Company’s capital requirements currently exceed its operation cash flow generated. As such the Company is dependent upon future financings in order to maintain its flexibility and liquidity and may from time to time be required to issue equity, issue debt, adjust capital spending or seek joint venture partners.

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 meet current and upcoming obligations. Current plans for the development commitments of the Company’s Texas leases include debt or equity financing or seeking and obtaining a joint venture partner.

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 and favourable market conditions to sustain future development of the business.

As at August 31, 2011and 2010 the Company considers its capital structure to comprise of shareholders equity and long-term debt.

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, 2011.

The Company is not subject to any externally imposed restrictions on its capital requirements.

16. Income Taxes

The Company has capital losses in the amount of approximately $195,852 (2010 - $195,852) which may be carried forward indefinitely to offset future capital gains, and non capital losses in the amount of approximately $1,349,189 (2010 - $794,304) 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		264,244
2030		286,991
2031		557,101
	$	1,349,189

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

16. Income Taxes (cont’d)

A reconciliation between income taxes provided at actual rates and at the basic rate ranging from 28% to 31% (2010 - 28% to 31%) (2009 - 25% to 29%) for federal and provincial taxes is as follows:

	2011			2010			2009
Taxes at statutory rates	$	(225,259	)	$	(203,169	)	$	(88,792	)
Non-taxable items and others		81,421			154,677			47,326
Change in valuation allowance		143,838			48,492			41,466
	$	-		$	-		$	-

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

	2011			2010
Operating loss carry forwards	$	337,297		$	198,576
Share issue costs		6,119			11,959
Marketable securities		1,467			1,467
Capital losses carry forwards		24,482			24,482
Oil and gas interests		29,016			17,939
Cumulative eligible capital		1,319			1,418
Future tax asset		399,700			255,841
Valuation allowance		(399,700	)		(255,841	)
	$	-		$	-

The Company has provided a full valuation allowance against future tax assets at August 31, 2011, due to uncertainties in the Company's ability to utilize its net operating losses.

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

These consolidated financial statements have been prepared in accordance with "Canadian GAAP". Material variations in the accounting principles, practices and methods used in preparing these consolidated financial statements from "US GAAP" and in SEC Regulation S-X are described and quantified below.

The significant differences between Canadian GAAP and US GAAP which had any impact on the consolidated balance sheet and consolidated statement of cash flows are noted below.

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 $219,464 (2010-$104,630) for US GAAP and an impairment loss of $49,464 (2010-$54,630) was recorded for Canadian GAAP.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

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

	2011			2010
Total assets according to Canadian GAAP	$	9,478,226		$	6,107,452
Additional impairment of oil and gas interests		(170,000	)		(50,000	)
Total assets according to US GAAP	$	9,308,226		$	6,057,452

	2011			2010
Total shareholders’ equity according to Canadian GAAP	$	4,220,299		$	4,239,777
Deficit adjustment per US GAAP
Additional impairment of oil and gas interests		(170,000	)		(50,000	)
Total shareholders’ equity according to US GAAP		4,050,299		$	4,189,777

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

	2011			2010			2009
Net loss according to Canadian GAAP	$	752,557		$	688,709		$	328,861
Add: Additional impairment of oil and gas interests		170,000			50,000			73,638
Net loss according to US GAAP	$	922,557		$	738,709		$	402,499
Loss per share, basic and diluted	$	(0.029	)	$	(0.030	)	$	(0.023	)
Shares used in the computation of loss per share		31,927,228			24,687,130			17,646,295

Adoption of New Accounting Policies

FASB Accounting Standards Update ("ASU") No. 2010-13 was issued in April 2010, and amends and clarifies ASC 718 with respect to the classification of an employee share based payment award with an exercise price denominated in the currency of a market in which the underlying security trades. This ASU did not have a material effect on the Company.

In April 2010, the FASB issued ASU 2010-14, “Accounting for Extractive Activities — Oil & Gas”. ASU 2010-14 amends paragraph 932-10-S99-1 due to SEC Release No. 33-8995, "Modernization of Oil and Gas Reporting." The amendments to the guidance on oil and gas accounting are effective August 31, 2010, and did not have a significant impact on the Company's financial position that, if it is unable to raise additional capital, it may find it necessary to substantially reduce or cease operations.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

Future Accounting Pronouncements

In January 2010, FASB issued ASU 2010-06 "Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurement" was issued, which provides amendments to Subtopic 820-10 that requires new disclosures as follows:

1.	Transfers in and out of Levels 1 and 2. A reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers.

Activity in Level 3 fair value measurements. In the reconciliation for fair value measurements using significant unobservable inputs (Level 3), a reporting entity should present separately information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one net number).

This Update provides amendments to Subtopic 820-10 that clarify existing disclosures as follows:

Level of disaggregation. A reporting entity should provide fair value measurement disclosures for each class of assets and liabilities. A class is often a subset of assets or liabilities within a line item in the statement of financial position. A reporting entity needs to use judgment in determining the appropriate classes of assets and liabilities.

Disclosures about inputs and valuation techniques. A reporting entity should provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements. Those disclosures are required for fair value measurements that fall in either Level 2 or Level 3.

This Update also includes conforming amendments to the guidance on employers' disclosures about postretirement benefit plan assets (Subtopic 715-20). The conforming amendments to Subtopic 715-20 change the terminology from major categories of assets to classes of assets and provide a cross reference to the guidance in Subtopic 820-10 on how to determine appropriate classes to present fair value disclosures. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years.

In December 2010, the FASB issued ASU 2010-28 "Intangibles – Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test For Reporting Units With Zero or Negative Carrying Amounts" ("ASU 2010-28").Under ASU 2010-28, if the carrying amount of a reporting unit is zero or negative, an entity must assess whether it is more likely than not that goodwill impairment exists. To make that determination, an entity should consider whether there are adverse qualitative factors that could impact the amount of goodwill, including those listed in ASC 350-20-35-30. As a result of the new guidance, an entity can no longer assert that a reporting unit is not required to perform the second step of the goodwill impairment test because the carrying amount of the reporting unit is zero or negative, despite the existence of qualitative factors that indicate goodwill is more likely than not impaired. ASU 2010-28 is effective for public entities for fiscal years, and for interim periods within those years, beginning after December 15, 2010, with early adoption prohibited.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

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

Future Accounting Pronouncements (cont’d)

In December 2010, the FASB issued ASU 2010-29 "Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations" ("ASU 2010-29"). ASU 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The amendments in this Update also expand the supplemental pro forma disclosures under Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The amended guidance is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted.

In April 2011, the FASB issued ASU No. 2011-02, A Creditor's Determination of Whether a Restructuring Is a Troubled Debt Restructuring, as codified in ASC 310, Receivables. The amendments in this update provide additional guidance to assist creditors in determining whether a restructuring of a receivable meets the criteria to be considered a troubled debt restructuring. The amendments in this update are effective for the period beginning on or after June 15, 2011, and should be applied retrospectively to the beginning of the annual period of adoption. The Company does not expect this update to have a material impact on its consolidated financial statements.

The Company will transition to IFRS on September 1, 2011 and will no longer be required to prepare a reconciliation to US GAAP. Accordingly, the Company has not assessed the impact of adopting future US accounting pronouncements with an application date of September 1, 2011 or beyond in its financial statements and disclosures (see Note 3).

18. Commitments and Contingencies

The Company has drilling commitments on its Mathews Lease and Murphy Lease located in Zavala County, Texas, USA (see Note 7).

Subsequent to the year ended August 31, 2011, a vendor of Dyami Energy has filed a claim in the District Court of Harris County, Texas seeking payment of US$62,800. Dyami Energy is disputing the claim on the basis of excessive charges. The full amount of the claim has been recorded in accounts payable and the outcome of this claim is uncertain at this time. Any legal costs will be expensed as incurred.

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

19. Subsequent Events

On September 1, 2011 the Company repaid to Source, the secured promissory note in full in the amount of US$75,000 together with accrued interest of US$6,250.

Subsequent to the year ended August 31, 2011, the Company commenced drilling its Matthews/Dyami #2H well located in Zavala County, Texas.

Subsequent to the year ended August 31, 2011, the Company issued 639,297 common shares to promissory note holders as full settlement of interest due in the amount of US$166,000 and CDN$14,900.

Subsequent to the year ended August 31, 2011, the Company received $198,845 and US$165,000 and issued promissory notes to five shareholders of the Company. The notes are due on demand and bear interest at 10% per annum. Interest is payable annually on the anniversary date of the note.

20. Supplemental Cash Flow Information and Non-cash Transactions

The following table summarizes the non-cash transactions for the years ended August 31:

	2011			2010			2009
Issuance of shares and warrants for services		88,569			326,511			-
Acquisition of subsidiary		-			4,213,443		$	445,528
Issuance of units on acquisition of subsidiary		-			(4,213,443	)	$	(445,528	)
Transaction costs		-			35,581			-
Warrants cancelled		(35,519	)		-			-
Secured notes payable-Long term		-			1,021,344			-
Secured notes payable-Current		-			186,183			-
Shares issued to settle debt					-		$	62,500
Prepaid portion of shares for services		44,285			-			-

The following table summarizes the supplemental cash flow information for the years ended August 31:

Supplemental cash flow information	2011		2010		2009
Income taxes paid		-	$	10,215		-
Interest paid		-		-		-

The following table summarizes the changes in non-cash working capital for the years ended August 31:

	2011			2010			2009
Accounts receivable	$	(74,486	)	$	(9,312	)	$	(9,297	)
Accounts payable		770,098			63,382			33,252
Due from related party		1,325			-			-
Income taxes payable		-			(10,215	)		-
Net change	$	696,937		$	43,855		$	23,955

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

For the years ended August 31, 2011, 2010 and 2009

21. Comparative Figures

Certain comparative figures have been reclassified to conform to the presentation adopted in 2011.

22. 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.

Item 2

Management’s Discussion and Analysis

Financial Condition and Operating Results

For the year ended

August 31, 2011

(Expressed in Canadian Dollars)

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 year ended August 31, 2011and 2010 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 23, 2011 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).

Certain measures in this Management Discussion and Analysis of Financial Condition and Operating Results do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles such as netback and other production figures and therefore are considered non-GAAP measures. Therefore these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. All figures herein refer to Canadian dollars unless otherwise stated.

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 amalgamated under the laws of the Province of Ontario. The Company's 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. The Company’s oil and gas interests are located in Alberta, Canada and Zavala County, Texas. 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 Over-the-Counter Bulletin Board (OTCBB) under the symbol EFRDF.

The Company’s Audited Consolidated Financial Statements for the year ended August 31, 2011 and 2010 include the accounts of the Company, its wholly owned subsidiaries 1354166 Alberta Ltd. and Dyami Energy LLC (“Dyami Energy”) from the date of acquisition August 31, 2010.

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 became Eagleford Energy Inc.

OVERALL PERFORMANCE

Revenue for the year ended August 31, 2011 was down $33,588 to $71,786 compared to $105,374 for the same period in 2010. The decrease in revenue during 2011 is attributed to lower production volumes and lower commodity prices received. Net loss and comprehensive loss for the twelve months ended August 31, 2011 was $752,557 compared to $688,709 for the comparable twelve month period in 2010. The increase in loss during 2011 was primarily related to decreases in revenue and increases in administrative expenditures including interest costs which were partially offset by a gain on foreign exchange and a gain on disposal of marketable securities.

For the year ended August 31, 2011 the Company’s cash position increased by $121,490 to $165,266 compared to cash of $43,776 at August 31, 2010. At August 31, 2011 the Company’s accounts receivable was $127,546 representing an increase of $74,486 compared to $53,060 at August 31, 2010. Prepaid expenses and deposits at August 31, 2011 were $44,285 compared to Nil in the prior period. For the year ended August 31, 2011 current liabilities increased by $4,365,295 to $5,207,719 compared to $842,424 at August 31, 2010. Long term liabilities decreased by $975,043 to $50,208 compared to $1,025,251 at August 31, 2010. The Company has a working capital deficiency of $4,870,621 at August 31, 2011 compared to a working capital deficiency of $744,262 at August 31, 2010.

During the year ended August 31, 2011, common share purchase warrants were exercised for proceeds of $594,475.

During the year ended August 31, 2011 the Company received $2,878,736 and issued promissory notes bearing interest at 10% per annum. Interest is payable annually on the anniversary date of the notes.

During the year ended August 31, 2011 the Company paid $98,440 of secured notes and $110,000 loan payable.

Through Dyami Energy, the Company commenced operations in August 2010 to drill an initial Eagle Ford shale test well on the Matthews Lease in Zavala County, Texas. The Matthews/Dyami #1H well was drilled to a measured depth of approximately 8,563, feet which includes a 3,300 foot “in section” lateral into the Eagle Ford shale formation. A shot point sleeve was installed in the Eagle Ford shale formation to facilitate a multi stage frac completion.

On January 20, 2011 the Company spud its 100% working interest Murphy/Dyami #1 test well on its 2,637 gross acre Murphy Lease located in Zavala County, Texas. The well was drilled to a vertical depth of approximately 4,588 feet into the Buda formation.

On March 29, 2011 the Company spud the Matthews/Dyami #3 well on the Matthews Lease, Zavala County, Texas. The well was drilled to a vertical depth of approximately 3,500 feet to the base of the San Miguel formation. The Company completed a nitrified acid injection operation and the well has been placed on production testing.

On March 31, 2011 the Company entered into a Farmout Agreement (the “Farmout”) from surface to the base of the San Miguel formation (the “San Miguel”) on the Matthews Lease located in Zavala County, Texas. Under the Farmout, the farmee may spend up to US$1,050,000 on exploration and development of the San Miguel formation to earn a maximum of 42.50% working interest (31.875% net revenue interest). Under the terms of the Farmout, the farmee may earn an initial 25% of the Company’s working interest in the San Miguel by paying 100% of the costs to drill, complete, equip and perform an injection on a vertical test well to a depth of approximately 3,500 feet (the “Initial Test Well”). After the performance of the Initial Test Well, the farmee may increase its working interest to 50% of the Company’s working interest by spending the entire $1,050,000 on additional operations on the San Miguel in a good faith effort to produce hydrocarbons.

On July 30, 2011 the Company spud its second 100% working interest Murphy/Dyami #2 well on its Murphy Lease located in Zavala County, Texas. The well was drilled to a vertical depth of approximately 4,415 feet.

The Company is formulating detailed frac and completion programs for the Matthews/Dyami #1H, Murphy/Dyami #1 and Murphy/Dyami #2 wells.

For the year ended August 31, 2011 the Company incurred $3,158,688 in exploration expenditures related to its Matthews and Murphy Leases in Zavala County, Texas.

The Company expects to apply additional capital to further enhance its 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 may 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 shareholder loans, cash flow from oil and gas operations and proceeds from the issuance of common shares.

RISK AND UNCERTAINTIES

The Company is subject to several risk factors including, but not limited to: the volatility of oil and natural gas prices; foreign exchange and currency risks; general risks related to foreign operations such as political, economic, regulatory and other uncertainties as they relate to both foreign investment policies and energy policies; governments exercising from time to time significant influence on the economy to control inflation; developing environmental regulations in foreign jurisdictions; discovery of new oil and natural gas reserves; concentration of oil sales receipts with a few major customers; substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the long-term for which additional financings will required to implement Eagleford’s business plan.

As the Company has not experienced sufficient positive cash flow from operations to independently finance its growth and operations, it has been reliant on access to capital in the form of both debt and equity to fund on-going operations and to fund capital investments. Although periodic volatility of financial and capital markets may severely limit access to capital, the Company has been able to attract the required investment capital in the past however no assurances can be made that it will continue to do so in the future.

The Company is exposed to foreign exchange and currency risk as a result of fluctuations in exchange rates through its investments as well as some of its debt balances which are denominated in US$.

Some of the Company’s exploration and development costs are expected to be received/paid in reference to US$ denominated prices while a significant portion of its operating and general and administrative costs are denominated in Canadian dollars. As a result the Company is exposed to fluctuations in currency exchange rates between the US dollar and Canadian dollar. The Company has not entered into any currency derivatives in order to reduce its exposure to fluctuations that may incur.

Fluctuations in energy prices will not only impact revenues of the Company but may also affect the ability of the Company to raise additional capital to fund operations and working capital requirements. Crude oil prices are correlated with overall global economic growth and activity. The continuing volatility in the global economic environment has resulted in significant variation in crude oil prices over the last year. Any dramatic drop in crude oil prices will have a negative impact on the operational cash flows of the Company as well as on its ability to finance capital expenditures. In absence of externally-sourced capital, this could limit growth prospects over the short run or may even require the Company to dispose of assets.

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 CONCENTRATION OF RISKS

The Company is exposed in varying degrees of risks arising from financial its instruments. The Company does not participate in the use of derivative financial instruments to mitigate these risks and has no designated hedging transactions. The Board approves and monitors the risk management processes. The Board’s main objectives for managing risks are to ensure liquidity, the fulfillment of obligations and limited exposure to credit and market risks while ensuring greater returns on any surplus funds. There were no changes to the objectives or the process from the prior year. Cash and cash equivalents and marketable securities are the only financial instruments and are classified as level 1 financial instruments in the fair value hierarchy.

Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

The types of risk exposure and the ways in which such exposures are managed are as follows:

Credit Risk

Liquidity Risk

Market Risk

The Company mitigates these risks by:

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

•	performing geophysical, geological or engineering analyses of prospects.

•	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

	2011						2010
	Increase 10%			Decrease 10%			Increase 10%			Decrease 10%
Revenue	$	78,965		$	64,607		$	115,911		$	94,837
Net loss	$	(745,378	)	$	(759,736	)	$	(678,172	)	$	(699,246	)

(ii)	Currency Risk

The Company is exposed to currency risk through the following assets and liabilities denominated in US dollars at August 31, 2011 and 2010:

Financial Instruments	2011		2010
Cash and cash equivalents	$	117,383	$	5,046
Accounts receivable		72,487		21,926
Due from related party		-		1,245
Accounts payable		656,401		198,015
Shareholder loans		2,790,000		-
Secured notes payable		1,035,000		1,135,000
Total US$	$	4,671,271	$	1,361,232
CDN dollar equivalent at year end (1)	$	4,570,372	$	1,448,215

(1)

Translated at the exchange rate in effect at August 31, 2011 $0.9784 (August 31, 2010 - $1.0639)

(iii)

Interest Rate Risk

CAPITAL MANAGEMENT

As at August 31, 2011and 2010 the Company considers its capital structure to comprise of shareholders equity and long-term debt.

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, 2011.

The Company is not subject to any externally imposed restrictions on its capital requirements.

SELECTED ANNUAL INFORMATION

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

For the years ended August 31,	2011			2010			2009
Revenue	$	71,786		$	105,374		$	56,199
Net loss and comprehensive loss	$	(752,557	)	$	(688,709	)	$	(328,861	)
Loss per share basic and diluted	$	(0.024	)	$	(0.028	)	$	(0.019	)
Assets	$	9,478,226		$	6,107,452		$	600,327
Long term liabilities	$	50,208		$	1,025,251		$	3,634

August 31, 2011 – 2010

For the year ended August 31, 2011 revenue decreased compared to revenue in the prior period as a result of natural production declines and lower natural gas prices. The net loss for the year ended August 31, 2011 was $752,557 up $63,848 compared to a net loss of $688,709 in 2010. The increase in loss and comprehensive loss for fiscal 2011 was primarily attributed to interest costs of $265,889 versus $5,750 in the prior period, an increase of $57,789 in professional fees, an increase of $72,090 in head office costs, an increase in salaries and wages of $44,061 and an increase of $88,569 in marketing and public relations. The overall higher administrative costs were partially offset by a gain on foreign exchange, a gain on disposal of marketable securities and a decrease in consulting fees. For the year ended August 31, 2011 assets increased significantly up $3,370,774 to $9,478,226 compared to $6,107,452 for the same period in 2010. The increase in assets is primarily attributed to exploration expenditures incurred of $3,158,688 on the Matthews and Murphy leases in Zavala County, Texas. Long term liabilities decreased in fiscal 2011 compared to 2010 as a result of a US $960,000 long term secured note being moved into current liabilities.

August 31, 2010 - 2009

For the year ended August 31, 2010 revenue increased substantially compared 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, 2009 was primarily attributed to acquisition of 1354166 Alberta Ltd.

RESULTS OF OPERATIONS

	For the Years Ended
Historical	August 31
Production	2011			2010			2009
Natural gas – mcf/d		53			68			45
Historical Prices
Natural Gas - $/mcf	$	3.68		$	4.22		$	3.42
Royalties costs - $/mcf	$	0.76		$	0.98		$	0.63
Production costs - $/mcf	$	2.68		$	2.62		$	3.28
Net back - $/mcf	$	0.24		$	0.62		$	(0.49	)
Operations
Revenue	$	71,786		$	105,374		$	56,199
Net loss and comprehensive loss	$	(752,577	)	$	(688,709	)	$	(328,861	)
Loss per share basic and diluted	$	(0.024	)	$	(0.028	)	$	(0.019	)

Production Volume

For the year ended August 31, 2011 average natural gas sales volumes decreased to 53 mcf/d compared to 68 mcf/d in the comparable twelve month period in 2010. Total production volume for the year ended August 31, 2011 was 19,500 mcf compared to 24,950 mcf for the same period in 2010. The decrease in average sales volume per day and total production volume for the year ended August 31, 2011 was a result of natural production declines.

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 per day 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.

Commodity Prices

For the year ended August 31, 2011 average natural gas prices received per mcf decreased by 13% to $3.68 compared to $4.22 for the twelve months ended August 31, 2010. The decrease in average natural gas prices received was attributed to lower commodity prices for natural gas for the year ended August 31, 2011.

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.

Revenue

Revenue for the year ended August 31, 2011 was down $33,588 to $71,786 compared to $105,374 for the same period in 2010. The decrease in revenue for the year ended August 31, 2011 was attributed to lower production volume due to natural production declines and lower commodity prices received for natural gas.

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.

Operating Costs

For the year ended August 31, 2011 operating costs were $67,611 down $34,979 compared to operating costs of $102,590 for the year ended August 31, 2010. The decrease in operating costs for the year ended August 31, 2011 was attributed lower production volumes.

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.

Depletion

Depletion for the year ended August 31, 2011 decreased by $15,234 to $23,136 compared to $38,370 for the year ended August 31, 2010. The decrease in depletion for the year ended August 31, 2011 was a result of lower production volume.

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.

Administrative Expenses

Administrative expenses for the year ended August 31, 2011 were $741,596 compared to $653,153 for the year ended August 31, 2010. The increase in expenses during fiscal 2011 was primarily attributed to interest costs recorded of $265,889 versus $5,750 in the prior period, an increase of $57,789 in professional fees, an increase of $72,090 in head office costs, and increase of $88,569 in marketing and public relations, an increase in salaries and wages of $44,061 an increase in management fees of $32,250 and an increase in transfer and registrar costs of $16,354. During the year ended August 31, 2011 the Company recorded an impairment of oil and gas interests of $49,464 compared to $54,630 in the comparable period in 2010. The higher administrative expenses during fiscal 2011 were partially offset by a gain on foreign exchange of $164,800 and a reduction in consulting fees of $326,511 compared to fiscal 2010. The increase in overall administrative expenses for the year ended August 31, 2011 is a result of the increased operations of the Company.

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.

Gain on Disposal of Marketable Securities

During the year ended August 31, 2011 the Company recorded a gain on disposal of marketable securities of $8,000 versus $Nil for the comparable period in 2010.

During the year ended August 31, 2010 the Company recorded a gain on disposal of marketable securities of $Nil versus $Nil for the comparable period in 2009.

Interest Income

For the year ended August 31, 2011 interest income was $Nil compared to $30 for the comparable period in 2010.

For the year ended August 31, 2010 interest income was $30 compared to$1,580 for the comparable period in 2009.

The decreases in interest income during fiscal 2011 and 2010 are attributed to decreases in cash held by the Company during the respective periods.

Net Loss and Comprehensive Loss for the Year

Net loss for year ended August 31, 2011 was $752,557 up $63,848 or 9% compared to a net loss of $688,709 for the year ended August 31, 2010. The increase in net loss and for the year ended August 31, 2011 was primarily related to a decrease in revenue and increases in administrative expenses.

Net 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 per Share

The net loss per share for the year ended August 31, 2011 was $0.024 compared to a net loss per share of $0.028 for the same twelve month period in 2010.

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.

SUMMARY OF QUARTERLY RESULTS

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

	2011			2011			2011			2010
For the quarter ending	August 31			May 31			February 28			November 30
Revenue	$	17,925		$	17,826		$	18,936		$	17,099
Net loss and comprehensive loss	$	(295,381	)	$	(241,814	)	$	(116,370	)	$	(98,992	)
Loss per share basic and diluted	$	(0.010	)	$	(0.007	)	$	(0.004	)	$	(0.003	)

Revenue for the four quarters fluctuated as a result of changes in production volume and commodity prices received. The increase in loss for the quarter ended May 31, 2011 was attributed to higher administrative expenses including marketing and public relations of $88,569 and increases in interest expense of $74,864. The increase in loss for the quarter ended August 31, 2011 was attributed to higher administrative expenses including increases in interest expense of $86,845 and an increase in professional fees for year-end audit costs and costs associated with the evaluation of the Company’s reserves. In addition, the company incurred a write down of oil and gas interests of $49,464.

	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	$	(496,520	)	$	(75,144	)	$	(36,746	)	$	(80,299	)
Loss per share basic and diluted	$	(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.

FOURTH QUARTER RESULTS

Production Volume

For the three months ended August 31, 2011 average natural gas sales volumes were 53 mcf/d compared to 68 mcf/d for the comparable period in 2010. Total production volume for the three months ended August 31, 2011 was 4,957 mcf compared to 6,227 mcf for the same three month period ending August 31, 2010. The decrease in production volume in 2011 is primarily related to natural production declines from the Company’s Botha, Alberta gas unit.

Commodity Prices

For the three months ended August 31, 2011 average natural gas sales prices received per mcf decreased to $3.62 compared to $3.75 for the three month period ended August 31, 2010.

Revenue

Revenue decreased by $5,438 to $17,925 for the three months ending August 31, 2011 compared to $23,363 for the three months ending August 31, 2010. Lower commodity prices received and lower production volume was responsible for the decrease in revenue.

Operating Costs

Operating costs were $4,761 for the three months ended August 31, 2011 compared to $50,102 for the three months ending August 31, 2010. The decrease in operating costs for the three month ended August 31, 2011 is due to lower production volume and a credit received from the operator in the current period.

Depletion

Depletion for the three months ending August 31, 2011 was $5,881 compared to depletion of $12,526 for the three months ending August 31, 2010. The decrease in depletion for the three months ended August 31, 2011 was a result of lower production volume.

Administrative Expenses

For the three months ending August 31, 2011 administrative expenditures were down $166,666 to $310,664 compared to $477,330 for the same period in 2010. The primary decrease in administrative expenses for the three months ending August 31, 2011 relate to consulting fee expense in the amount of $Nil compared to $326,511 in the prior period three month in 2010. The decrease in administrative expenditures were partially offset by a foreign exchange loss of $36,600 in the current period compared to $Nil in 2010, interest expense of $86,845 in the current period compared to $5,750 in the prior three month period, an increase in management fees of $17,250 to $18,750 for the three months ended August 31, 2011 compared to $1,500 in the three month period ended August 31, 2010 and an increase in professional fees of $7,400 to $55,958 compared to 48,558 in the prior period in 2010.

Gain on Disposal of Marketable Securities

During the three months ended August 31, 2011 the Company recorded a gain on disposal of marketable securities of $8,000 versus $Nil for the comparable period in 2010.

Net loss and comprehensive loss for the period

Net loss and comprehensive loss for the three months ending August 31, 2011 was $295,381 down $201,139 compared to $496,520 for the prior period in 2010.

Loss per share

The loss per share for the three months ending August 31, 2011 was $0.009 compared to $0.020 for the comparative same three month period in 2010.

CAPITAL EXPENDITURES

For the year ended August 31, 2011 the Company incurred exploration expenditures of $3,158,688 on its Matthews and Murphy Leases located in Zavala County, Texas.

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

FINANCING ACTIVITIES

During the year ended August 31, 2011, 500,000 common share purchase warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $35,000; 625,247 common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $44,475; and 2,575,000 common share purchase warrants were exercised at $0.20 expiring April 14, 2011 for proceeds of $515,000.

During the year ended August31, 2011 the Company received $2,878,736 and issued demand promissory notes bearing interest at 10% per annum. Interest is payable annually on the anniversary date of the notes.

During the year ended August 31, 2011 the Company paid $98,440 of secured notes and $110,000 loan payable.

LIQUIDITY AND CAPITAL RESOURCES

Cash as of August 31, 2011 was $165,266 compared to cash of $43,776 at August 31, 2010. During the year ended August 31, 2011 the Company received proceeds from the exercise of common share purchase warrants in the amount of $594,475 and received $2,878,736 and issued demand promissory notes bearing interest at a rate of 10% per annum.

For the year ended August 31, 2011 the primary use of funds was related to exploration expenditures incurred of $3,158,688 for the Company’s Matthews Lease and Murphy Lease located in Zavala County, Texas. In addition, the Company paid $98,440 in secured notes and repaid $110,000 loan payable. The Company’s working capital deficiency at August 31, 2011 is $4,870,621 compared to a working capital deficiency of $744,262 at August 31, 2010.

Our current assets of $337,098 as at August 31, 2011 ($98,162 as of August 31, 2010) include the following items: cash $165,266 ($43,776 as of August 31, 2010); marketable securities $1 ($1 as of August 31, 2010); accounts receivable $127,546 ($53,060 as of August 31, 20010); due from related party $Nil ($1,325 as of August 31, 2010) and prepaid expenses and deposits of $44,285 (Nil as of August 31, 2010).

Our current liabilities of $5,207,719 as of August 31, 2011 ($842,424 as of August 31, 2010) include the following items: accounts payable $1,258,839 ($488,741 as of August 31, 2010); due to shareholders $2,936,236 ($57,500 as of August 31, 2010); loan payable $Nil ($110,000 as of August 31, 2010); and secured notes payable of $1,012,644 ($186,183 as of August 31, 2010).

At August 31, 2011 the Company has outstanding the following common share purchase warrants: 10,525,474 warrants exercisable at $0.07 per share; 296,903 warrants exercisable at US$1.00 per share; 148,452 warrants exercisable at US$1.50 per share; 1,709,233 warrants exercisable at US$1.00 per share; and 50,000 warrants exercisable at US$1.25. If any of these common share purchase warrants are exercised it would generate additional capital for us.

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, 2011:

	Year ended August 31, 2011					As at August 31, 2011
	Interest and other income		Net (loss)			Oil and gas interests		Other assets
Canada	$	71,786	$	(696,643	)	$	243,000	$	264,611
United States		-		(55,914	)		8,898,128		72,487
Total	$	71,786	$	(752,557	)	$	9,141,128	$	337,098

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 (loss)			Oil and gas interests		Other assets
Canada	$	105,404	$	(688,709	)	$	314,000	$	68,141
United States		-		-			5,695,290		30,021
Total	$	105,404	$	(688,709	)	$	6,009,290	$	98,162

SEASONALITY AND TREND INFORMATION

RELATED PARTY TRANSACTIONS AND BALANCES

		2011				2010 (1)				2009 (1)
Management fees to the President and Director of the Company		$	56,250			$	24,000			$	18,000

(1)

Management fees to the former President of the Company.

At August 31, 2011 included in accounts payable are management fees payable to the President of $56,250 (2010 – Nil).

At August 31, 2011 the amount of directors’ fees included in accounts payable was $8,800 (2010 - $6,700).

COMMITMENTS AND CONTINGENCIES

The Company has drilling commitments on its Mathews Lease and Murphy Lease located in Zavala County, Texas, USA.

Mathews Lease, Zavala County, Texas, USA

The royalties payable under the Matthews Lease are 25%.

(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; and

(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”).

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

Murphy Lease, Zavala County, Texas, USA

The royalties payable under the Murphy Lease are 25%.

Secured Notes Payable

On August 31, 2010 the Company issued a US$175,000, 5% per annum secured promissory note to Source Re Work Program, Inc. (“Source”). The note was secured by the Eagleford’s interest in the Matthews Lease, Zavala County, Texas. US$100,000 of the note was due on February 28, 2011 and was repaid. The balance of US$75,000 (CDN $73,380) of the note together with accrued interest is due and payable on August 31, 2011. For the year ended August 31, 2011 interest of $6,115 was recorded and included in accounts payable (see Note 19).

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Operations and 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.

Significant Accounting Policies

Principles of Consolidation

Oil and Gas Interests

Developed oil and gas reserves - Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)	Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii)	Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction means is by not involving a well.

(i)	Reserves on any undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at great distances;

(ii)	Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedules to be drilled within five years, unless the specific circumstances justify a longer time; and

(iii)

Depletion and Depreciation

Depletion of oil and 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 oil and 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 of Long-Lived Assets

Revenue Recognition

Environmental and Site Restoration Costs

Foreign Currencies

Marketable Securities

Financial Instruments

Cash and cash equivalents are designated as “held-for-trading” and is measured at fair value, which approximates carrying value.

Accounts receivable are designated as “loans and receivable” and are carried at amortized cost. Accounts payable and accrued liabilities, secured notes payable and shareholder loans are designated as “other financial liabilities” and are carried at amortized cost.

Level 1 – fair values are based on quoted prices in active markets for identical assets or liabilities;

Level 2 – fair values are based on inputs other than quoted prices that are observable for the asset or liability, either directly (as prices) or indirectly (derived from prices); or

Level 3 – applies to assets and liabilities for inputs that are not based on observable market data, which are unobservable inputs.

Cash Equivalents

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

Estimates and Measurement Uncertainty

Areas where management is required to make significant estimates are as follows:

ii.

The provision for asset retirement obligations requires management to estimate the timing and amount of cash flows required to retire its Oil and Gas Interests.

iii.

iv.

The recognition of future income tax assets requires judgment as to whether future taxable income will be sufficient to realize the benefit of these tax assets.

Income Taxes

Non-Monetary Transactions

Stock-Based Compensation

The quoted market price of the Company’s shares on the date of issuance under any stock compensation plan is considered as fair value of the shares issued.

Loss Per Share

Warrants

CHANGE IN ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS

Change in Accounting Policies

Business Combinations

Future Accounting Pronouncements

Adoption of International Financial Accounting Standards (“IFRS”)

On January 1, 2011, public companies in Canada were required to adopt IFRS.

Public companies in Canada were required to adopt IFRS for the years beginning on or after January 1, 2011. For the company, the adoption date is September 1, 2011.

Consequently, effective September 1, 2011, the Company adopted IFRS as the basis for preparing its consolidated financial statements. The company will prepare its consolidated financial statements for the first quarter ending November 30, 2011 in accordance with IFRS, which will include comparative data for the prior year also prepared in accordance with IFRS as well as an opening IFRS balance sheet at September 1, 2010.

IFRS CONVERSION PLAN

There are significant accounting policy changes anticipated on adoption of IFRS which are described in more detail below. Most adjustments required on transition to IFRS will be made retrospectively against opening retained earnings as of the date of the first comparative balance sheet being September 1, 2010. In July 2009, the International Accounting Standards Board (“IASB”) issued amendments to IFRS 1 “First time adoption of IFRS” allowing additional exemptions for first-time adopters.

The IFRS conversion plan consists of three phases as identified below:

Phase 1 – Initial Scoping (Completed)

Eagleford’s Management has undertaken a preliminary high-level scoping study to consider the potential impact of the implementation of IFRS on the Company’s financial reporting. The initial scoping includes the identification of key differences between Canadian GAAP and IFRS, and high-level changes required in accounting policies, systems and processes.

Phase 2 – Detailed Assessment and Design (In progress)

Comprehensive documentation and analysis of changes in accounting standards, policies, processes and procedures identified on scoping from Phase 1.

Phase 3 – Implementation (In progress)

Implementation and execution of changes identified from Phase 2.

POTENTIAL IMPACT OF IFRS ADOPTION

Significant differences that have been identified between Canadian GAAP and IFRS that will impact the Company’s are:

IFRS 1 - First -time adoption of IFRS;

IAS 16 - Property, plant and equipment;

IFRS 6 – Exploration and evaluation assets;

IAS 36 - Impairment testing;

IAS 37 – Provision, contingencies liabilities and contingencies assets (Decommissioning costs); and

An increased level of disclosure requirements.

These differences have been identified based on the current IFRS standards issued and expected to be in effect on the date of transition. Certain IFRS standards may be modified, and as a result, the impact may be different than the Company’s current expectations. Management is currently determining the financial statement impact of these standards. The impact on the consolidated financial statements is not reasonably determinable at this time.

IFRS 1 - First Time Adoption of IFRS

The transition to IFRS requires the Company to apply IFRS 1, which prescribes requirements for preparing IFRS compliant financial statements in the first reporting period after the changeover date (July 1, 2011). IFRS 1 includes a requirement for retrospective application of each IFRS standard as if they were always in effect. IFRS 1 also mandates certain exemptions for retrospective application and provides optional exemptions from retrospective application to ease the transition to IFRS in the transition year.

This standard will have a significant impact on Eagleford’s consolidated financial statements, at least from the perspective of reconciliation from Canadian GAAP to IFRS. However, this standard has the potential to be most complex to implement and have the greatest financial statement impact depending on policies choices made by Eagleford.

IAS 16 - Property Plant and Equipment

Items of property, plant and equipment, which include petroleum and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into CGUs for impairment testing. The cost of property, plant and equipment at the date of transition to IFRS using the revaluation model, are expected to be recorded at their previous Canadian GAAP carrying amount under successful efforts, as allowed under the IFRS 1.

When significant parts of an item of property, plant and equipment, including petroleum and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

Gains and losses on disposal of an item of property, plant and equipment, including petroleum and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net within profit or loss.

The Company is currently evaluating the impact of this accounting standard.

IFRS 6 - Exploration and Evaluation Expenditures

Pre-acquisition expenditures on oil and gas assets are recognized as an expense in the statement of operations when incurred. In accordance with IFRS 6, exploration and evaluation costs are capitalized within intangible assets until the success or otherwise of the well or project has been established and subject to an impairment review. The costs of unsuccessful wells in an area are written off to the income statement: this is in accordance with the successful efforts accounting policy with Canadian GAAP but is also compatible with IAS 36 on the basis the asset is impaired.

Eagleford does not expect a significant material impact on its statement of financial position, however the Company is currently evaluating its policy options and applicable impact of these policies under IFRS.

IAS 36 - Impairment of Assets

IAS 36 uses the concept of cash generating units to accumulate asset carrying costs to test and measure impairment.

IFRS will require impairment testing to be performed at the cash generating unit level, which is lower than the current cost center level.

In addition, IAS 36 uses a one-step approach for testing and measuring asset impairments, with asset carrying values being compared to the higher of: value-in-use and fair value less costs to sell. Value-in-use is defined as the amount equal to the present value of future cash flows expected to be derived from the asset. In the absence of an active market, fair value less costs to sell may also be determined using discounted cash flows. The use of discounted cash flows under IFRS to test and measure asset impairment differs from Canadian GAAP, which uses undiscounted cash flows as an initial first step to test impairment.

Under IAS 36, impairment losses that were previously recognized may be reversed where circumstances change such that the impairment is reduced. This differs from Canadian GAAP, which prohibits the reversal of previously recognized impairment losses.

The Company is currently evaluating the impact of this accounting standard.

IAS 37 - Decommissioning Costs

Under IFRS, the recognition criteria for contingent liabilities are much more explicit than Canadian GAAP and may potentially require the booking of additional liabilities associated with the asset retirement obligations of Eagleford’s oil and gas assets. Liabilities for decommissioning and restoration are recognized for both legal and constructive obligations. Under IFRS, the estimated liability is calculated at each reporting period using estimates of risk-adjusted future cash outflows, discounted using the risk free rate whereas under Canadian GAAP the estimated liability is estimated using a credit-adjusted rate, rather than a risk free rate.

Changes in the estimated timing of cash flows necessary to discharge the obligation are added to or deducted from the cost of the related asset and the adjusted amounts are amortized prospectively over the estimated useful life of the asset. The measurement of the present value of the estimate (arising due to different discount rates used) is likely to be higher under IFRS as compared to Canadian GAAP.

Information Systems

It is expected that the conversion to IFRS will have a minimal impact on the Eagleford’s information system.

RECONCILIATION TO ACCOUNTING PRINCIPLES GENERALLY ACCEPTED IN THE UNITED STATES

The significant differences between Canadian GAAP and US GAAP which had any impact on the consolidated balance sheet and consolidated statement of cash flows are noted below.

Oil and Gas Interests

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

	2011			2010
Total assets according to Canadian GAAP	$	9,478,226		$	6,107,452
Additional impairment of oil and gas interests		(170,000	)		(50,000	)
Total assets according to US GAAP	$	9,308,226		$	6,057,452

	2011			2010
Total shareholders’ equity according to Canadian GAAP	$	4,220,299		$	4,239,777
Deficit adjustment per US GAAP
Additional impairment of oil and gas interests		(170,000	)		(50,000	)
Total shareholders’ equity according to US GAAP		4,050,299		$	4,189,777

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

	2011			2010			2009
Net loss according to Canadian GAAP	$	752,557		$	688,709		$	328,861
Add: Additional impairment of oil and gas interests		170,000			50,000			73,638
Net loss according to US GAAP	$	922,557		$	738,709		$	402,499
Loss per share, basic and diluted	$	(0.029	)	$	(0.030	)	$	(0.023	)
Shares used in the computation of loss per share		31,927,228			24,687,130			17,646,295

Adoption of New Accounting Policies

Future Accounting Pronouncements

1.	Transfers in and out of Levels 1 and 2. A reporting entity should disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers.

This Update provides amendments to Subtopic 820-10 that clarify existing disclosures as follows:

SUBSEQUENT EVENTS

On September 1, 2011 the Company repaid to Source, the secured promissory note in full in the amount of US$75,000 together with accrued interest of US$6,250.

Subsequent to the year ended August 31, 2011, the Company commenced drilling its Matthews/Dyami #2H well located in Zavala County, Texas.

Subsequent to the year ended August 31, 2011, the Company issued 639,297 common shares to promissory note holders as full settlement of interest due in the amount of US$166,000 and CDN$14,900.

OTHER MD&A REQUIREMENTS

(a)	Additional Information

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.

(b)	Share Capital and Contributed Surplus as at August 31, 2011 and the date of this MD&A.

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, 2008		10,471,739	$	467,604
February 5, 2009 private placement (note a)		2,600,000		67,600
February 25, 2009 private placement (note b)		1,000,256		26,007
February 27, 2009 acquisition (note c)		8,910,564		231,675
February 27, 2009 debt settlement (note d)		1,250,000		32,500
Balance at August 31, 2009		24,232,559		825,386
Exercise of warrants (note e)		2,100,000		197,400
August 31, 2010 acquisition, net of transaction costs (note f)		3,418,467		2,794,398
Balance August 31, 2010		29,751,026		3,817,184
Exercise of warrants (note h)		3,710,346		722,572
Issued as compensation (note i)		100,000		95,800
Balance August 31, 2011		33,561,372		4,635,556
Issued in settlement of debt (note j)		639,297		204,107
Balance as of the date of this MD&A		34,200,669	$	4,839,663

On December 10, 2011, 296,903 common share purchase warrants expired. The amount of $191,057 based on relative fair value using the Black Scholes model was re-allocated from warrants and recorded as an increase to contributed surplus.

(j) Subsequent to the year ended August 31, 2011 the Company issued 639,297 common shares to promissory note holders as full settlement of interest due in the amount of US$166,000 and CDN$14,900. The amount allocated to common shares was based on the share price at the time of issuance was $204,107.

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

	2011					2010					2009
Warrants	Number of Warrants			Weighted Average Price		Number of Warrants			Weighted Average Price		Number of Warrants		Weighted Average Price
Outstanding beginning of year		16,445,053		$	0.22		16,335,820		$	0.09		2,575,000	$	0.20
Issued		50,000			1.25		2,209,233			1.04		13,760,820		0.07
Exercised		(2,575,000	)		0.20		(2,100,000	)		0.07		-		-
Exercised		(1,113,346	)		0.07		-			-		-		-
Cancelled		(36,430	)		1.50		-			-		-		-
Cancelled		(18,215	)		1.25		-			-		-		-
Outstanding end of year		12,730,062		$	0.24		16,445,053		$	0.22		16,335,820	$	0.09

The following table summarizes the outstanding warrants as at August 31, 2011 and the date of this MD&A:

Date	Number of Warrants			Note	Exercise Price		Expiry Date	Warrant Value ($)
		1,000,000		(note a, e, h)	$	0.07	February 5, 2014	$	24,000
		400,256		(note b, h)	$	0.07	February 25, 2014		9,606
		9,125,218		(note c, d, e, h)	$	0.07	February 27, 2014		219,031
		296,903		(note g)	US$	1.00	December 10, 2011		191,057
		148,452		(note g)	US$	1.50	June 10, 2012		99,935
		1,709,233		(note f)	US$	1.00	August 31, 2014		1,388,833
		50,000		(note i)	US$	1.25	May 4, 2012		37,054
Balance August 31, 2011		12,730,062						$	1,969,516
		(296,903	)	(note g)	US$	1.00	December 10, 2011		(191,057	)
Balance at the date of this MD&A		12,433,159						$	1,778,459

The fair value of the warrants issued during the year ended August 31, 2011, 2010 and 2009 were estimated on the date of issue using the Black-Scholes pricing model with the following assumptions:

Black-Scholes Assumptions used	2011
Risk-free interest rate		1.7	%
Expected volatility		254	%
Expected life (years)		1
Dividend yield		0	%
Fair value of the warrants issued on May 4, 2011	$	0.74

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

The weighted average basic and diluted shares outstanding at August 31, 2011, 2010 and 2009 is as follows:

Weighted Average Shares Outstanding	2011		2010		2009
Weighted average shares outstanding, basic		31,927,228		24,687,130		17,646,295
Dilutive effect of warrants		13,273,114		16,008,996		9,749,557
Weighted average shares outstanding, diluted		45,200,342		40,696,126		27,395,852

Stock Option Plan

Contributed Surplus

Contributed surplus transactions for the respective years are as follows:

	Amount
Balance, August 31, 2008 and 2009	$	38,000
Imputed interest		5,750
Balance, August 31, 2010		43,750
Warrants cancelled		35,519
Imputed interest		5,750
Balance, August 31, 2011		85,019
Warrants expired		191,057
Premium on common shares issued as debt settlement		(3,239	)
Balance as of the date of this MD&A	$	272,837

(c)	Disclosure Controls and Procedures

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 Consolidated Financial Statements for the year ended August 31, 2011 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 on SEDAR at www.sedar.com.