February 11, 2011 - 20-F: Annual and transition report of foreign private issuers [Sections 13 or 15(d)]

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

¨REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended August 31, 2010

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______________________ to ______________________

¨ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Date of event requiring this shell company report ____________________________

Commission File Number: 0-53646

EAGLEFORD ENERGY INC.

(Exact name of Registrant as specified in its charter)

Ontario, Canada

(Jurisdiction of incorporation or organization)

1 King Street West, Suite 1505

Toronto, Ontario, Canada, M5H 1A1

(Address of principal executive offices)

James Cassina, Telephone (416) 364-4039, Fax (416) 364-8244

1 King Street West, Suite 1505, Toronto, Ontario, Canada, M5H 1A1

(Name, telephone, e-mail and/or facsimile number and address of company contact person)

Securities registered or to be registered pursuant to section 12(b) of the Act: None

Securities registered or to be registered pursuant to Section 12(g) of the Act: Common Stock, no par value

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

(Title of Class)

The number of outstanding shares of the issuer’s common stock as of August 31, 2010 was 29,751,026 shares.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

If this report is an annual or a transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨

Accelerated filer ¨

Non-accelerated filer x

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP ¨

International Financial Reporting Standards

by the International Accounting Standards Board ¨

Other x

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. ‘

Item 17 x Item 18 ¨

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Table of Contents

GENERAL		1
NOTE REGARDING FORWARD-LOOKING STATEMENTS		1
PART I		1
ITEM 1	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS	1
A.	DIRECTORS AND SENIOR MANAGEMENT	1
B.	ADVISERS	1
C.	AUDITORS	1
ITEM 2	OFFER STATISTICS AND EXPECTED TIMETABLE	2
A.	OFFER STATISTICS	2
B.	METHOD AND EXPECTED TIMETABLE	2
ITEM 3	KEY INFORMATION	2
A.	SELECTED FINANCIAL DATA	2
B.	CAPITALIZATION AND INDEBTEDNESS	5
C.	REASONS FOR THE OFFER AND USE OF PROCEEDS	5
D.	RISK FACTORS	5
ITEM 4	INFORMATION ON THE COMPANY	12
A.	HISTORY AND DEVELOPMENT OF THE COMPANY	13
B.	BUSINESS OVERVIEW	17
C.	ORGANIZATIONAL STRUCTURE	21
D.	PROPERTY, PLANTS AND EQUIPMENT	21
ITEM 4A	UNRESOLVED STAFF COMMENTS	26
ITEM 5	OPERATING AND FINANCIAL REVIEW AND PROSPECTS	26
A.	OPERATING RESULTS	44
B.	LIQUIDITY AND CAPITAL RESOURCES	48
C.	RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES	49
D.	TREND INFORMATION	49
E.	OFF-BALANCE SHEET ARRANGEMENTS	50
F.	TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS	51
G.	SAFE HARBOR	53
ITEM 6.	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	53
A.	DIRECTORS AND SENIOR MANAGEMENT	53
B.	COMPENSATION	54
C.	BOARD PRACTICES	57
D.	EMPLOYEES	64
E.	SHARE OWNERSHIP	64
ITEM 7	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	66
A.	MAJOR SHAREHOLDERS	66
B.	RELATED PARTY TRANSACTIONS	67
C.	INTERESTS OF EXPERTS AND COUNSEL	68
ITEM 8	FINANCIAL INFORMATION	68
A.	CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION	68
B.	SIGNIFICANT CHANGES	68
ITEM 9	THE OFFER AND LISTING	68
A.	OFFER AND LISTING DETAILS	68
B.	PLAN OF DISTRIBUTION	69

C.	MARKETS	69
D.	SELLING SHAREHOLDERS	69
E.	DILUTION	69
F.	EXPENSES OF THE ISSUE	69
ITEM 10	ADDITIONAL INFORMATION	69
A.	SHARE CAPITAL	69
B.	MEMORANDUM AND ARTICLES OF ASSOCIATION	69
C.	MATERIAL CONTRACTS	71
D.	EXCHANGE CONTROLS	72
E.	TAXATION	73
F.	DIVIDENDS AND PAYING AGENTS	76
G.	STATEMENT BY EXPERTS	76
H.	DOCUMENTS ON DISPLAY	76
I.	SUBSIDIARY INFORMATION	76
ITEM 11	QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK	76
ITEM 12	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	78
A.	DEBT SECURITIES	78
B.	WARRANTS AND RIGHTS	78
C.	OTHER SECURITIES	78
D.	AMERICAN DEPOSITORY SHARES	78
PART II		78
ITEM 13	DEFAULTS, DIVIDENDS ARREARAGES AND DELINQUENCIES	78
ITEM 14	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	78
ITEM 15	CONTROLS AND PROCEDURES	79
ITEM 16	[RESERVED]	80
A.	AUDIT COMMITTEE FINANCIAL EXPERT	80
B.	CODE OF ETHICS	80
C.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	81
D.	EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES	81
E.	PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS	82
F.	CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT	82
G.	CORPORATE GOVERNANCE	82
PART III		82
ITEM 17	FINANCIAL STATEMENTS	82
ITEM 18	FINANCIAL STATEMENTS	82
ITEM 19	EXHIBITS	82

GENERAL

In this Annual Report, references to “we”, “us”, “our”, the “Company”, and “Eagleford” mean Eagleford Energy Inc., and its subsidiaries, unless the context requires otherwise.

We use the Canadian dollar as our reporting currency and our financial statements are prepared in accordance with Canadian generally accepted accounting principles. Note 16 to our annual consolidated financial statements provide a reconciliation of our financial statements to United States generally accepted accounting principles. All monetary references in this document are to Canadian dollars, unless otherwise indicated. All references in this document to “dollars” or “$” or “CDN$” mean Canadian dollars, unless otherwise indicated, and references to “US$” mean United States dollars.

Except as noted, the information set forth in this Annual Report is as of January 31, 2011 and all information included in this document should only be considered accurate as of such date. Our business, financial condition or results of operations may have changed since that date.

NOTE REGARDING FORWARD-LOOKING STATEMENTS

The statements contained in Item 4 – “Information on the Company”, Item 5 – “Operating and Financial Review and Prospects” and Item 11 – “Quantitative and Qualitative Disclosures About Market Risk” are inherently subject to a variety of risks and uncertainties that could cause actual results, performance or achievements to differ significantly.

PART I

ITEM 1

IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

A. DIRECTORS AND SENIOR MANAGEMENT

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

B. ADVISERS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

C. AUDITORS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 2

OFFER STATISTICS AND EXPECTED TIMETABLE

A. OFFER STATISTICS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

B. METHOD AND EXPECTED TIMETABLE

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 3

KEY INFORMATION

A. SELECTED FINANCIAL DATA

The following table presents selected financial data derived from our Audited Consolidated Financial Statements for the fiscal years ended August 31, 2010, 2009, 2008, 2007 and 2006. You should read this information in conjunction with our Audited Consolidated Financial Statements and related notes (Item 17), as well as Item 4: “Information on the Company” and Item 5: “Operating and Financial Review and Prospects” of this Annual Report.

Our consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) in Canadian dollars. Note 17 to the audited annual consolidated financial statements provides descriptions of material measurement differences between Canadian GAAP and US generally accepted accounting principles (“US GAAP”) as they relate to us and a reconciliation of our consolidated financial statements to US GAAP.

The selected consolidated statement of operations data set forth below for the years ended August 31, 2010, 2009, 2008 and 2007 and the selected consolidated balance sheet data set forth below as of August 31, 2010, 2009, 2008 and 2007 is derived from our consolidated financial statements, which have been audited by Schwartz Levitsky Feldman LLP, Chartered Accountants, Toronto, Canada all of which are attached to and forming part of this Annual Report under Item 17 – Financial Statements.

The selected consolidated statement of operations data set forth below for the year ended August 31, 2006 and the selected consolidated balance sheet data set forth below as of August 31, 2006 is derived from our consolidated financial statements, which have been audited by BDO Dunwoody LLP, Chartered Accountants, Toronto, Canada.

EAGLEFORD ENERGY INC.

Presented Pursuant to Canadian Generally Accepted Accounting Principles

(STATED IN CANADIAN DOLLARS)

	YEARS ENDED AUGUST 31,
	2010			2009			2008			2007			2006
CONSOLIDATED STATEMENT OF OPERATIONS DATA
Revenue	$	105,375		$	56,199		$	292		$	637		$	760
Income (loss) from oil and gas operations		(35,586	)		(53,626	)		268			541			311
Administrative expenses		653,153			276,815			50,782			40,691			51,463
Operating loss for the year		(688,739	)		(330,441	)		(50,514	)		(40,150	)		(51,152	)
Interest income		30			1,580			-			205			-
Net loss and comprehensive loss for the year		(688,709	)		(328,861	)		(50,514	)		(39,945	)		(51,152	)
Loss per common share basic and diluted		(0.028	)		(0.019	)		(0.006	)		(0.006	)		(0.008	)
Weighted average common shares
outstanding		24,687,130			17,646,295			7,955,482			6,396,739			6,396,739
BALANCE SHEET INFORMATION
Working capital (deficiency)		(744,262	)		(137,372	)		(93,634	)		(483,860	)		(444,839	)
Total assets		6,107,452			600,327			208,486			9,746			8,298
Total shareholders’ equity (deficiency)		4,239,777			265,994			(93,186	)		(482,860	)		(442,915	)

The following table sets forth our selected consolidated financial data as set forth in the preceding table, as reconciled pursuant to United States Generally Accepted Accounting Principles:

EAGLEFORD ENERGY INC.

Presented Pursuant to United States Generally Accepted Accounting Principles

(STATED IN CANADIAN DOLLARS)

	YEARS ENDED AUGUST 31,
	2010			2009			2008			2007			2006
CONSOLIDATED STATEMENT OF OPERATIONS DATA
Revenue	$	105,375		$	56,199		$	292		$	637		$	760
Income (loss) from operations		(35,586	)		(53,626	)		268			541			311
Administrative expenses		653,153			276,815			50,782			40,691			51,463
Operating loss for the year		(688,739	)		(330,441	)		(50,514	)		(40,150	)		(51,152	)
Interest income		30			1,580			-			205			-
Net loss and comprehensive loss according to Canadian GAAP		(688,709	)		(328,861	)		(50,514	)		(39,945	)		(51,152	)
Unrealized gain on marketable securities		-			-			-			-			(171	)
Additional impairment of oil and gas interests		(50,000	)		(73,638	)		-			-			-
Comprehensive loss according to US GAAP		(738,709	)		(402,499	)		(50,514	)		(39,945	)		(51,323	)
Net loss per common share basic and diluted according to US GAAP		(0.030	)		(0.023	)		(0.006	)		(0.006	)		(0.008	)
Shares used in the computation of basic and diluted earnings per share		24,687,130			17,646,295			7,955,482			6,396,739			6,396,739
BALANCE SHEET INFORMATION
Working capital deficiency		(744,262	)		(137,372	)		(93,634	)		(483,860	)		(444,840	)
Total assets per Canadian GAAP		6,107,452			600,327			208,486			9,746			8,298
Unrealized gain on marketable securities		-			-			-			-			-
Write-down of marketable securities		-			-			-			-			(1	)
Additional impairment of oil and gas interests		(50,000	)		(73,638	)		-			-			-
Total assets per US GAAP		6,057,452			526,689			208,486			9,746			8,297
Total shareholders’ equity (deficiency) per Canadian GAAP		4,239,777			265,994			(93,186	)		(482,860	)		(442,915	)
Accumulated other comprehensive income:		-			-			-			-			-
Unrealized gain on marketable securities		-			-			-			-			(1	)
Additional impairment of oil and gas interests		(50,000	)		(73,638	)		-			-			-
Total shareholders’ equity (deficiency) per US GAAP		4,189,777			192,356			(93,186	)		(482,860	)		(442,916	)
OTHER FINANC IAL DATA
Cash flow provided by (used in):
Operating activities		(219,320	)		(172,333	)		(50,414	)		(268	)		(17,523	)
Investing activities		(21,228	)		80,499			-			-			11,512
Financing activities		111,419			62,013			252,188			-			-

Differences between Generally Accepted Accounting Principles (GAAP) in Canada and the United States

For the year ended August 31, 2010 the preparation of our Audited Consolidated Financial Statements in accordance with Canadian GAAP with a reconciliation to US GAAP recorded an additional impairment in oil and gas interests of $50,000 on the consolidated balance sheet and on the consolidated statement of loss, comprehensive loss and deficit. For the year ended August 31, 2009 the preparation of our Audited Consolidated Financial Statements in accordance with Canadian GAAP with a reconciliation to US GAAP recorded an additional impairment in oil and gas interests of $73,638 on the consolidated balance sheet and on the consolidated statement of loss, comprehensive loss and deficit. For the years ended August 31, 2008 and 2007 the preparation of our Audited Consolidated Financial Statements in accordance with US GAAP would not have resulted in differences to the Consolidated Balance Sheet or Consolidated Statement of Loss, Comprehensive Loss and Deficit from our Audited Consolidated Financial Statements prepared using Canadian GAAP. For the years ended August 31, 2006 the preparation of our Audited Consolidated Financial Statements in accordance with US GAAP recorded an unrealized (loss) gain on marketable securities in accumulated other comprehensive (loss) income on the consolidated balance sheet and the consolidated statement of loss, comprehensive loss and deficit of $(1).

Recently Issued United States Accounting Standards are included in Note 17 to our August 31, 2010 Audited Consolidated Financial Statements.

Exchange Rate Information

The exchange rate between the Canadian dollar and the U.S. dollar was CDN$1.00 per US$0.9989 (or US$0.9989 per CDN$1.00) as of January 31, 2011.

The average exchange rates for the periods indicated below (based on the daily noon buying rate for cable transfers in New York City certified for customs purposes by the Federal Reserve Bank of New York) are as follows:

	YEARS ENDED AUGUST 31,
	2010		2009		2008		2007		2006
Average exchange rate CDN$ per US$1.00		1.0640		1.0967		1.0631		1.0560		1.1066

Average exchange rate US$ per CDN$1.00		0.9360		0.9033		0.9369		0.9440		0.8934

The high and low exchange rates between the Canadian dollar and the U.S. dollar for each of the six months ended January 31, 2011are as follows:

Month	Exchange rate CDN$ per US$1.00
	Low		High
January 2011		0.9864		1.0020
December 2010		1.0004		1.0176
November 2010		1.0012		1.0266
October 2010		1.0028		1.0298
September 2010		1.0219		1.0520
August 2010		1.0154		1.0640

B. CAPITALIZATION AND INDEBTEDNESS

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

C. REASONS FOR THE OFFER AND USE OF PROCEEDS

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

D. RISK FACTORS

Our securities are highly speculative and subject to a number of risks. You should not consider an investment in our securities unless you are capable of sustaining an economic loss of the entire investment. In addition to the other information presented in this Annual Report, the following risk factors should be given special consideration when evaluating an investment in our securities.

General Risk Factors

We require additional capital which may not be available to us on acceptable terms, or at all. Both the exploration and development of oil and gas reserves can be capital-intensive businesses. We intend to satisfy any additional working capital requirements from cash flow and by raising capital through public or private sales of debt or equity securities, debt financing or short-term loans, or a combination of the foregoing. We have no current arrangements for obtaining additional capital, and may not be able to secure additional capital, or on terms which will not be objectionable to us or our shareholders. Under such circumstances, our failure or inability to obtain additional capital on acceptable terms or at all could have a material adverse effect on us.

We have a history of losses and a limited operating history as an oil and gas exploration and development company which makes it more difficult to evaluate our future prospects. To date, we have incurred significant losses. We have a limited operating history upon which any evaluation of us and our long-term prospects might be based. We are subject to the risks inherent in the oil and gas industry, as well as the more general risks inherent to the operation of an established business. We and our prospects must be considered in light of the risks, expenses and difficulties encountered by all companies engaged in the extremely volatile and competitive oil and gas markets. Any future success we might achieve will depend upon many factors, including factors, which may be beyond our control. These factors may include changes in technologies, price and product competition, developments and changes in the international oil and gas market, changes in our strategy, changes in expenses, fluctuations in foreign currency exchange rates, general economic conditions, and economic and regulatory conditions specific to the areas in which we compete. To address these risks, we must, among other things, comply with environmental regulations; expand our portfolio of proven oil and gas properties and negotiate additional working interests and prospect participations; and expand and replace depleting oil and gas reserves.

We have significant debt which may make it more difficult for us to obtain future financing or engage in business combination transactions. We have significant debt obligations. The degree to which this indebtedness could have consequences on our future prospects includes the effect of such debts on our ability to obtain financing for working capital, capital expenditures or acquisitions. The portion of available cash flow that will need to be dedicated to repayment of indebtedness will reduce funds available for expansion. If we are unable to meet our debt obligations through cash flow from operations, we may be required to refinance or adopt alternative strategies to reduce or delay capital expenditures, or seek additional equity capital.

Our future operating results are subject to fluctuation based upon factors outside of our control. Our operating results may in the future fluctuate significantly depending upon a number of factors including industry conditions, oil and gas prices, rate of drilling success, rates of production from completed wells and the timing of capital expenditures. Such variability could have a material adverse effect on our business, financial condition and results of operations. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit our future ability to participate in exploration or to participate in economically attractive oil and gas projects.

Our operating results will be affected by foreign exchange rates. Since energy commodity prices are primarily priced in US dollars, a portion of our revenue stream is affected by U.S./Canadian dollar exchange rates. We do not hedge this exposure. While to date this exposure has not been material, it may become so in the future.

Our inability to manage our expected growth could have a material adverse effect on our business operations and prospects. We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. The ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expend, train and manage our employee base. The inability to deal with this growth could have a material adverse impact on our business, operations and prospects.

To compete in our industry, we must attract and retain qualified personnel. Our ability to continue our business and to develop a competitive edge in the marketplace depends, in large part, on our ability to attract and retain qualified management and personnel. Competition for such personnel is intense, and we may not be able to attract and retain such personnel which may negatively impact our share price. We do not have key-man insurance on any of our employees, directors or senior officers and we do not have written employment agreements with any of our employees, directors or senior officers.

We must continue to institute procedures designed to avoid potential conflicts involving our officers and directors. Some of our directors and officers are or may serve on the board of directors of other companies from time to time. Pursuant to the provisions of the Business Corporations Act ( Ontario ), our directors and senior officers must disclose material interests in any contract or transaction (or proposed contract or transaction) material to us. To avoid the possibility of conflicts of interest which may arise out of their fiduciary responsibilities to each of the boards, all such directors have agreed to abstain from voting with respect to a conflict of interest between the applicable companies. In appropriate cases, we will establish a special committee of independent directors to review a matter in which several directors, or members of management, may have a conflict.

We rely on the expertise of certain persons and must insure that these relationships are developed and maintained. We are dependent on the advice and project management skills of various consultants and joint venture partners contracted by us from time to time. Our failure to develop and maintain relationships with qualified consultants and joint venture partners will have a material adverse effect on our business and operating results.

We must indemnify our officers and directors against certain actions. Our articles contain provisions that state, subject to applicable law, we must indemnify every director or officer, subject to the limitations of the Business Corporations Act (Ontario), against all losses or liabilities that our directors or officers may sustain or incur in the execution of their duties. Our articles further state that no director or officer will be liable for any loss, damage or misfortune that may happen to, or be incurred by us in the execution of his duties if he acted honestly and in good faith with a view to our best interests. Such limitations on liability may reduce the likelihood of litigation against our officers and directors and may discourage or deter our shareholders from suing our officers and directors based upon breaches of their duties to us, though such an action, if successful, might otherwise benefit us and our shareholders.

We do not currently maintain a permanent place of business within the United States. A majority of our directors and officers are nationals or residents of countries other than the United States, and all or a substantial portion of such persons' assets are located outside the United States. As a result, it may be difficult for investors to enforce within the United States any judgments obtained against our company or our officers or directors, including judgments predicated upon the civil liability provisions of the securities laws of the United States or any state thereof.

The global financial crisis is expected to cause petroleum and natural gas prices to remain volatile for the near future. Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions worsened in 2008 and are continuing into 2011, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and will impact the performance of the global economy going forward. Petroleum and natural gas prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing global credit and liquidity concerns.

Since our sole executive officer does not devote his full time to the performance of his Company duties, he may engage in other work activities to our detriment. James Cassina, our sole executive officer, devotes approximately 75% of his work time to the performance of his Company duties. Although he has an obligation to perform his duties in a manner consistent with our best interests and through his stock ownership in the Company, is incentivized to do so, may encounter conflicts regarding the availability and use of his work time. Although there are no such present conflicts, the development thereof could have a material adverse effect on us.

Risks Factors Relating to Our Common Stock

Our stockholders may have difficulty selling shares of our common stock as there is a limited public trading market for such stock. There is only a limited public market for our common stock, and no assurance can be given that a broad or active public trading market will develop in the future or, if developed, that it will be sustained. Our common stock trades on the Over-the-Counter Bulletin Board. In addition, our common stock has not been qualified under any applicable state blue-sky laws, and we are under no obligation to so qualify or register our common stock, or otherwise take action to improve the public market for such securities. Our common stock could have limited marketability due to the following factors, each of which could impair the timing, value and market for such securities: (i) lack of profits, (ii) need for additional capital, (ii) limited public market for such securities; (iii) the applicability of certain resale requirements under the Securities Act; and (iv) applicable blue sky laws and the other factors discussed in this Risk Factors section.

Possible volatility of stock price. The market price for our common stock may be volatile and is subject to significant fluctuations in response to a variety of factors, including the liquidity of the market for the common stock, variations in our quarterly operating results, regulatory or other changes in the oil and gas industry generally, announcements of business developments by us or our competitors, litigation, changes in operating costs and variations in general market conditions. Because we have a limited operating history, the market price for our common stock may be more volatile than that of a seasoned issuer. Changes in the market price of our securities may have no connection with our operating results. No predictions or projections can be made as to what the prevailing market price for our common stock will be at any time.

We do not anticipate paying dividends on our common stock. We presently plan to retain all available funds for use in our business, and therefore do not plan to pay any cash dividends with respect to our securities in the foreseeable future. Hence, investors in our common stock should not expect to receive any distribution of cash dividends with respect to such securities for the foreseeable future.

Our shareholders may experience dilution of their ownership interests because of our future issuance of additional shares of common stock. Our constating documents authorize the issuance of an unlimited number of shares of common stock, without par value. In the event that we are required to issue additional shares of common stock or securities exercisable for or convertible into additional shares of common stock, enter into private placements to raise financing through the sale of equity securities or acquire additional oil and gas property interests in the future from the issuance of shares of our common stock to acquire such interests, the interests of our existing shareholders will be diluted and existing shareholders may suffer dilution in their net book value per share depending on the price at which such securities are sold. If we do issue additional shares, it will cause a reduction in the proportionate ownership and voting power of all existing shareholders.

At the Annual and Special Meeting of Shareholders to be held on February 24, 2011, shareholders will be asked to approve a resolution permitting us to issue up 30,851,026 additional shares of common stock by way of private placements, acquisitions or equity credit lines to be completed on or before February 24, 2012.

At the Annual and Special Meeting of Shareholders to be held on February 24, 2011, shareholders will be asked to approve a resolution authorizing us to consolidate our issued and outstanding common shares on an up to one (1) for four (4) basis, or divide our issued and outstanding common shares on an up to four (4) for one (1) basis.

At the Annual and Special Meeting of Shareholders to be held on February 24, 2011, shareholders will be asked to approve a resolution authorizing us to increase the maximum aggregate number of common shares reserved for issuance under our Stock Option Plan, as amended, (the “Plan”) to an amount equal to 20% of the 30,851,026 shares issued and outstanding as of January 14, 2011, the date of the Notice of Meeting and Management Information Circular (or a total of 6,107,205 shares).

As of the date of this Annual Report, no such options are issued.

Prospective investors in our Company are urged to seek independent investment advice. Independent legal, accounting or business advisors (i) have not been appointed by, and have not represented or held themselves out as representing the interests of prospective investors in connection with this Annual Report, and (ii) have not “expertized” or held themselves out as “expertizing” any portion of this Annual Report, nor is our legal counsel providing any opinion in connection with us, our business or the completeness or accuracy of this Annual Report. Neither we nor any of our respective officers, directors, employees or agents, including legal counsel, make any representation or expresses any opinion (i) with respect to the merits of an investment in our common stock, including without limitation the proposed value of our common stock; or (ii) that this Annual Report provides a complete or exhaustive description of us, our business or relevant risk factors which an investor may now or in the future deem pertinent in making his, her or its investment decision. Any prospective investor in our common stock is therefore urged to engage independent accountants, appraisers, attorneys and other advisors to (a) conduct such due diligence review as such investor may deem necessary and advisable, and (b) to provide such opinions with respect to the merits of an investment in our Company and applicable risk factors upon which such investor may deem necessary and advisable to rely. We will fully cooperate with any investor who desires to conduct such an independent analysis so long as we determine, in our sole discretion, that such cooperation is not unduly burdensome.

Applicable SEC rules governing the trading of “penny stocks” will limit the trading and liquidity of our common stock and may affect the trade price for our common stock. The Securities and Exchange Commission (“SEC”) has adopted rules which generally define "penny stock" to be any equity security that has a market price (as defined) of less than US$5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities will be covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and "accredited investors". The term "accredited investor" refers generally to institutions with assets in excess of US$5,000,000 or individuals with a net worth in excess of US$1,000,000 or annual income exceeding US$200,000 or US$300,000 jointly with their spouse.

The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation.

In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the shares that are subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We expect that the penny stock rules will discourage investor interest in and limit the marketability of our common shares.

In addition to the "penny stock" rules described above, The Financial Industry Regulatory Authority (“FINRA”) has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and other information. Under interpretations of these rules, the FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. The FINRA requirements will make it more difficult for broker-dealers to recommend that their customers buy our common shares, which may limit your ability to buy and sell our shares and have an adverse effect on the market for our shares.

Risks Factors Relating to Our Business

Our future success is dependent upon our ability to locate, obtain and develop commercially viable oil and gas deposits. Our future success is dependent upon our ability to economically locate commercially viable oil and gas deposits. We may not be able to consistently identify viable prospects, and such prospects, if identified, may not be commercially exploitable. Our inability to consistently identify and exploit commercially viable hydrocarbon deposits would have a material and adverse effect on our business and financial position.

Exploratory drilling activities are subject to substantial risks. Our expected revenues and cash flows will be principally dependent upon the success of any drilling and production from prospects in which we participate. The success of such prospects will be determined by the economical location, development and production of commercial quantities of hydrocarbons. Exploratory drilling is subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected formation and drilling conditions, pressure or other irregularities in formations, blowouts, equipment failures or accidents, as well as weather conditions, compliance with governmental requirements or shortages or delays in the delivery of equipment. Our inability to successfully locate and drill wells that will economically produce commercial quantities of oil and gas could have a material adverse effect on our business and, financial position.

Our drilling and exploration plans will be subject to factors beyond our control. A prospect is a property that has been identified based on available geological and geophysical information that indicates the potential for hydrocarbons. Whether we ultimately drill a property may depend on a number of factors including funding; the receipt of additional seismic data or reprocessing of existing data; material changes in oil or gas prices; the costs and availability of drilling equipment; the success or failure of wells drilled in similar formations or which would use the same production facilities; changes in estimates of costs to drill or complete wells; our ability to attract industry partners to acquire a portion of our working interest to reduce exposure to drilling and completion costs; decisions of our joint working interest owners; and restrictions under provincial regulators.

Our operating results are subject to oil and natural gas price volatility. Our profitability, cash flow and future growth will be affected by changes in prevailing oil and gas prices. Oil and gas prices have been subject to wide fluctuations in recent years in response to changes in the supply and demand for oil and natural gas, market uncertainty, competition, regulatory developments and other factors which are beyond our control. It is impossible to predict future oil and natural gas price movements with any certainty. We do not engage in hedging activities. As a result, we may be more adversely affected by fluctuations in oil and gas prices than other industry participants that do engage in such activities. An extended or substantial decline in oil and gas prices would have a material adverse effect on our access to capital, and our financial position and results of operations.

Unforeseen title defects may result in a loss of entitlement to production and reserves. Although we conduct title reviews in accordance with industry practice prior to any purchase of resource assets, such reviews do not guarantee that an unforeseen defect in the chain on title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized.

Estimates of reserves and predictions of future events are subject to uncertainties. Certain statements included in this Annual Report contain estimates of our oil and gas reserves and the discounted future net revenues from those reserves, as prepared by independent petroleum engineers or us. There are numerous uncertainties inherent in such estimates including many factors beyond our control. The estimates are based on a number of assumptions including constant oil and gas prices, and assumptions regarding future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves. Such estimates are inherently imprecise indications of future net revenues, and actual results might vary substantially from the estimates based on these assumptions. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves. In addition, our reserves might be subject to revisions based upon future production, results of future exploration and development, prevailing oil and gas prices and other factors. Moreover, estimates of the economically recoverable oil and gas reserves, classifications of such reserves and estimates of future net cash flows prepared by independent engineers at different times may vary substantially. Information about reserves constitutes forward-looking statements.

The success of our business is dependent upon our ability to replace reserves. Our future success depends upon our ability to find, develop and acquire oil and gas reserves that are economically recoverable. As a result we must locate, acquire and develop new oil and gas reserves to replace those being depleted by production. Without successful funding for acquisitions and exploration and development activities, our reserves will decline. We may not be able to find and develop or acquire additional reserves at an acceptable cost.

Most of our competitors have substantially greater financial, technical, sales, marketing and other resources than we do. We engage in the exploration for and production of oil and gas, industries which are highly competitive. We compete directly and indirectly with oil and gas companies in our exploration for and development of desirable oil and gas properties. Many companies and individuals are engaged in the business of acquiring interests in and developing oil and gas properties in the United States and Canada, and the industry is not dominated by any single competitor or a small number of competitors. Many of such competitors have substantially greater financial, technical, sales, marketing and other resources, as well as greater historical market acceptance than we do. We will compete with numerous industry participants for the acquisition of land and rights to prospects, and for the equipment and labor required to operate and develop such prospects. Competition could materially and adversely affect our business, operating results and financial condition. Such competitive disadvantages could adversely affect our ability to participate in projects with favorable rates of return.

Shortages of supplies and equipment could delay our operations and result in higher operating and capital costs. Our ability to conduct operations in a timely and cost effective manner is subject to the availability of natural gas and crude oil field supplies, rigs, equipment and service crews. Although none are expected currently, any shortage of certain types of supplies and equipment could result in delays in our operations as well as in higher operating and capital costs.

Our business is subject to interruption from severe weather. Presently, our operations are conducted principally in the central region of Alberta, Canada and in Southwest Texas. The weather in these areas and other areas in which we may operate in the future can be extreme and can cause interruption or delays in our drilling and construction operations.

We are dependent on third-party pipelines and would experience a material adverse effect on our operations were our access to such pipelines be curtailed or the rates charged for use thereof materially increased. Substantially all our sales of natural gas production are effected through deliveries to local third-party gathering systems to processing plants. In addition, we rely on access to inter-provincial pipelines for the sale and distribution of substantially all of our gas. As a result, a curtailment of our sale of natural gas by pipelines or by third-party gathering systems, an impairment of our ability to transport natural gas on inter-provincial pipelines or a material increase in the rates charged to us for the transportation of natural gas by reason of a change in federal or provincial regulations or for any other reason, could have a material adverse effect upon us. In such event, we would have to obtain other transportation arrangements. We may not have economical transportation alternatives and it may not be feasible for us to construct pipelines. In the event such circumstances were to occur, our operating netbacks from the affected wells would be suspended until, and if, such circumstances could be resolved.

Our business is subject to operating hazards and uninsured risks. The oil and gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured formations, adverse weather conditions, governmental and political actions, premature reservoir declines, and environmental hazards such as oil spills, gas leaks and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by us could have a material adverse impact on us. Insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not insured or insured fully could have a material adverse effect on our financial condition.

Our business is subject to restoration, safety and environmental risk. Our present operations are primarily in western Canada and southwest Texas and certain laws and regulations exist that require companies engaged in petroleum activities to obtain necessary safety and environmental permits to operate. Such legislation may restrict or delay us from conducting operations in certain geographical areas. Further, such laws and regulations may impose liabilities on us for remedial and clean-up costs, or for personal injuries related to safety and environmental damages, such liabilities collectively referred to as “asset retirement obligations”. While our safety and environmental activities have been prudent in managing such risks, we may not always be successful in protecting us from the impact of all such risks.

The termination or expiration of any of our licenses and leases may have a material adverse effect on our results of operations. Our properties are held in the form of licenses and leases and working interests in licenses and leases. If we, or the holder of the license or lease, fail to meet the specific requirement of a license or lease, the license or lease may terminate or expire. We may not meet the obligations required to maintain each license or lease. The termination or expiration of our licenses or leases or the working interests relating to a license or lease may have a material adverse effect on our results of operations and business.

Compliance with the Kyoto Protocol may subject us to increased operating costs. Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases". Recently, representatives from approximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol. Pursuant to the resulting Copenhagen Accord, a non-binding political consensus rather than a binding international treaty such as the Kyoto Protocol, the Government of Canada revised its emissions reduction targets slightly. There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases. The Corporation's exploration and production facilities and other operations and activities emit greenhouse gases and require the Corporation to comply with Alberta's greenhouse gas emissions legislation contained in the Climate Change and Emissions Management Act and the Specified Gas Emitters Regulation. The Corporation may also be required comply with the regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which is now expected to be modified to ensure consistency with the regulatory scheme for greenhouse gas emissions adopted by the United States. The direct or indirect costs of these regulations may have a material adverse effect on the Corporation's business, financial condition, results of operations and prospects. The future implementation or modification of greenhouse gases regulations, whether to meet the limits required by the Kyoto Protocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including those of the Corporation. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on the Corporation and its operations and financial condition. See "Industry Conditions – Climate Change Regulation".

Compliance with new or modified environmental laws or regulations could have a materially adverse impact on us. We are subject to various Canadian and US laws and regulations relating to the environment. We believe that we are currently in compliance with such laws and regulations. However, such laws and regulations may change in the future in a manner which will increase the burden and cost of compliance. In addition, we could incur significant liability under such laws for damages, clean-up costs and penalties in the event of certain discharges into the environment. In addition, environmental laws and regulations may impose liability on us for personal injuries, clean-up costs, environmental damage and property damage as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for accidental environmental damages, but do not maintain insurance for the full potential liability that could be caused by such environmental damage. Accordingly, we may be subject to significant liability, or may be required to cease production in the event of the noted liabilities.

ITEM 4

INFORMATION ON THE COMPANY

We are incorporated under the laws of the Province of Ontario, and are registered as an extra-provincial company in Alberta. Our primary activities are investment in, exploration and development and production of oil and gas.

We hold a 0.5% non-convertible gross overriding royalty in a natural gas well located in the Haynes area in the Province of Alberta, Canada.

We hold a 5.1975% working interest held in trust through a joint venture partner in a natural gas unit located in the Botha area in the Province of Alberta, Canada.

Through Dyami Energy LLC we hold a 75% working interest before payout which reduces to a 61.50% working interest after payout of $12,500,000 of production revenue in the Matthews lease. Directly, we hold a 10% working interest before payout which reduces to a 7.50% working interest after payout of $15,000,000 of production revenue in the Matthews lease. The Matthews lease comprises approximately 2,629 gross acres of land in Zavala County, Texas.

Through Dyami Energy LLC, we hold a 100% working interest in the Murphy Lease comprising approximately 2,637 acres of land in Zavala County, Texas subject to a 10% carried interest on the drilling costs 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

Our registered office and management office is located at 1 King Street West, Suite 1505, Toronto, Ontario, M5H 1A1, Telephone (416) 364-4039, Facsimile (416) 364-8244. Our books and financial records are located in the registered office and management office. 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 Registrar and Transfer Agent is Equity Transfer & Trust Company located at Suite 400, 200 University Avenue, Toronto, Ontario, M5H 4H1. 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.

A. HISTORY AND DEVELOPMENT OF THE COMPANY

We were incorporated in Ontario, Canada on September 22, 1978, under the Business Corporations Act (Ontario), under the name Bonanza Red Lake Explorations Inc. (“Bonanza Red Lake”). By prospectus dated November 20, 1978 and a further amendment to the Prospectus dated January 10, 1979 we became a reporting issuer in the Province of Ontario and raised $250,000 to acquire interests in and to explore and develop certain mineral lands located near the Town of Red Lake, Ontario, Canada. In 1987, we optioned our mineral lands in Red Lake, Ontario to Pure Gold Resources Inc., who expended sufficient funds during 1988 and 1989 to earn an 85% interest in our eight patented mineral claims, and then discontinued its exploration program on the property. Bonanza Red Lake had subsequently written the carrying amount of these mineral claims down to $1.

On March 29, 2000, Bonanza Red Lake entered into a Share Exchange Agreement with 1406768 Ontario Inc. (“1406768 Ontario”). 1406768 Ontario is a company incorporated under the laws of the Province of Ontario by articles of incorporation dated effective March 13, 2000. The purpose of the transaction was to allow Bonanza Red Lake to acquire a company, 1406768 Ontario, which resulted in our owning part of an operating business. At an Annual and Special Meeting of shareholders held on May 10, 2000 we received shareholder approval for the acquisition of 1406768 Ontario; the consolidation of Bonanza Red Lake’s issued and outstanding common shares on a one new common share for every three old common shares basis; a name change from Bonanza Red Lake to Eugenic Corp; a new stock option plan (the “Plan”) authorizing 1,275,000 common shares to be set aside for issuance under the Plan; and authorizing the directors to determine or vary the number of directors of the Company from time to time which pursuant to our Articles provide for a minimum of three and a maximum of ten.

By Articles of Amendment dated August 15, 2000, Bonanza Red Lake consolidated its issued and outstanding common shares on a one new common share for every three old common shares basis and changed the name of the company to Eugenic Corp.

We completed the acquisition of 1406768 Ontario on October 12, 2000 and acquired all of the issued and outstanding shares of 1406768 Ontario for $290,000. The purchase price was satisfied by our issuance of 5,800,000 company units at $0.05 per unit. Each unit consisted of one common share and one common share purchase warrant entitling the holder to purchase one common share of ours at an exercise price of $0.25 per common share until October 12, 2003. As a result of this transaction, the original shareholders of 1406768 Ontario owned 90.7% of our issued shares. The acquisition resulted in a change in business and an introduction of new management for us. The acquisition was accounted for as a reverse take-over of us by 1406768 Ontario. Our net assets acquired at fair value as at October 12, 2000 resulted in a deficiency of assets over liabilities in the amount of $123,170 which was charged to share capital. All of the 5,800,000 outstanding warrants expired on October 12, 2003.

On November 2, 2001, we were extra-provincially registered in the Province of Alberta, Canada.

As part of an initiative to create cash flow, we commenced oil and gas operations effective August 31, 2001 and acquired a 25% working interest in one section of land (640 gross acres) in the Windfall Area of Alberta, Canada for a purchase price of $75,000. On June 25, 2003 we disposed of this property for net proceeds of $85,000.

On September 10, 2001, we entered into a Participation Agreement to acquire a 30% interest in one section of land (640 gross acres) in the St Anne area of Alberta, Canada by paying 40% of the costs to acquire approximately 7.1 kilometers of proprietary 2D seismic data. After review of the seismic data, it was determined that the joint partners would not undertake to drill a test well. Accordingly, the costs associated with acquiring this prospect were written off during fiscal 2003 - $4,806 and in fiscal 2002 - $22,781.

We entered into an Agreement dated February 28, 2002 to participate in drilling two test wells by paying 10% of the costs to drill to earn a 6% working interest before payout and a 3.6% working interest after payout. The first test well in the Haynes area of Alberta, Canada was drilled and proved to contain uneconomic hydrocarbons and was subsequently abandoned and costs of $38,855 were written off in 2002. On August 28, 2003 the joint partners farmed out their interest in the Haynes prospect for a 10% non-convertible overriding royalty (“NCOR”). The farmee drilled a test well and placed the well on production commencing December 2003. Our share of this NCOR is 0.5%. The second test well in the Mikwan area of Alberta, Canada was drilled and initially placed on production from the Glauconite formation and later shut in during 2003. The Glauconite formation was subsequently abandoned and the Belly River formation was completed and placed on production in January 2004.

Effective August 9, 2002, we entered into an agreement with Wolfden Resources Inc. (“Wolfden”) and sold our 15% interest in 8 patented mining claims located in Dome Township, Red Lake, Ontario (the “Mining Claims”) for consideration of $5,000 plus we retained a 0.3% net smelter return royalty of the net proceeds realized from the sale of recovered minerals. Wolfden also holds a right of first refusal to purchase our 0.3% net smelter return royalty. Pursuant to an arrangement dated effective August 18, 2006, Wolfden transferred certain assets including its interests in and to the Mining Claims to Premier Gold Mines Limited (“Premier”).

Effective October 28, 2005, we surrendered our 6% working interest in a gas well slated for abandonment and related expiring leases in the Mikwan area of Alberta. In exchange for the surrender of interests, we were released of our abandonment and site reclamation obligations.

On April 14, 2008, we completed a non-brokered private placement of a total of 2,575,000 units (each a "Unit") at a purchase price of $0.10 per Unit for gross proceeds of $257,500 (the "Offering"). Each Unit was comprised of one common share and one purchase warrant (each a "Warrant"). Each Warrant is exercisable until April 14, 2011 to purchase one additional share of our common stock at a purchase price of $0.20 per share.

On April 14, 2008, we also entered into an agreement (the "Debt Settlement Agreement") with our then President, Secretary and Director, Sandra J. Hall, to convert debt in the amount of $50,000 through the issuance of a total of 500,000 shares at an attributed value of $0.10 per Share. In connection with the conversion, Ms. Hall also agreed to forgive $38,000 of the debt owing to her by us.

In addition, on April 14, 2008, we also completed similar debt settlement arrangements with two other arm's length parties, in an effort to reduce the debt that we have reflected on our financial statements. In the aggregate, we entered into agreements to convert $100,000 of debt, through the issuance of a total of 1,000,000 shares at an attributed value of $0.10 per share.

On February 5, 2009, we completed a non-brokered private placement of 2,600,000 units (each a “Unit”) at a purchase price of $0.05 per Unit for gross proceeds of $130,000. Each Unit was comprised of one common share (each a “Unit Share”) and one purchase warrant (each a “Warrant”). Each Warrant is exercisable until February 5, 2014 to purchase one additional share of our common stock (each a “Warrant Share”) at a purchase price of $0.07 per share. 1407271 Ontario Inc. purchased 1,600,000 units. 1407271 Ontario Inc. is owned 100% by our former President, Ms. Sandra Hall. Ms. Hall is also the sole director and officer of 1407271.

On February 25, 2009, we completed a non-brokered private placement of 1,000,256 units (each a “Unit”) at a purchase price of $0.05 per Unit for gross proceeds of approximately $50,013. Each Unit was comprised of one common share (each a “Unit Share”) and one purchase warrant (each a “Warrant”). Each Warrant is exercisable until February 25, 2014 to purchase one additional share of our common stock (each a “Warrant Share”) at a purchase price of $0.07 per share. Sandra Hall, our former president and former director, and Milton Klyman, a director, purchased 600,000 Units and 50,000 Units, respectively.

On February 27, 2009, we purchased all of the issued and outstanding shares issued in the capital stock of 1354166 Alberta Ltd. (“1354166 Alberta”), a company incorporated on October 3, 2007 in the Province of Alberta Canada (the "Transaction") under the Business Corporations Act (Alberta). In connection therewith, we issued to the shareholders of 1354166 an aggregate of 8,910,564 units (each a "Unit") at $0.05 per unit or an aggregate of $445,528 and following the closing repaid $118,000 of shareholder loans in 1354166 by cash payment. . Each unit is comprised of one share of our common stock (each a "Share") and one purchase warrant (each a "Warrant"). Each Warrant is exercisable until February 27, 2014 to purchase one additional share of our common stock at a purchase price of $0.07 per share. 1354166 is a private company that has a 5.1975% working interest held in trust through a joint venture partner in a natural gas unit located in the Botha area of Alberta, Canada.

On February 27, 2009, we entered into an agreement with a non-related party, to convert 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 (the "Debt Settlement"). Each Unit was comprised of one common share (each a “Unit Share”) and one purchase warrant (each a “Warrant”). Each Warrant is exercisable until February 27, 2014 to purchase one additional share of our common stock (each a “Warrant Share”) at a purchase price of $0.07 per share.

By Articles of Amendment dated November 12, 2009, 1406768 Ontario changed its name to Eagleford Energy Inc.By Articles of Amalgamation dated November 30, 2009 we amalgamated with Eagleford Energy Inc. and upon the amalgamation the amalgamated entity's name became Eagleford Energy Inc.

Effective June 10, 2010, we 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, we 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 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 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.

On November 5, 2010 we terminated the agreement with Gar Wood dated June 10, 2010. As a result 36,430 warrants were cancelled out of the 333,333 warrants issued exercisable at $1.00 expiring December 10, 2011 and 18,215 warrants were cancelled out of the 166,667 warrants issued exercisable at $1.50 expiring June 10, 2012.During the fiscal year ended August 31, 2010, 1,100,000 of our common share purchase warrants were exercised at $0.07 expiring February 5, 2014 for proceeds of $77,000 and 1,000,000 of our common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $70,000.

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

On August 31, 2010, we acquired 100% the issued and outstanding membership interests of Dyami Energy LLC, a Texas limited liability corporation for consideration of $4,218,812. (US$3,965,422) satisfied by (i) the issuance of 3,418,467 units of the Company. Each unit is comprised of one common share and one-half a purchase warrant. Each full warrant is exercisable into one additional common share at US$1.00 per share on or before August 31, 2014 (the “Units’) and (ii) the assumption of $1,021,344 (US$960,000) of Dyami Energy debt by way of a secured promissory note.The note bears interest at 6% per annum, is secured by Dyami’s interest in the Matthews and Murphy leases and is payable on December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000.

Dyami Energy holds a 75% working interest before payout and a 61.50% working interest after payout of production revenue of $12.5 million in the Matthews Lease comprising approximately 2,629 gross acres of land in Zavala County, Texas and a 100% working interest in 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 (collectively the “Leases”).

The Members of Dyami entered into lock up agreements on closing and placed 50% of the Units in escrow (1,709,234 common shares and 854,617 purchase warrants) until such time that we receive a National Instrument 51-101 compliant report from an independent engineering firm indicating at least 100,000 boe 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 to be returned to us for cancellation. In addition without our 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 our common shares.

In connection with the Dyami Energy acquisition, we entered into a one year employment agreement with Eric Johnson and reserved 850,000 common share purchase warrants, exercisable on an earn-out basis, for the purchase of 850,000 common shares of our stock at a price of US$1.00 per share during a period of five years from the date of issuance.

During August 2010, Dyami Energy commenced operations to drill its Initial Test Well on the Matthews Lease, Zavala County, Texas. On October 15, 2010 the well was spud in and drilled to a measured depth of 8,563, feet including 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 protect the well bore and facilitate a multi stage frac completion.

The well was logged extensively and 36 sidewall cores were taken from 4 key formations in descending order, the San Miguel, the Austin Chalk, the Eagle Ford and the Buda. The logs were interpreted by Weatherford International Ltd and the sidewall cores were analyzed by Core Laboratories and Weatherford and based on those results the Company is formulating a detailed frac design and completion plan for the Dyami/Matthews #1 H well.

During the fiscal year ended August 31, 2010 we spent $10,046 on exploration expenditures related to the Matthews Lease.

The following table summarizes the costs incurred in our oil and gas interests for acquisition, exploration, and development activities for the years ended August 31, 2010, 2009 and 2008.

Oil and Gas Interests	2010			2009			2008
Developed-Alberta, Canada
Net book value at September 1	$	407,000		$	448		$	448
Acquisition of 1354166 Alberta		-			538,995			-
Depletion		(38,370	)		(26,638	)		(24	)
Write down of oil and gas interests		(54,630	)		(105,805	)		(528	)
Total developed, Alberta Canada		314,000			407,000			448
Undeveloped-Texas USA
Acquisition of oil and gas interests		212,780			-			-
Exploration expenditures		10,046			-			-
Acquisition of Dyami Energy		5,472,464			-			-
Total undeveloped, Texas, USA		5,695,290			-			-
Total developed and undeveloped	$	6,009,290		$	407,000		$	448

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

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

On January 26, 2011, 25,247 of our common share purchase warrants were exercised at $0.07 expiring February 27, 2014 for proceeds of $1,767.

Subsequent to the year-end August 31, 2010 and through to January 31, 2011, we received US$1,760,000 and CDN$149,000 and issued promissory notes to five of our shareholders. The notes are due on demand and bear interest at 10% per annum. Interest is payable annually on the anniversary date of the notes.

Subsequent to the year-end August 31, 2010 we received US $300,000 from our President and issued a promissory note to him. 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 three months ended November 30, 2010 we incurred $1,627,606 in expenditures related to the Matthews/Dyami #1H well.

On January 20, 2011 we spud our initial well, the Murphy/Dyami 1-H, on our 100% working interest Murphy Lease comprising 2,637 acres of land in Zavala County, Texas. The well was drilled vertically to a depth of 4,588 feet through the Eagle Ford shale to the Buda formation and logged by Weatherford International. Core samples were recovered from the Georgetown, Buda, Eagle Ford Shale, Serpentine and the Escondido formations for interpretation and analysis.

We intend to apply additional capital to further enhance our property interests. As part of our 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 are dependent on the nature of future opportunities evaluated by us. These expenditures could be funded through cash held by the Company or through cash flow from operations. Any expenditure which exceeds available cash will be required to be funded by additional share capital or debt issued by us, or by other means. Our long-term profitability will depend upon our ability to successfully implement our business plan.

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

Our registered office and principal place of business in Ontario is located at 1 King Street West, Suite 1505, Toronto, Ontario M5H 1A1. Our telephone number at that address is (416) 364-4039.

B. BUSINESS OVERVIEW

Directly and through our wholly owned subsidiaries 1354166 Alberta and Dyami Energy we are primarily engaged in the development, acquisition and production of oil and gas interests located in Alberta, Canada and Texas, USA. Our operations consist of a 0.5% NCOR in a natural gas well located in Haynes, Alberta, Canada a 5.1975% working interest in a natural gas unit located in Alberta, Canada, an 85% working interest before payout (69% working interest after payout) in Matthews lease comprising 2,629 gross acres of land in Zavala County, Texas. In addition, we hold a 100% working interest in the Murphy lease comprising approximately 2,637 acres of land in Zavala County, Texas subject to a 10% carried interest on the drilling costs 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..

We have a 0.3% Net Smelter Return Royalty on 8 patented mining claims located in Red Lake, Ontario, Canada.

For the three fiscal years ending August 31, 2010, 2009 and 2008 the total gross revenue derived from the sale of our natural gas interests was as follows:

	Total
August 31, 2010	$	105,375
August 31, 2009	$	56,199
August 31, 2008	$	292

We sell our natural gas production to integrated oil and gas companies and marketing agencies. Sales prices are generally set at market prices available in Canada or the United States.

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw make the ground unstable and municipalities and provincial transportation departments enforce road bans that may restrict the level of activity. Seasonal factors and unexpected weather patterns may lead to declines in production activity and increased consumer demand or changes in supply during certain months of the year may influence the commodity prices.

There is an existing and available market for the oil and gas produced from the properties. However, the prices obtained for production are subject to market fluctuations, which are affected by many factors, including supply and demand. Numerous factors beyond our control, which could affect pricing include:

•

the level of consumer product demand;

•

weather conditions;

•

the foreign supply of oil and gas;

•

the price of foreign imports;

•

volatility in market prices for oil and natural gas;

•

ability to raise financing;

•

reliance on third party operators;

•

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

•

liabilities inherent in oil and natural gas operations;

•

dilution of interests in oil and natural gas properties;

•

general business and economic conditions;

•

the ability to attract and retain skilled staff;

•

uncertainties associated with estimating oil and natural gas reserves;

•

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

•

governmental regulation and environmental legislation.

We caution that the foregoing list of important factors is not exhaustive. Investors and others who base themselves on our forward-looking statements should carefully consider the above factors as well as the uncertainties they represent and the risk they entail. We also caution 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.

We do not have a reliance on raw materials, as we operate in an extractive industry.

We do not have a reliance on any significant patents or licenses.

The oil and gas business is highly competitive in every phase. Many of our competitors have greater financial and technical resources, and have established multi-national operations, secured land rights and licenses, which we may not have. As a result, we may be prevented from participating in drilling and acquisition programs (See, Item 3.D Key Information - Risk Factors).

Governmental Regulation/Environmental Issues

Our oil and gas operations are subject to various United States and Canadian governmental regulations including those imposed by the Texas Railroad Commission and Alberta Energy Resources Conversation Board and Alberta Utilities Commission. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. The production, handling, storage, transportation and disposal of oil and gas, by-products thereof, and other substances and materials produced or used in connection with oil and gas operations are also subject to regulation under federal, state, provincial and local laws and regulations relating primarily to the protection of human health and the environment. To date, expenditures related to complying with these laws, and for remediation of existing environmental contamination, have not been significant in relation to the results of operations of our company. The requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. These regulations may adversely affect our operations and cost of doing business. It is likely that these laws and regulations will become more stringent in the future (See, Item 3.D Key Information - Risk Factors).

Climate Change Regulation

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"), which requires a reduction in greenhouse gas emissions by signatory countries between 2008 and 2012. The Kyoto Protocol officially came into force on February 16, 2005 and commits Canada to reduce its greenhouse gas emissions levels to 6% below 1990 "business-as-usual" levels by 2012.

In anticipation of the expiry of the Kyoto Protocol in 2012, government leaders and representatives from approximately 170 countries met in Copenhagen, Denmark from December 6 to 18, 2009 (the "Copenhagen Conference") to attempt to negotiate a successor to the Kyoto Protocol. The primary result of the Copenhagen Conference was the Copenhagen Accord, which represents a broad political consensus rather than a binding international treaty like the Kyoto Protocol and has not been endorsed by all participating countries. The Copenhagen Accord reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate change. Although certain countries, including Canada, have committed to reducing their emissions individually or jointly by at least 80% by 2050, the Copenhagen Accord does not establish binding GHG emissions reduction targets. The Copenhagen Accord calls for a review and implementation of its stated goals by 2016.

In response to the Copenhagen Accord, the Government of Canada indicated on January 29, 2010 that it will seek to achieve a 17% reduction in greenhouse gas emissions from 2005 levels by 2020. This goal is similar to the goal expressed in previous policy documents which are discussed below.

On February 14, 2007, the House of Commons passed Bill C-288, An Act to ensure Canada meets its global climate change obligations under the Kyoto Protocol. The resulting Kyoto Protocol Implementation Act came into force on June 22, 2007. Its stated purpose is to "ensure that Canada takes effective and timely action to meet its obligations under the Kyoto Protocol and help address the problem of global climate change." It requires the federal Minister of the Environment to, among other things, produce an annual climate change plan detailing the measures to be taken to ensure Canada meets its obligations under the Kyoto Protocol. It also authorizes the establishment of regulations respecting matters such as emissions limits, monitoring, trading and enforcement.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both greenhouse gases and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). Although draft regulations for the implementation of the Updated Action Plan were intended to be published in the fall of 2008 and become binding on January 1, 2010, no such regulations have been proposed to date. Further, representatives the Government of Canada have recently indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to greenhouse gas emissions regulation, which may include an absolute cap on emissions combined with allowances to be used for compliance that may be partially auctioned off to regulated entities. It is also unclear whether the approach adopted by the United States will provide for the payment into a technology fund as a compliance mechanism, as is currently permitted in Alberta and by the Updated Action Plan. As a result, many provisions of the Updated Action Plan, described below, are expected to be significantly modified.

The stated goal of the Updated Action Plan, as currently drafted, is to reduce greenhouse gas emissions to 20% below 2006 levels by 2020 and 60-70% by 2050. As noted above, the goal has now been modified by the Government of Canada. The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis. Facility-specific targets applied to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets.

The Updated Action Plan makes a distinction between "Existing Facilities" and "New Facilities". For Existing Facilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by 2010 followed by a continuous annual emissions intensity improvement of 2%. "New Facilities" are defined as facilities beginning operations in 2004 and include both greenfield facilities and major facility expansions that (i) result in a 25% or greater increase in a facility's physical capacity, or (ii) involve significant changes to the processes of the facility. New Facilities will be given a 3-year grace period during which no emissions intensity reductions will be required. Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year of commercial operation of a New Facility. Further, emissions intensity targets for New Facilities will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time. The method of applying this cleaner fuel standard has not yet been determined. In addition, the Updated Action Plan indicates that targets for the adoption of carbon capture and storage ("CCS") technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators that begin operations in 2012 or later. These targets will become operational in 2018, although the exact nature of the targets has not yet been determined.

Given the large number of small facilities within the upstream oil and gas and natural gas pipeline sectors, facilities within these sectors will only be subject to emissions intensity targets if they meet certain minimum emissions thresholds. That threshold will be (i) 50,000 tonnes of CO2 equivalents per facility per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalents per facility per year for the upstream oil and gas facility; and (iii)10,000 boe/d/company. These regulatory thresholds are significantly lower than the regulatory threshold in force in Alberta, discussed below. In all other sectors govern by the Updated Action Plan all facilities will be subject to regulation.

Four separate compliance mechanisms are provided for in the Updated Action Plan in respect of the above targets: Technology Fund contributions, offset credits, clean development credits and credits for early action. Regulated entities will be able to use Technology Fund contributions to meet their emissions intensity targets. The contribution rate for Technology Fund contributions will increase over time, beginning at $15 tonnes per CO2 equivalent for the 2010-12 period, rising to $20 in 2013, and thereafter increasing at the nominal rate of GDP growth. Maximum contribution limits will also decline from 70% in 2010 to 0% in 2018. Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions. Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as described above.

The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities. In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued to the project proponent. Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either purchase the offset credits for cancellation or banking for future use or sale.

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto Protocol which facilitates investment by developed nations in emissions reduction projects in developing countries. The purchase of such Emissions Reduction Credits will be restricted to 10% of each firm's regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to regulated entities for emissions reduction activities undertaken between 1992 and 2006. These credits will be both tradable and bankable.

Alberta

Alberta enacted the Climate Change and Emissions Management Act (the "CCEMA") on July 1, 2007, amending it through the Climate Change and Emissions Management Amendment Act which received royal asset on November 4, 2008. The CCEMA is based on an emissions intensity approach similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.

Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year are subject to comply with the CCEMA. Similarly to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make a distinction between "Existing Facilities" and "New Facilities". Existing Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2008 or that have completed 8 or more years of commercial operation. Existing Facilities were required to reduce their emissions intensity by March 31, 2008 by 12% from a baseline established by their average emissions intensity between 2003 and 2005. New Facilities are defined as facilities that completed their first year of commercial operation subsequent to December 31, 2008, have completed less than 8 years of commercial operation, or are designated as New Facilities in accordance with the Specified Gas Emitters Regulation. New Facilities are also required to reduce their emissions intensity by 12% but this target is based on the emissions intensity of the facility in its third year of commercial operation and does not apply during the first 3 years of operation of the New Facility. Unlike the Updated Action Plan, the CCEMA does not contain any provision for continuous annual improvements beyond the 12% emissions intensity required.

The CCEMA contains similar compliance mechanisms as the Updated Action Plan. Regulated emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions Management Fund (the "Fund") at a rate of $15 per tonne of CO2 equivalent. Unlike the Updated Action Plan, CCEMA contains no provisions for an increase to this contribution rate. Emissions credits can be purchased from regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters that have generated emissions offsets through activities that result in emissions reductions in accordance with established protocols published by the Government of Alberta. Unlike the Updated Action Plan, the CCEMA does not contemplate a linkage to external compliance mechanisms such as the Kyoto Protocol's Clean Development Mechanism.

C. ORGANIZATIONAL STRUCTURE

We have two wholly owned subsidiaries. 1354166 Alberta Ltd., is a company incorporated under the Business Corporations Act (Alberta) and Dyami Energy LLC is a Texas Limited Liability company.

D. PROPERTY, PLANTS AND EQUIPMENT

Our executive offices consist of approximately 140 square feet of office space and are rented at $500 per month on a month to month basis. ) The address of our executive offices is 1 King Street West, Suite 1505, Toronto, Ontario Canada.

Canada

We hold directly a 0.5% NCOR in a natural gas well located in Haynes, Alberta, Canada.

We hold through our wholly owned subsidiary 1354166 Alberta a 5.1975% working interest in a natural gas unit located in Botha, Alberta, Canada.

We have a 0.3% Net Smelter Return Royalty on eight patented mining claims located in Red Lake, Ontario, Canada.

United States

We hold through our wholly owned subsidiary Dyami Energy a 75% working interest before payout and a 61.5% working interest after payout of $12,500,000 of production in Matthews lease comprising approximately 2,629 gross acres of land in Zavala County, Texas.

We hold directly a 10% working interest before payout and a 7.5% working interest after payout of $15,000,000 of production in Matthews lease comprising approximately 2,629 gross acres of land in Zavala County, Texas.

We hold through our wholly owned subsidiary Dyami Energy, a 100% working interest in the Murphy lease comprising approximately 2,637 acres of land in Zavala County, Texas subject to a 10% carried interest on the drilling costs 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. The Matthews and Murphy Leases are subject to royalties payable of 25%.

Our Matthews Lease is situated adjacent to the Redhawk land block under development by Petrohawk Energy Corporation in Zavala County, Texas and is part of the Maverick Basin of Southwest Texas and downdip from the United States Geological Studies north boundary of the Smackover-Austin-Eagle Ford total petroleum system.

The map below indicates the location of our Matthews Lease and Murphy Lease located in Zavala County, Texas.

The table below is a glossary of terms and abbreviations that may be used in this Item.

GLOSSARY OF TERMS

Natural Gas	Mcf	1,000 cubic feet
	MMcf	1,000,000 cubic feet
	Mcf/d	1,000 cubic feet per day

Oil and Natural Gas Liquids	Bbl	Barrel
	Mbbls	1,000 barrels
	Blpd	Barrels of liquid per day
	Boe	Barrel of oil equivalent (1)
	Bpd	Barrels per day
	Boepd	Barrels of oil equivalent per day
	Bopd	Barrels of oil per day
	NGLs	Natural gas liquids

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

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		6.289
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

The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economics data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs changes. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. These factors and assumptions include among others (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates, (iii) production decline rates, (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production, (vii) effects of government regulation; and (viii) other government levies imposed over the life of the reserves.

As circumstances change and additional data becomes available, reserves estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required for changes in well performance, prices, economic conditions and governmental restrictions. Revisions to reserve estimates can arise from changes in year–end prices, reservoir performance and geological conditions or production. These revisions can be either positive or negative (See Item 3.D. Key Information – Risk Factors).

As a Canadian issuer, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (NI 51-101) issued by the Canadian Securities Administrators, in all of our reserves related disclosures. NI 51-101 mandates significant changes in the way reporting issuers are required to determine and publicly disclose information relating to oil and gas reserves. Under NI 51-101, proved reserves is an estimate, the premise of which means there must be at least a ninety percent probability that actual quantities of crude oil and natural gas proved reserves recovered will equal or exceed the estimated proved reserves.

The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of crude oil and natural gas activities by reporting issuers and elevate reserves reporting to a higher level of confidence and accountability. In the United States, registrants, including foreign private issuers like us, are required to disclose proved reserves using the standards contained in the United States Securities and Exchange Commission (“SEC”) Regulation S-X. However, under certain circumstances, applicable U.S. law permits us to comply with our own country’s law if the requirements vary. We believe that the standards for determining proved reserves under NI 51-101 meet those set forth under U.S. law and thus we have presented our proved reserves under NI 51-101 only.

The crude oil and natural gas industry commonly applies a conversion factor to production and estimated proved reserve volumes of natural gas in order to determine an “all commodity equivalency” referred to as barrels of oil equivalent (“boe”). The conversion factor we have applied in this Report is the current convention used by many oil and gas companies, where six thousand cubic feet (“mcf”) is equal to one barrel (“bbl”). A boe is based on an energy equivalency conversion method primarily applicable at the burner tip. It may not represent equivalency at the wellhead and may be misleading if used in isolation.

Reserve Information. The estimate of our proved reserves on a constant-pricing basis, and their associated net present values, have been based on the August 31, 2010, 2009 and 2008 actual posted commodity prices as determined by our qualified reserves evaluator, Sproule Associates Limited (“Sproule”), a member of the Association of Professional Engineers Geologists and Geophysicists of Alberta, Canada. Appropriate adjustments have been made to account for quality and transportation, to the constant natural gas prices, and to the constant natural gas by-products prices to reflect historical prices received for each area. It should not be assumed that the discounted net present value estimated by Sproule represents the fair market value of the reserves. Where the present value is based on constant price and cost assumptions, there is no assurance that such price and cost assumptions will be attained and variances could be material. At August 31, 2010, our developed properties include a 0.5% NCOR in a natural gas well located in Haynes, Alberta, Canada which is carried on the books at NIL and through our wholly owned subsidiary 1354166 Alberta a 5.1975% working interest in a natural gas unit located in the Botha area Northwest, Alberta near the town of Manning, Canada. The unit is governed by a Pooling Agreement dated December 01, 1991 (covering Natural Gas in the Debolt formation) which contains a Right of First Refusal provision. Under a participation agreement dated October 15, 2003, 1354166 Alberta’s working interest is held in trust by a joint venture partner.

The table below sets out in CDN dollars the constant prices and the exchange rate used. As of August 31, 2010 all of our reserves were located in Alberta, Canada.

August 31, 2010	Natural Gas Alberta AECO-C	4.07 $/Mcf
	Exchange Rate:	0.956 $ US/$ Cdn.

August 31, 2009	Natural Gas Alberta AECO-C	2.14 $/Mcf
	Exchange Rate:	0.9132 $ US/$ Cdn

August 31, 2008	Natural Gas Alberta AECO-C	6.92 $/Mcf
	Exchange Rate:	0.9483 $US/$Cdn.

Proved Reserves: The following table reflects estimates of our proved developed reserves as at August 31, 2010, 2009, and 2008 as reported by Sproule stated in CDN dollars. All of our gas reserves are located in Canada. The following table represents our net interest in its reserves (after crown royalties, freehold royalties and overriding royalties and interests owned by others). Estimated cash flow figures before income tax are net of all royalties, operating and capital costs and discounted at 10% to the Net Present Value (“NPV”). NPV figures are based on constant prices.

Period	Proved Reserves	Natural Gas Mmcf	Net Present Value discounted at 10%
August 31, 2010	Proved Developed	152	$	110
August 31, 2009	Proved Developed	29	$	Nil
August 31, 2008	Proved Developed	Nil	$	256

Production Volume: The following table sets forth the net quantities of natural gas produced during the fiscal years ended August 31, 2010, 2009 and 2008.

August 31,		2010			2009		2008
Natural Gas (Mcf)		24,941			16,412		37

Historical Production: The following table sets out our net share of production, average sales prices, average royalties, production costs and average net back per unit of production for the fiscal years ended August 31, 2010, 2009 and 2008.

	For the Years Ended
Historical Production	August 31, 2010		August 31, 2009			August 31, 2008
Natural Gas – Mcf/d		68		45	l	Nil
Natural Gas Prices- $/Mcf	$	4.42	$	3.42		$	9.23
Royalty Costs - $/Mcf		0.98		0.63		Nil
Production Costs - $/Mcf		2.62		3.28	l	Nil
Net Back - $/Mcf	$	0.62	$	(0.49	)	$	9.23

Producing Wells: The following table sets forth the number of our gross and net oil and natural gas wells and the number of gross and net non-producing oil and natural gas wells that we have an interest in by location as of August 31, 2010, 2009 and 2008. A gross well is a well in which we own an interest. A net well represents the fractional interest we own in gross wells. For the fiscal years ended August 31, 2010, 2009 and 2008 we held a 0.5% NCOR in a natural gas well located in Haynes, Alberta, Canada and through our wholly owned subsidiary, 1354166 Alberta a 5.1975% working interest in a natural gas unit located in the Botha area Northwest, Alberta near the town of Manning, Canada.

The following table sets out the number of gross and net producing oil and natural gas wells and the number of gross and net non-producing oil and natural gas wells that we have an interest in by location.

Location- Alberta, Canada	Gross Producing Gas Wells		Net Producing Gas Wells		Gross Non-Producing Gas Wells		Net Non-Producing Gas Wells
2010		3		5.1975		6		5.1975
2009		3		5.1975		6		5.1975
2008	Nil		Nil		Nil		Nil

Acreage. The following table sets forth the developed and undeveloped acreage of the projects in which the Company holds an interest, on a gross and a net basis as of August 31, 2010, 2009 and 2008. The developed acreage is stated on the basis of spacing units designated by provincial authorities and typically on the basis of 160 acre spacing unit for oil production and 640 acre spacing unit for gas production in Alberta. Our developed acreage is located in Alberta, Canada. Our undeveloped acreage is located in Zavala County, Texas.

August 31,

2010

2009

2008

Gross

Net

Gross

Net

Gross

Net

Developed Acreage, Canada

8,320

432

8,320

432

Nil

Undeveloped Acreage, USA

5,266

4,872

Nil

Reserve Reconciliation: The following table sets forth a reconciliation of the changes in our associated and non-associated gas (MMcf) reserves as at August 31, 2010 against such reserves as at August 31, 2009.

	ASSOCIATED AND NON-ASSOCIATED GAS
	Net Proved (MMcf)			Net Probable (MMcf)			Net Proved Plus Probable (MMcf)
At August 31, 2009		248			91			339
Technical Revisions		(10	)		(22	)		(32	)
Production		(25	)		-			(25	)
At August 31, 2010		213			69			282

Production Estimates: The following table indicates the volume of production estimated for the year ending August 31, 2011 reflected in the estimates of future net revenue based on constant prices and costs.

Property		Associated and Non-Associated Gas (MMcf)
Botha, Alberta		16

Additional Information Concerning Abandonment and Reclamation Costs:

We base our estimates for costs of abandonment and reclamation of surface leases and wells on previous experience with similar well site locations and area terrain. We believe that our range of estimates at $30,000 gross per well for abandonment and reclamation costs are reasonable and applicable to its wells. Our independent qualified reserves evaluator has also estimated similar costs in deriving our estimate of future net revenue. Ultimately all wells in the natural gas unit will require abandonment and reclamation. The total of such costs estimated for 5.1975 net wells for the fiscal year ended August 31, 2010 was $8,568 and $2,568 calculated using a discount rate of 10% percent. We do not expect to pay abandonment and reclamation costs over the next 3 fiscal years.

Present Activities, Results of Exploration and Drilling:

During August 2010, through Dyami Energy, we commenced operations to drill an initial Eagle Ford shale test well on the Matthews Lease in Zavala County, Texas. The well was spud on October 15, 2010 and was drilled to a measured depth of 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 protect the well bore and facilitate a multi stage frac completion.

The well was logged extensively and 36 sidewall cores were taken from 4 key formations in descending order, the San Miguel, the Austin Chalk, the Eagle Ford and the Buda. The logs were interpreted by Weatherford International Ltd and the sidewall cores were analyzed by Core Laboratories and Weatherford and based on the results we are is formulating a detailed frac design and completion plan for the Dyami/Matthews #1 H well.

For the three months ended November 30, 2010 we incurred $1,627,606 in expenditures related to the Matthews/Dyami #1H well.

On January 20, 2011 we spud the initial well, the Murphy/Dyami 1-H, on our 100% working interest Murphy Lease comprising 2,637 acres of land in Zavala County, Texas. The well was drilled vertically to a depth of 4,588 feet through the Eagle Ford shale to the Buda formation and logged by Weatherford International. Core samples were recovered from the Georgetown, Buda, Eagle Ford Shale, Serpentine and the Escondido formations for interpretation and analysis.

Governmental Regulation/Environmental Issues: Our oil and gas operations are subject to various Canadian and US governmental regulations. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. The production, handling, storage, transportation and disposal of oil and gas, by-products thereof, and other substances and materials produced or used in connection with oil and gas operations are also subject to regulation under federal, state, provincial and local laws and regulations relating primarily to the protection of human health and the environment. To date, expenditures related to complying with these laws, and for remediation of existing environmental contamination, have not been significant in relation to the results of operations of our company. The requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations (See, Item 3.D Key Information - Risk Factors).

ITEM 4A UNRESOLVED STAFF COMMENTS

Not Applicable

ITEM 5 OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read in conjunction with our “Selected Financial Data” under Item 3 above, our Audited Consolidated Financial Statements for the fiscal years ended August 31, 2010, 2009 and 2008 and notes thereto included under “Item 17”. Unless otherwise indicated, discussion under this Item is based on Canadian dollars and is presented in accordance with Canadian Generally Accepted Accounting Principles (“GAAP”). For reference to differences between Canadian GAAP and United States Generally Accepted Accounting Principles (“US GAAP”) see Note 17 to our Audited Consolidated Financial Statements for the fiscal years ended August 31, 2010 and 2009.

Certain measures in this discussion and analysis 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.

Certain statements made in this Item are forward-looking statements under the Reform Act. Forward- looking statements are based on current expectations that involve a numbers of risks and uncertainties, which could cause actual events or results to differ materially from those reflected herein. See, Item 3.D Key Information - Risk Factors for discussion of important factors, which could cause results to differ materially from the forward- looking statements below.

Overview

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

Our operations consist of a 0.5% Non Convertible Overriding Royalty in a natural gas well located in Haynes, Alberta, Canada a 5.1975% working interest in a natural gas unit located in Alberta, Canada, an 85% working interest before payout (69% working interest after payout) in Matthews lease comprising 2,629 gross acres of land in Zavala County, Texas. In addition, we hold a 100% working interest in the Murphy lease comprising approximately 2,637 acres of land in Zavala County, Texas subject to a 10% carried interest on the drilling costs 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..

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

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

On November 12, 2009, our wholly owned subsidiary 1406768 Ontario Inc. changed its name to Eagleford Energy Inc. On November 30, 2009 we amalgamated with Eagleford Energy Inc. and upon the amalgamation our new name became Eagleford Energy Inc.

Financial Instruments and Risk Factors

We are exposed to financial risk, in a range of financial instruments including cash, accounts receivable and accounts payable and income taxes payable and loans payable. We manage our exposure to financial risks by operating in a manner that minimizes our exposure to the extent practical.

The main financial risks affecting us are discussed below.

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

	2010				2009
	Amount		Fair Value		Amount		Fair Value
Financial assets

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

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

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

Credit Risk

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

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

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

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

The carrying amount of cash and cash equivalents and accounts receivable represents our maximum credit exposure.

As at August 31, 2010 our accounts receivable is aged as follows:

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

Liquidity Risk

Liquidity risk includes the risk that, as a result of our operational liquidity requirements:

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

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

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

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

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

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

(1)

Translated at current exchange rate.

Capital Management

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

As at August 31, 2010, our capital structure included the following:

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

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

There were no changes in our capital management during the year ended August 31, 2010.

We are not subjected to any externally imposed capital requirements.

Critical Accounting Policies and Estimates and Change in Accounting Policies and Initial Adoption

Our significant accounting policies, estimates and changes to accounting policies are also described in the Notes to the Audited Consolidated Financial Statements for the fiscal years ended August 31, 2010, 2009, and 2008 (See Item 17 – Financial Statements). It is increasingly important to understand that the application of generally accepted accounting principles involves certain assumptions, judgments and estimates that affect reported amounts of assets, liabilities, revenues and expenses. The application of principles can cause varying results from company to company.

The most significant accounting policies that impact us relate to oil and gas accounting and reserve estimates.

Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada. The preparation of our consolidated financial statements in accordance with US GAAP have resulted in differences to the consolidated balance sheet and the consolidated statement of loss, comprehensive loss and deficit from the consolidated financial statements prepared using Canadian GAAP (see Reconciliation to Accounting Principles Generally Accepted in the United States below).

Critical Accounting Policies and Estimates

Going Concern

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

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

Principles of Consolidation

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

Oil and Gas Interests

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

Depletion and Depreciation

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

(a)

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

(b)

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

(c)

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

Impairment Test

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

Revenue Recognition

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

Royalties

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

Transportation

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

Environmental and Site Restoration Costs

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

Foreign Currencies

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

Marketable Securities

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

Financial Instruments

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

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

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

Cash and cash equivalents

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

Accounting Estimates

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

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

Income Taxes

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

Non-Monetary Transactions

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

Stock-Based Compensation

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

Loss Per Share

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

Warrants

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

Change in Accounting Policy and Future Accounting Changes

(a) EIC Credit Risk

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

(b) Financial Instruments – Disclosures

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

(i)

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

(ii)

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

(iii)

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

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

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

(d) General Standard of Financial Statement Presentation

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

(e) Future Accounting Changes

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

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

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

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

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

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

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

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

RECONCILIATION TO ACCOUNTING PRINCIPLES GENERALLY ACCEPTED IN THE UNITED STATES

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

Oil and Gas Interests

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

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

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

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

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

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

DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

Adoption of New Accounting Policies

Financial Accounting Standards Board’s Codification of US GAAP

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

Business combinations

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

Non-controlling interests

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

Derivative Instruments and Hedging Activities

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

Subsequent events

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

The Fair Value Measurement of Liabilities

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

Equity method investees

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

Future U.S. Accounting Policy Changes

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

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

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

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

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

INTERNATIONAL FINANCIAL REPORTING STANDARDS

Transition to International Financial Reporting Standards

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

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

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

Initial analysis of key areas for which changes to accounting policies may be required			Completed
Detailed analysis of all relevant IFRS requirements and identification of area requiring accounting policy changes or those with accounting policy alternatives			Throughout fiscal 2010 and 2011
Assessment of first-time adoption (IFRS 1) requirements and alternatives			Throughout fiscal 2010 and 2011
Final determination of changes to accounting policies and choices to be made with respect to first-time adoption alternatives			Q2, Q3 (August 31, 2011)
Resolution of the accounting policy change implications on information technology, internal controls and contractual arrangements			Q2, Q3 (August 31, 2011)
Management and employee training			Throughout the transition period
Quantification of the Financial Statement impact of changes in accounting policies			Throughout fiscal 2011

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

• Property, Plant and Equipment

Pre-exploration costs

Exploration and evaluation costs

Depletion, depreciation and amortization

• Impairment testing

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

• Stock-based compensation

• Income taxes

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

Property, Plant and Equipment

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

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

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

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

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

Impairment Testing

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

Asset Retirement Obligation

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

Stock-based Compensation

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

Accounting for Income Tax

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

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

Changes to IFRS Accounting Standards

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

Internal Controls over Financial Reporting

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

Education and Training

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

Impacts to our Business

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

SEGMENTED INFORMATION

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

Geographic information:

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

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

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

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

Other Information

Additional information relating to us may be obtained or viewed from the System for Electronic Data Analysis and Retrieval at www.sedar.com and our future United States Securities and Exchange Commission filings can be viewed through the Electronic Data Gathering Analysis and Retrieval System (EDGAR) at www.sec.gov.

Share Capital

Share Capital as at August 31, 2010

Share Capital and Contributed Surplus

Authorized:

Unlimited number of common shares

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

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

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

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

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

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

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

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

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

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

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

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

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

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

	August 31,
	2010					2009				2008
Warrants	Number of Warrants			Weighted Average Price		Number of Warrants		Weighted Average Price		Number of Warrants		Weighted Average Price
Outstanding beginning of year		16,335,820		$	0.09		2,575,000	$	0.20		-		-
Issued		2,209,233			1.04		13,760,820		0.07		2,575,000	$	0.20
Exercised		(2,100,000	)		0.07		-		-		-		-
Outstanding end of year		16,445,053		$	0.22		16,335,820	$	0.09		2,575,000	$	0.20

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

Number of Warrants	Note	Exercise Price		Expiry Date	Warrant Value ($)
2,575,000	(note a)	$	0.20	April 14, 2011	$	100,875
500,000	(note c, g)	$	0.07	February 5, 2014		12,000
1,000,256	(note d)	$	0.07	February 25, 2014		24,006
10,160,564	(note e, f)	$	0.07	February 27, 2014		243,853
333,333	(note i)	$	US1.00	December 10, 2011		214,372
166,667	(note i)	$	US 1.50	June 10, 2012		112,139
1,709,233	(note h)	$	US1.00	August 31, 2014		1,388,833
16,445,053					$	2,096,078

The fair value of the warrants issued during the year ended August 31, 2010, 2009 and 2008 were estimated on the date of issue using the Black-Scholes pricing model with the following assumptions:

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

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

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

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

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

Stock Option Plan

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

Contributed Surplus

Contributed surplus transactions for the respective years are as follows:

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

Overall Performance

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

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

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

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

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

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

We expect to apply additional capital to further enhance our property interests. As part of our oil and gas development program, management 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 us. These expenditures could be funded through cash held by us or through cash flow from our operations. Any expenditure which exceeds available cash will be required to be funded by additional share capital or debt issued by us, or by other means. Our long-term profitability will depend upon our ability to successfully implement its business plan.

Selected Financial Information

The following table reflects the summary of operating results for the years ended August 31, 2010, 2009 and 2008.

Presented Pursuant to Canadian Generally Accepted Accounting Principles

(CANADIAN $, Except Per Share Data)

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

Selected Financial Information should be read in conjunction with the discussion below and “Critical Accounting Policies and Estimates” above.

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, 2008 was primarily attributed to acquisition of 1354166 Alberta Ltd.

August 31, 2008 – 2007

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

A. OPERATING RESULTS

THE FOLLOWING DISCUSSION OF OUR RESULTS OF OPERATIONS IS A COMPARISON OF OUR FISCAL YEAR ENDED AUGUST 31, 2010 VERSUS AUGUST 31, 2009 AND AUGUST 31, 2009 VERSUS AUGUST 31, 2008.

Presented Pursuant to Canadian Generally Accepted Accounting Principles

(CANADIAN $, Except Per Share Data)

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

Production Volume

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

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

Commodity Prices

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

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

Revenue

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

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

Operating Costs

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

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

Depletion

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

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

Administrative Expenses

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

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

Interest Income

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

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

Net loss and comprehensive loss for the period

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

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

Net loss per share

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

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

Summary of Quarterly Results

The following tables reflect the summary of quarterly results for the years ended August 31, 2010, August 31, 2009 and August 31, 2008.

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

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

	2009			2009			2009			2008
For the Quarters ended	August 31			May 31			February 28			November 30
Revenue	$	23,078		$	32,796		$	260		$	65
Net loss and comprehensive loss for the period	$	(249,967	)	$	(62,554	)	$	(9,721	)	$	(6,619	)
Net loss per share	$	(0.013	)	$	(0.005	)	$	(0.001	)	$	(0.001	)

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

	2008			2008			2008			2007
For the Quarters ended	August 31			May 31			February 29			November 30
Revenue	$	50		$	79		$	92		$	71
Net loss and comprehensive loss for the period	$	(20,646	)	$	(7,064	)	$	(16,539	)	$	(6,265	)
Loss per share	$	(0.003	)	$	(0.001	)	$	(0.003	)	$	(0.001	)

Revenue over the four quarters has fluctuated as a result of changes in natural gas sales prices received and natural gas sales volumes. The increase in net loss and comprehensive loss for the quarter ending August 31, 2008 was primarily attributed to an increase in professional fees relating to the year-end audit, costs associated with the evaluation of our reserves and a write down of oil and gas interests.

Fourth Quarter Results August 31, 2010Versus August 31, 2009

Production Volume

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

Commodity Prices

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

Revenue

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

Operating Costs

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

Depletion

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

Administrative Expenses

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

Interest

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

Net loss and comprehensive loss for the period

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

Loss per share

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

B.	LIQUIDITY AND CAPITAL RESOURCES

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

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

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

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

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

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

Our 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 we issued additional common shares from treasury it would cause the current shareholders dilution.

Outlook and Capital Requirements

A part of our oil and gas development program, we anticipate further expenditures to expand our existing portfolio of proved reserves. Amounts expended on future exploration and development are dependent on the nature of future opportunities evaluated by us. These expenditures could be funded through cash held by us 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 us, or by other means. Our long-term profitability will depend upon our ability to successfully implement our business plan.

C.	RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES

We do not engage in research and development activities.

D.	TREND INFORMATION

Seasonality

Our 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 our oil and gas properties is the primary determinant for the volume of sales during the year.

There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business.

The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. A tight supply demand balance for natural gas causes significant elasticity in pricing, whereas higher than average storage levels tend to depress natural gas pricing. Drilling activity, weather, fuel switching and demand for electrical generation are all factors that affect the supply-demand balance. Recently, liquefied natural gas shipments to North America have also resulted in natural gas supply and natural gas pricing being based more on factors other than supply and demand in North America. Changes to any of these or other factors create price volatility.

Crude oil is influenced by the world economy, Organization of the Petroleum Exporting Countries' ("OPEC") ability to adjust supply to world demand and weather. Political events also trigger large fluctuations in price levels. The current global financial crisis has reduced liquidity in financial markets thereby restricting access to financing and has caused significant volatility to commodity prices. Petroleum prices are expected to remain volatile for at least the near term as a result of market uncertainties over the supply and demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing global credit and liquidity concerns.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. 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 although the Canadian dollar has recently decreased from such levels.

A second trend within the Canadian oil and gas industry is the "renewal" of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel. To the extent that this trend continues, we will have to compete with these companies and others to attract qualified personnel.

A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the global economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Kyoto Protocol and other environmental initiatives will have on the sector and, in more recent times, by the tax changes relating to income trusts and other "specified investment flow-through" entities ("SIFTs") and by the NRF and new Alberta government royalty programs implemented along with the NRF. The impact of the NRF and these new royalty programs is still being determined and will vary company to company based on the percentage of production in Alberta, their commodity mix and depths of production, among other things. The amount and degree of these impacts have yet to be determined.

Pursuant to the existing provisions of the Tax Act, to the extent that a SIFT has any income for a taxation year after certain inclusions and deductions, the SIFT will be permitted to deduct all amounts of income which are paid or become payable by it to unitholders in the year. Under the legislation which received Royal Assent on June 22, 2007, SIFTs will be liable for tax at a rate consistent with the taxes currently imposed on corporations commencing in January 2011, provided that the SIFT experiences only "normal growth" and no "undue expansion" before then, in which case the tax could be imposed prior to the January 2011 deadline. Although the tax changes will not affect the method in which we will be taxed, it may have an impact on the ability of a SIFT to purchase producing assets from oil and gas exploration and production companies (as well as the price that a SIFT is willing to pay for such an acquisition) thereby affecting exploration and production companies' ability to be sold to a SIFT which has been a key "exit strategy" in recent years for oil and gas companies. This may be a benefit for us as it will compete with SIFTs for the acquisition of oil and gas properties from junior producers. However, it may also limit our ability to sell producing properties or pursue an exit strategy.

E.	OFF-BALANCE SHEET ARRANGEMENTS

There are no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes of financial condition, revenues, or expenses, results of operations, liquidity, capital expenditures or capital resources, which individually or in the aggregate are material to our investors.

F.	TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

The following table illustrates our contractual obligations as at August 31, 2010.

	Payments Due by Period
	Total		Less than 1 year		1-3 years		4-5 years		After 5 years
Secured note payable current (1)				186,183
Secured note payable long term(1)		1,207,527			$	1,021,344		-		-
Total contractual obligations	$	1,207,527	$	186,183	$	1,021,344		-		-

(1)

Translated at current exchange rate.

Secured Notes Payable

Current

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

Long Term

On August 31, 2010 we assumed $1,201,344 (US$960,000) of Dyami Energy debt by way of a secured promissory note payable (the “Secured Note”). The Secured Note bears interest at 6% per annum, is secured by Dyami Energy’s interests in the Matthews and Murphy Leases and is payable on December 31, 2011 or upon our closing a financing or series of financings in excess of US$4,500,000. We may, in our sole discretion, prepay any portion of the principal amount.

In addition to the contractual financial obligations noted above we have development commitments on our Mathews Lease and Murphy Lease in order to keep the leases in good standing.

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

(a)

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

(b)

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

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

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

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

Murphy Lease, Zavala County

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

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

during the development of the Murphy Lease, Dyami Energy is required to spud a well every180 days, or otherwise release and re-assign its rights to the Murphy Lease, but excluding the unit acreage area it has already drilled and earned. Each period of 180 days, following the drilling of the test well, or abandonment of operation thereon shall be calculated as follows: (i) If the preceding well is drilled and completed, the 180 day period shall commence on the date that production is brought to the surface and the well is flow tested, and (ii) If the well is abandoned as a dry hole (whether temporarily or not) the date that the drilling rig moves off location. Likewise, if a producing well ceases to produce, and such well is not timely re-worked or re-drilled within a six month period, Dyami Energy shall also be required to release and re-assign its rights to the Murphy Lease, but excluding the unit acreage area it has already drilled and earned.

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

On January 20, 2011 we spud our initial well, the Murphy/Dyami 1-H, on our 100% working interest Murphy Lease, Zavala County, Texas. The well was drilled vertically to a depth of 4,588 feet through the Eagle Ford shale to the Buda formation and accordingly Dyami Energy has satisfied (a) above.

The Murphy/Dyami 1-H was logged by Weatherford International and core samples were recovered from the Georgetown, Buda, Eagle Ford Shale, Serpentine and the Escondido formations for interpretation and analysis.

G.	SAFE HARBOR

Certain statements in Sections 5.E and 5.F of this Annual Report may constitute "forward looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Such statements are generally identifiable by the terminology used such as "plans", "expects", "estimates", "budgets", "intends", "anticipates", "believes", "projects", "indicates", "targets", "objective", "could", "may", or other similar words. The forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.	DIRECTORS AND SENIOR MANAGEMENT

The following table sets forth the names of all of our directors and executive officers as of the date of the filing of this Annual Report, with each position and office held by them in our Company, and the period of their service as a director or as an officer.

Name	Age	Position with the Company	Date First Elected as Director
James Cassina	54	President, Chief Executive Officer, Chief Financial Officer and Director	February 9, 2010
Milton Klyman	85	Director	November 15, 1996
Colin McNeil	64	Director	June 18, 2010

All of our directors serve until our next Annual General Meeting or until a successor is duly elected, unless the office is vacated in accordance with our Articles or Bylaws. Subject to the terms of their employment agreements, if any, executive officers are appointed by the Board of Directors to serve until the earlier of their resignation or removal, with or without cause by the directors. James Cassina, our sole executive officer, devotes approximately 40% of his work time to his duties as an officer and director.

There are no family relationships between any of our directors or executive officers. There are no arrangements or understandings between any two or more directors or executive officers.

Mr. Cassina has been an officer since June 18, 2010 a director of ours since February 9, 2010. Mr. Cassina is an officer of Dyami Energy LLC our Texas subsidiary. As Chairman of Assure Energy, Inc. (“Assure”) (OTCBB: ASUR), an oil and gas exploration and production company, Mr. Cassina led Assure’s merger in September 2005 with Geocan Energy Inc. (TSX: GCA) (“Geocan”), an oil and gas company which then grew to daily production of over 3,700 barrels of oil or gas equivalents. Mr. Cassina thereafter served as a Director of Geocan and later Chairperson of its Board appointed Special Advisory Committee formed to seek strategic alternatives to enhance shareholder value. Subsequently Geocan merged with Arsenal Energy Inc. in October 2008. Mr. Cassina served in various senior capacities, including President, and Director from 1999 to 2002 and then Chairman until March 2007 of EnerNorth Industries Inc. (AMEX: ENY), an international enterprise engaged in engineering and offshore fabrication, oil and gas exploration and production, and in India, independent power project development.

Mr. Milton Klyman has been a director of ours since November 15, 1996. Mr. Klyman was also our Treasurer from December 31, 2003 to December 28, 2007. From February 27, 2009 to present, Mr. Klyman has been a director of 1354166 Alberta Ltd., our Alberta subsidiary. Mr. Klyman is a self-employed financial consultant and has been a Chartered Accountant since 1952. Mr. Klyman is a Life Member of the Canadian Institute of Chartered Accountants. Mr. Klyman serves as a director on the boards of Western Troy Capital Resources Inc., and Bonanza Blue Corp. Mr. Klyman served as a director of the EnerNorth from April 2001 until March 21, 2007. .

On March 20, 2007 EnerNorth filed an Assignment in Bankruptcy under the Bankruptcy and Insolvency Act (Canada).

Mr. Colin McNeil, has been a director of ours since June 18, 2010. Mr. McNeil is a self-employed oil and gas consultant and has been a geophysicist since 1972. Mr. McNeil serves as a director of Strategic Oil & Gas. Mr. McNeil has managed exploration programs and structured technical assessments for companies in the Middle East, Africa, Asia, Central and South America, the Arctic, and Canada.Mr. McNeil is a member of the Association of Professional, Engineers, Geologists and Geophysicists of Alberta, Society of Exploration Geophysicists, Canadian Society of Exploration Geophysicists, American Association of Petroleum Geologists and the Canadian Society of Petroleum Geologists.

B.	COMPENSATION

Executive Compensation

The following table presents a summary of all annual and long-term compensation paid by us including our subsidiaries, for services rendered to us by our executive officers and directors in any capacity for the three fiscal years ended August 31, 2010.

Summary Compensation Table (CDN$)

								Non-equity Incentive Plan Compensation
Name and Principal Position	Year	Salary(1)		Share Based Awards		Option Based Awards(2)		Annual Incentive Plans		Long Term Incentive Plans		Pension Value		All Other Compen- sation(3)		Total Compen- sation
		($)		($)		($)		($)		($)		($)		($)		($)
James Cassina.,	2010		0		0		0		0		0		0		600		600
Chief Executive	2009		0		0		0		0		0		0		0		0
Officer,	2008		0		0		0		0		0		0		0		0
President and
Director (4)

Sandra J. Hall,	2010	$	24,000		0		0		0		0		0		1,000	$	25,000
Chief Executive	2009	$	18,000		0		0		0		0		0		200	$	18,200
Officer,	2008	$	12,000		0		0		0		0		0		200	$	12,200
President and
Director (5)

Milton Klyman,	2010		0		0		0		0		0		0		1,300		1,300
Director	2009		0		0		0		0		0		0		200		200
	2008		0		0		0		0		0		0		200		200

Colin McNeil,	2010		0		0		0		0		0		0		400		400
Director(6)	2009		0		0		0		0		0		0		0		0
	2008		0		0		0		0		0		0		0		0

William Jarvis,	2010		0		0		0		0		0		0		1,100		1,100
Director(7)	2009		0		0		0		0		0		0		200		200
	2008		0		0		0		0		0		0		100		100

(1)	Management fees.

(2)	No options have been issued to date.

(3)	Accrued on account of directors fees at a rate of $100 per meeting.

(4)	Mr, Cassina was appointed as our President and Chief Executive and Financial Officer on June 18, 2010.

(5)	Ms. Hall resigned as our Chief Executive and Financial Officer, President, Secretary and Director on June 18, 2010.

(6)	Mr. McNeil was appointed as a Director on June 18, 2010

(7)	Mr. Jarvis resigned as a Director on July 16, 2010.

Compensation Discussion and Analysis

Objective of the Compensation Program

The objectives of the Company's compensation program are to attract, hold and inspire performance of its named executive officers (“NEOs”) of a quality and nature that will enhance the sustainable profitability and growth of the Company. The Company views it as an important objective of the Company's compensation program to ensure staff retention.

The Compensation Review Process

To determine compensation payable, the compensation committee of the Company (the "Compensation Committee") determines an appropriate compensation reflecting the need to provide incentive and compensation for the time and effort expended by the NEOs of the Company while taking into account the financial and other resources of the Company.

The Company’s Compensation Committee is comprised of Milton Klyman (Chair) and Colin McNeil. The Compensation Committee is comprised entirely of independent directors. Compensation is determined in the context of our strategic plan, our growth, shareholder returns and other achievements and considered in the context of position descriptions, goals and the performance of each NEO. With respect to directors’ compensation, the Compensation Committee reviews the level and form of compensation received by the directors, members of each committee, the board chair and the chair of each board committee, considering the duties and responsibilities of each director, his or her past service and continuing duties in service to us. The compensation of directors, the CEO and executive officers of competitors are considered, to the extent publicly available, in determining compensation and the Compensation Committee has the power to engage a compensation consultant or advisor to assist in determining appropriate compensation.

Elements of Executive Compensation

The Company's NEO compensation program is based on the objectives of: (a) recruiting and retaining the executives critical to the success of the Company; (b) providing fair and competitive compensation; (c) balancing the interests of management and shareholders of the Company; and (d) rewarding performance, on the basis of both individual and corporate performance.

For the financial year ended August 31, 2010, the Company's NEO compensation program consisted of the following elements:

(a)

a base salary/management fee (the "Short-Term Incentive").

(b)

a long-term equity compensation consisting of stock options granted under the Company's stock incentive plan ("Long-Term Incentive").

The specific rationale and design of each of these elements are outlined in detail below.

Short-Term Incentive

Salaries form an essential element of the Company's compensation mix as they are the first base measure to compare and remain competitive relative to peer groups. Base salaries are fixed and therefore not subject to uncertainty and are used as the base to determine other elements of compensation and benefits. The base salary provides an immediate cash incentive for the Named Executive Officers. The Compensation Committee and the Board review salaries at least annually.

Base salary/management fees of the Named Executive Officer is set by the Compensation Committee on the basis of the applicable officer’s responsibilities, experience and past performance. In determining the base salary to be paid to a particular Named Executive Officer, the Compensation Committee considers the particular responsibilities related to the position, the experience level of the officer, and his or her past performance at the Company and the current financial position of the Company.

Long-Term Incentive

The granting of stock options is a variable component of compensation intended to reward the Company's Named Executive Officers for their success in achieving sustained, long-term profitability and increases in stock value. Stock options ensure that the Named Executive Officers are motivated to achieve long-term growth of the Company and continuing increases in shareholder value. In terms of relative emphasis, the Company places more importance on stock options.

The Company provides long-term incentive compensation through its stock option plan. The Compensation Committee recommends the granting of stock options from time to time based on its assessment of the appropriateness of doing so in light of the long-term strategic objectives of the Company, its current stage of development, the need to retain or attract particular key personnel, the number of stock options already outstanding and overall market conditions. The Compensation Committee views the granting of stock options as a means of promoting the success of the Company and higher returns to its shareholders. The Board grants stock options after reviewing recommendations made by the Compensation Committee.

As of our fiscal year end August 31, 2010 we had no option/stock appreciation rights or grants outstanding.

Stock Option Plan

The Company’s Stock Option Plan (the "Plan") was adopted by the board of directors on January 26, 2010 and approved by a majority of our shareholders voting at the Annual and Special Meeting held on February 9, 2010. The Plan was adopted in order that we may be able to provide incentives for directors, officers, employees, consultants and other persons (an "Eligible Individual") to participate in our growth and development by providing us with the opportunity through share options to acquire an ownership interest in us. Directors and officers currently are not remunerated for their services except as stated in "Executive Compensation" above.

The maximum number of common shares which may be set aside for issue under the Plan is currently 4,846,512 common shares, provided that the board has the right, from time to time, to increase such number subject to the approval of our shareholders and any relevant stock exchange or other regulatory authority. The maximum number of common shares which may be reserved for issuance to any one person under the plan is 5% of the common shares outstanding at the time of the grant less the number of shares reserved for issuance to such person under any options for services or any other stock option plans. Any common shares subject to an option, which are not exercised, will be available for subsequent grant under the Plan. The option price of any common shares cannot be less than the closing sale price of such shares quoted on any trading system or on such stock exchange in Canada on which the common shares are listed and posted for trading as may be selected for such purpose by the board of directors, on the day immediately preceding the day upon which the grant of the option is approved by the board of directors.

Options granted under the Plan may be exercised during a period no exceeding five years, subject to earlier termination upon the optionee ceasing to be an Eligible Individual, or, in accordance with the terms of the grant of the option. The options are non-transferable and non-assignable except between an Eligible Individual and a related corporation controlled by such Eligible Individual upon the consent of the board of directors. The Plan contains provisions for adjustment in the number of shares issuable there under in the event of subdivision, consolidation, reclassification, reorganization or change in the number of common shares, a merger or other relevant change in the Company’s capitalization. The board of directors may from time to time amend or revise the terms of the Plan or may terminate the Plan at any time. The Company is seeking shareholder approval to amend the Plan to, among other things, increase the maximum aggregate number of common shares reserved for issuance under the Plan, to an amount equal to 20% of the 30,851,026 issued and outstanding common shares (6,170,205) common shares) of the Company as at the January 14, 2011 date of the Notice of Meeting.

The Company does not have any other long-term incentive plans, including any supplemental executive retirement plans.

Overview of How the Compensation Program Fits with Compensation Goals

The compensation package is designed to meet the goal of attracting, holding and motivating key talent in a highly competitive oil and gas exploration environment through salary and providing an opportunity to participate in the Company’s growth through stock options. Through the grant of stock options, if the price of the Company shares increases over time, both the Named Executive Officer and shareholders will benefit.

Incentive Plan Awards

There are no incentive plan awards outstanding for any of the Named Executive Officers as of August 31, 2010.

Pension Plan Benefits

The Company does not currently provide pension plan benefits to its Named Executive Officers.

Termination and Change of Control Benefits

The Company does not currently have executive employment agreements in place with any of its Named Executive Officers.

The Company has no compensatory plan, contract or arrangement where a named executive officer or director is entitled to receive compensation in the event of resignation, retirement, termination, change of control or a change in responsibilities following a change in control.

Director Compensation

Each director of the Company is entitled to receive the sum of $100 for each meeting of the directors, meeting of a committee of the directors or meeting of the shareholders attended. During the fiscal year ended August 31, 2010 no amount was paid by the Company with respect to such fees.

Retirement Policy for Directors

The Company does not have a retirement policy for its directors.

Directors’ and Officers’ Liability Insurance

The Company does not maintain directors’ and officers’ liability insurance.

C.	BOARD PRACTICES

Board of Directors

The mandate of our board of directors, prescribed by the Business Corporations Act (Ontario), is to manage or supervise the management of our business and affairs and to act with a view to our best interests. In doing so, the board oversees the management of our affairs directly and through its committees.

The term of Mr. Klyman as a director began on August 10, 2000. Mr. Cassina was appointed as a director on February 9, 2010 and Mr. McNeil who was appointed on June 18, 2010. Our directors serve until our next Annual General Meeting or until a successor is duly elected, unless the office is vacated in accordance with our Articles or Bylaws. Our sole executive officer was appointed by our Board of Directors to serve until the earlier of her resignation or removal, with or without cause by the directors. There was no compensation paid by us to our directors during the fiscal year ended August 31, 2010 for their services in their capacity as directors or any compensation paid to committee members.

As of August 31, 2010 our board of directors consists of three directors, two of which are "independent directors" in that they are "independent from management and free from any interest and any business or other relationship which could, or could reasonably be perceived to, materially interfere with the directors ability to act with a view to our best interests, other than interests and relationships arising from shareholding". The independent directors are Milton Klyman and Colin McNeil. It is our practice to attempt to maintain a diversity of professional and personal experience among our directors.

The independent directors of the Company do not hold regularly scheduled meetings at which non-independent directors and members of management are not in attendance. The Company holds meetings as required, at which the opinions of the independent directors are sought and duly acted upon for all material matters relating to the Company.

Directorships

The following directors of ours are directors of other Canadian or United States reporting issuers as follows:

Colin McNeil	Strategic Oil & Gas Ltd.
Milton Klyman	Bonanza Blue Corp. and Western Troy Capital Resources Inc.
James Cassina	Single Touch Systems Inc. and Bonanza Blue Corp.

Board and Committee Meetings

The board of directors has met at least once annually or otherwise as circumstances warrant to review our business operations, corporate governance and financial results. The table below reflects the attendance of each director of ours at each Board and committee meeting of the Board during the fiscal year ended August 31, 2010.

Name	Board of Directors Meetings		Audit Committee Meetings		Compensation Committee Meetings		Petroleum and Natural Gas Committee Meetings		Disclosure Committee Meetings
Milton Klyman		7		4		1		1	Nil
William Jarvis(1)		6		3		1		1	Nil
Sandra Hall(2)		5		3	Nil			1	Nil
James Cassina (3)		5		1	Nil		Nil		Nil
Colin McNeil(4)		3		1	Nil		Nil		Nil

(1) Mr. Jarvis resigned as a director on July 16, 2010.

(2) Ms. Hall resigned as President, Secretary and Director on June 18, 2010

(3) Mr. Cassina was appointed a director at our Annual and Special Meeting of Shareholders held on February 9, 2010 and President on June 18, 2010.

(4) Mr. McNeil was appointed director on June 18, 2010.

Board Mandate

The Board assumes responsibility for stewardship of the Company, including overseeing all of the operation of the business, supervising management and setting milestones for the Company. The Board reviews the statements of responsibilities for the Company including, but not limited to, the code of ethics and expectations for business conduct.

The Board approves all significant decisions that affect the Company and its subsidiaries and sets specific milestones towards which management directs their efforts.

The Board ensures, at least annually, that there are long-term goals and a strategic planning process in place for the Company and participates with management directly or through its committees in developing and approving the mission of the business of the Company and the strategic plan by which it proposes to achieve its goals, which strategic plan takes into account, among other things, the opportunities and risks of the Company's business. The strategic planning process is carried out at each Board meeting where there are regularly reviewed specific milestones for the Company.

The strategic planning process incorporates identifying the main risks to the Company's objectives and ensuring that mitigation plans are in place to manage and minimize these risks. The Board also takes responsibility for identifying the principal risks of the Company's business and for ensuring these risks are effectively monitored and mitigated to the extent practicable. The Board appoints senior management.

The Company adheres to regulatory requirements with respect to the timeliness and content of its disclosure. The Board approves all of the Company's major communications, including annual and quarterly reports and press releases. The Chief Executive Officer authorizes the issuance of news releases. The Chief Executive Officer is generally the only individual authorized to communicate with analysts, the news media and investors about information concerning the Company.

The Board and the audit committee of the Company (the "Audit Committee") examines the effectiveness of the Company's internal control processes and information systems.

The Board as a whole, given its small size, is involved in developing the Company's approach to corporate governance. The number of scheduled board meetings varies with circumstances. In addition, special meetings are called as necessary. The Chief Executive Officer establishes the agenda at each Board meeting and submits a draft to each director for their review and recommendation for items for inclusion on the agenda. Each director has the ability to raise subjects that are not on the agenda at any board meeting. Meeting agendas and other materials to be reviewed and/or discussed for action by the Board are distributed to directors in time for review prior to each meeting. Board members have full and free access to senior management and employees of the Company.

Position Descriptions

The Board has not developed written position descriptions for the Chairman of the Board or the Chief Executive Officer. The Board is currently of the view that the respective corporate governance roles of the Board and management, as represented by the Chief Executive Officer, are clear and that the limits to management's responsibility and authority are well-defined.

Each of the Audit Committee, Compensation Committee, Disclosure Committee and a Petroleum and Natural Gas Committee has a chair and a mandate.

Orientation and Continuing Education

We have developed an orientation program for new directors including a director’s manual ("Director’s Manual") which contains information regarding the roles and responsibilities of the board, each board committee, the board chair, the chair of each board committee and our president. The Director’s Manual contains information regarding its organizational structure, governance policies including the Board Mandate and each Board committee charter, and our code of business conduct and ethics. The Director’s Manual is updated as our business, governance documents and policies change. We update and inform the board regarding corporate developments and changes in legal, regulatory and industry requirements affecting us.

Ethical Business Conduct

We have adopted a written code of business conduct and ethics (the "Code") for our directors, officers and employees. The board encourages following the Code by making it widely available. It is distributed to directors in the Director’s Manual and to officers, employees and consultants at the commencement of their employment or consultancy. The Code reminds those engaged in service to us that they are required to report perceived or actual violations of the law, violations of our policies, dangers to health, safety and the environment, risks to our property, and accounting or auditing irregularities to the chair of the Audit Committee who is an independent director of ours. In addition, to requiring directors, officers and employees to abide by the Code, we encourage consultants, service providers and all parties who engage in business with us to contact the chair of the Audit Committee regarding any perceived and all actual breaches by our directors, officers and employees of the Code. The chair of our Audit Committee is responsible for investigating complaints, presenting complaints to the applicable board committee or the board as a whole, and developing a plan for promptly and fairly resolving complaints. Upon conclusion of the investigation and resolution of a complaint, the chair of our Audit Committee will advise the complainant of the corrective action measures that have been taken or advise the complainant that the complaint has not been substantiated. The Code prohibits retaliation by us, our directors and management, against complainants who raise concerns in good faith and requires us to maintain the confidentiality of complainants to the greatest extent practical. Complainants may also submit their concerns anonymously in writing. In addition to the Code, we have an Audit Committee Charter and a Policy of Procedures for Disclosure Concerning Financial/Accounting Irregularities.

Since the beginning of our most recently completed financial year, no material change reports have been filed that pertain to any conduct of a director or executive officer that constitutes a departure from the Code. The board encourages and promotes a culture of ethical business conduct by appointing directors who demonstrate integrity and high ethical standards in their business dealings and personal affairs. Directors are required to abide by the Code and expected to make responsible and ethical decisions in discharging their duties, thereby setting an example of the standard to which management and employees should adhere. The board is required by the Board Mandate to satisfy our CEO and other executive officers are acting with integrity and fostering a culture of integrity throughout the Company. The board is responsible for reviewing departures from the Code, reviewing and either providing or denying waivers from the Code, and disclosing any waivers that are granted in accordance with applicable law. In addition, the board is responsible for responding to potential conflict of interest situations, particularly with respect to considering existing or proposed transactions and agreements in respect of which directors or executive officers advise they have a material interest. The Board Mandate requires that directors and executive officers disclose any interest and the extent, no matter how small, of their interest in any transaction or agreement with us, and that directors excuse themselves from both board deliberations and voting in respect of transactions in which they have an interest. By taking these steps the board strives to ensure that directors exercise independent judgment, unclouded by the relationships of the directors and executive officers to each other and us, in considering transactions and agreements in respect of which directors and executive officers have an interest.

Nomination of Directors

The Board has not appointed a nominating committee and does not believe that such a committee is warranted at the present time. The entire Board determines new nominees to the Board, although a formal process has not been adopted. The nominees are generally the result of recruitment efforts by the Board members, including both formal and informal discussions among Board members and officers. The Board generally looks for the nominee to have direct experience in the oil and gas business and significant public company experience. The nominee must not have a significant conflicting public company association.

Compensation

The Board determines director and executive officer compensation by recommendation of the Compensation Committee. The Company's Compensation Committee reviews the amounts and effectiveness of compensation. Each of the members of the Compensation Committee are independent. The Board reviews the adequacy and form of compensation and compares it to other companies of similar size and stage of development. There is no minimum share ownership requirement of directors.

The Compensation Committee convenes at least once annually to review director and officer compensation and status of stock options. The Compensation Committee also responds to requests from management and the Board to review recommendations of management for new senior employees and their compensation. The Compensation Committee has the power to approve and/or amend these recommendations.

The Company has felt no need to retain any compensation consultants or advisors at any time since the beginning of the Company's most recently completed financial year.

Committees of the Board

Our board of directors discharges its responsibilities directly and through committees of the board of directors, currently consisting of the Audit Committee, a compensation committee (the "Compensation Committee"), a disclosure committee (the "Disclosure Committee") and a petroleum and natural gas committee (the "Petroleum and Natural Gas Committee").

Each of the Audit Committee, Disclosure Committee and the Petroleum and Natural Gas Committee consists of a majority of independent directors, while the Compensation Committee consists of independent directors. Each Committee has a specific mandate and responsibilities, as reflected in the charters for each committee.

Audit Committee

The mandate of the Audit Committee is formalized in a written charter. The members of the Audit Committee are James Cassina, Milton Klyman (Chair) and Colin McNeil. Based on his professional certification and experience, the board has determined that Milton Klyman is an Audit Committee Financial Expert and that James Cassina and Colin McNeil are financially literate. The Audit Committee's primary duties and responsibilities are to serve as an independent and objective party to monitor our financial reporting process and control systems, review and appraise the audit activities of our independent auditors, financial and senior management, and the lines of communication among the independent auditors, financial and senior management, and the board of directors for financial reporting and control matters including investigating fraud, illegal acts or conflicts of interest.

Compensation Committee

The mandate of the Compensation Committee is formalized in a written charter. The members of the Compensation Committee are Colin McNeil and Milton Klyman (Chair). The Compensation Committee is comprised entirely of independent directors. Compensation is determined in the context of our strategic plan, our growth, shareholder returns and other achievements and considered in the context of position descriptions, goals and the performance of each individual director and officer. With respect to directors’ compensation, the Compensation Committee reviews the level and form of compensation received by the directors, members of each committee, the board chair and the chair of each board committee, considering the duties and responsibilities of each director, his or her past service and continuing duties in service to us. The compensation of directors, the CEO, CFO and executive officers of competitors are considered, to the extent publicly available, in determining compensation and the Compensation Committee has the power to engage a compensation consultant or advisor to assist in determining appropriate compensation.

Disclosure Committee

The mandate of the Disclosure Committee is formalized in a written charter. The members of the Disclosure Committee are Milton Klyman, Colin McNeil and James Cassina (Chair). The Committee's duties and responsibilities include, but are not limited to, review and revise our controls and other procedures ("Disclosure and Controls Procedures") to ensure that (i) information required by us to be disclosed to the applicable regulatory authorities and other written information that we will disclose to the public is reported accurately and on a timely basis, and (ii) such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure; assist in documenting and monitoring the integrity and evaluating the effectiveness of the Disclosure and Control Procedures; the identification and disclosure of material information about us, the accuracy completeness and timeliness of our financial reports and all communications with the investing public are timely, factual and accurate and are conducted in accordance with applicable legal and regulatory requirements.

Petroleum and Natural Gas Committee

The members of the Petroleum and Natural Gas Committee are Milton Klyman, James Cassina and Colin McNeil (Chair). The Petroleum and Natural Gas Committee has the responsibility of meeting with the independent engineering firms commissioned to conduct the reserves evaluation on our oil and natural gas assets and to discuss the results of such evaluation with each of the independent engineers and management. Specifically, the Petroleum and Natural Gas Committee’s responsibilities include, but are not limited to, a review of management’s recommendations for the appointment of independent engineers, review of the independent engineering reports and considering the principal assumptions upon which such reports are based, appraisal of the expertise of the independent engineering firms retained to evaluate our reserves, review of the scope and methodology of the independent engineers’ evaluations, reviewing any problems experienced by the independent engineers in preparing the reserve evaluation, including any restrictions imposed by management or significant issues on which there was a disagreement with management and a review of reserve additions and revisions which occur from one report to the next.

Assessments

The board assesses, on an annual basis, the contributions of the board as a whole, the Audit Committee and each of the individual directors, in order to determine whether each is functioning effectively. The board monitors the adequacy of information given to directors, communication between the board and management and the strategic direction and processes of the board and committees. The Audit Committee will annually review the Audit Committee Charter and recommend, if any, revisions to the board as necessary.

Audit Committee

The mandate of the Audit Committee is formalized in a written charter. The members of the audit committee of the board are James Cassina, Milton Klyman (Chairman) and Colin McNeil. Based on his professional certification and experience, the board has determined that Milton Klyman is an Audit Committee Financial Expert and that Colin McNeil and James Cassina are financially literate. The audit committee's primary duties and responsibilities are to serve as an independent and objective party to monitor our financial reporting process and control systems, review and appraise the audit activities of our independent auditors, financial and senior management, and the lines of communication among the independent auditors, financial and senior management, and the board of directors for financial reporting and control matters including investigating fraud, illegal acts or conflicts of interest.

Relevant Education and Experience of Audit Committee Members

Milton Klyman is the Chairman of the Audit Committee. He is a self-employed financial consultant and has been a Chartered Accountant since 1952. Milton Klyman is a Life Member of the Institute of Chartered Accountants of Ontario, a Life member of the Canadian Institute of Mining Metallurgy and Petroleum and a Fellow of the Institute of Chartered Secretaries and Administrators.

James Cassina is a consultant in business development, mergers and acquisitions and corporate finance. James Cassina has served as a director and held various executive positions with public companies.

Colin McNeil is an independent consulting geophysicist and has managed exploration programs and structured technical assessments for companies in the Middle East, Africa, Asia, Central and South America, the Arctic, and Canada Colin McNeil has served as a director and held various positions with public and private companies.

Audit Committee Charter

•

Our Audit Committee Charter (the “Charter”) has been adopted by our board of directors. The Audit Committee of the board (the “Committee”) will review and reassess this charter annually and recommend any proposed changes to the board for approval. The Audit Committee’s primary duties and responsibilities are to:

•

Oversee (i) the integrity of our financial statements; (ii) our compliance with legal and regulatory requirements; and (iii) the independent auditors’ qualifications and independence.

•

Serve as an independent and objective party to monitor our financial reporting processes and internal control systems.

•

Review and appraise the audit activities of our independent auditors and the internal auditing functions.

•

Provide open lines of communication among the independent auditors, financial and senior management, and the board for financial reporting and control matters.

Role and Independence: Organization

The Committee assists the board on fulfilling its responsibility for oversight of the quality and integrity of our accounting, auditing, internal control and financial reporting practices. It may also have such other duties as may from time to time be assigned to it by the board.

The Audit Committee is to be comprised of at least three directors. The majority of the Committee members must be independent from management and free from any relationship that, in the opinion of the Board, would interfere with the exercise of his or her independent judgment as a member of the Committee.

All members shall, to the satisfaction of the board, be financially literate (i.e. will have the ability to read and understand a balance sheet, an income statement, a cash flow statement and the notes attached thereto), and at least one member shall have accounting or related financial management expertise to qualify as “financially sophisticated”. A person will qualify as “financially sophisticated” if an individual who possesses the following attributes:

•

an understanding of financial statements and generally accepted accounting principles;

•

an ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

•

experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by our financial statements, or experience actively supervising one or more persons engaged in such activities;

•

an understanding of internal controls and procedures for financial reporting; and

•

an understanding of audit committee functions.

Colin McNeil and Milton Klyman are “independent” as defined by the Securities and Exchange Commission, and the Board has determined that Milton Klyman is an “audit committee financial expert” as defined in Item 401(h) of Regulation S-K promulgated by the Securities and Exchange Commission.

The Committee members will be elected annually at the first meeting of the Board following the annual meeting of shareholders. Each member of the Committee serves during the pleasure of the Board and, in any event, only so long as he or she is a director.

One member of the Committee shall be appointed as chair. The chair shall be responsible for leadership of the Committee, including scheduling and presiding over meetings and making regular reports to the Board. The chair will also maintain regular liaison with the CEO, CFO, and the lead independent audit partner.

Responsibilities and Powers

Although the Committee may wish to consider other duties from time to time, the general recurring activities of the Committee in carrying out its oversight role are described below.

Annual review and revision of the Charter as necessary with the approval of the board.

Review and obtain from the independent auditors a formal written statement delineating all relationships between the auditor and us, consistent with Independence Standards Board Standard 1.

Recommending to the board the independent auditors to be retained (or nominated for shareholder approval) to audit our financial statements. Such auditors are ultimately accountable to the board and the Committee, as representatives of the shareholders.

Evaluating, together with the board and management, the performance of the independent auditors and, where appropriate, replacing such auditors.

Obtaining annually from the independent auditors a formal written statement describing all relationships between the auditors and us. The Committee shall actively engage in a dialogue with the independent auditors with respect to any relationship that may impact the objectivity and the independence of the auditors and shall take, or recommend that the board take, appropriate actions to oversee and satisfy itself as to the auditors’ independence.

Ensuring that the independent auditors are prohibited from providing the following non-audit services and determining which other non-audit services the independent auditors are prohibited from providing:

Bookkeeping or other services related to our accounting records or consolidated financial statements;

Financial information systems design and implementation;

Appraisal or valuation services, fairness opinions, or contribution-in-kind reports;

Actuarial services;

Internal audit outsourcing services;

Management functions or human resources;

Broker or dealer, investment advisor or investment banking services;

Legal services and expert services unrelated to the audit; and

Any other services which the Public Company Accounting Oversight Board determines to be impermissible.

Approving any permissible non-audit engagements of the independent auditors.

Meeting with our auditors and management to review the scope of the proposed audit for the current year, and the audit procedures to be used, and to approve audit fees.

Reviewing the audited consolidated financial statements and discussing them with management and the independent auditors. Consideration of the quality our accounting principles as applied in its financial reporting. Based on such review, the Committee shall make its recommendation to the Board as to the inclusion of our audited consolidated financial statement in our Annual Report to Shareholders.

Discussing with management and the independent auditors the quality and adequacy of and compliance with our internal controls.

Establishing procedures: (i) for receiving, handling and retaining of complaints received by us regarding accounting, internal controls, or auditing matters, and (ii) for employees to submit confidential anonymous concerns regarding questionable accounting or auditing matters.

Review and discuss all related party transactions involving us.

Engaging independent counsel and other advisors if the Committee determines that such advisors are necessary to assist the Committee in carrying out its duties.

Publicly disclose the receipt of warning about any violations of corporate governance rules.

Authority

The Committee will have the authority to retain special legal, accounting or other experts for advice, consultation or special investigation. The Committee may request any officer or employee of ours, our outside legal counsel, or the independent auditor to attend a meeting of the Committee, or to meet with any member of, or consultants to, the Committee. The Committee will have full access to our books, records and facilities.

Meetings

The Committee shall meet at least yearly, or more frequently as the Committee considers necessary. Opportunities should be afforded periodically to the external auditor and to senior management to meet separately with the independent members of the Committee. Meetings may be with representatives of the independent auditors, and appropriate members of management, all either individually or collectively as may be required by the Chairman of the Committee.

The independent auditors will have direct access to the Committee at their own initiative.

The Chairman of the Committee will report periodically the Committee’s findings and recommendations to the board of directors.

EMPLOYEES

As of August 31, 2010 and the date of the filing of this Annual Report we did not have any employees other than our sole executive officer.

E.	SHARE OWNERSHIP

Our common shares are owned by Canadian residents, United States residents and residents of other countries. The only class of our securities, which is outstanding as of the date of the filing of this Annual Report, is common stock. All holders of our common stock have the same voting rights with respect to their ownership of our common stock.

The following table sets forth as of the date of the filing of this Annual Report, certain information with respect to the amount and nature of beneficial ownership of the common stock held by (i) each person known to our management to be the beneficial owner of more than 5% of our outstanding shares of common stock; (ii) each person who is a director or an executive officer of ours; and (iii) all directors and executive officers of ours, as a group. Shares of our common stock subject to options, warrants, or convertible securities currently exercisable or convertible or exercisable or convertible within 60 days of the date of filing of this Annual Report are deemed outstanding for computing the share ownership and percentage of the person holding such options, warrants, or convertible securities but are not deemed outstanding for computing the percentage of any other person.

Name and Owner	Identity	Amount and Nature of Beneficial Ownership of Common Stock (1)			Percentage

Milton Klyman	Director		100,000	(2)		0.3	%
Colin McNeil	Director		0			0	%
Core Energy Enterprise, Inc. (3)	Principal Shareholder		4,073,208	(4)		12.38	%
James Cassina	Director and Principal Shareholder		12,065,046	(5)		32.68	%
Tonbridge Financial Corp.	Principal Shareholder		5,483,414	(6)		16.31	%
Benchmark Enterprises LLC	Shareholder		1,743,418	(7)		5.54	%
Eric Johnson	Vice President, Operations Dyami Energy		3,384,282	(8)		8.08	%
Gottbetter Capital Group, Inc.	Shareholder		2,416,881	(9)		7.78	%
All officers and directors as a group (3 persons)			12,165,046	(2)(5)		32.7	%

(1)

Unless otherwise indicated, the persons named have sole ownership, voting and investment power with respect to their stock, subject to applicable laws relative to rights of spouses. Percentage ownership is based on 30,876,273 shares of common stock outstanding as of the date of filing of this Annual Report.

(2)	Includes 50,000 shares underlying 50,000 presently exercisable warrants.

(3)	James Cassina has voting and investment power with respect to the shares of our common stock owned by Core Energy Enterprises Inc.

(4)	Includes 2,036,604 shares underlying 2,036,604 presently exercisable warrants.

(5)	Includes 2,036,604 outstanding shares and 2,036,604 shares underlying 2,036,604 presently exercisable warrants owned by Core Energy Enterprises Inc. Also includes 3,995,919 shares underlying 3,995,919 presently exercisable warrants owned directly by James Cassina.

(6)	Includes 2,741,707 shares underlying 2,741,707 presently exercisable warrants. David Yuhasz has voting and investment power with respect to the shares owned by Tonbridge Financial Corp.

(7)

Includes 1,162,279 shares and 581,139 shares underlying presently exercisable warrants. 581,140 shares and 290,570 warrants are being held in escrow until such time that we receive a NI 51-101 compliant report from an independent engineering firm indicating at least 100,000 boe of proven reserves on either the Murphy Lease or any formation below the San Miguel formation on the Matthews Lease. Andrew Godfrey has voting and investment power with respect to the shares owned by Benchmark Enterprises LLC.

(8)

Includes 2,256,188 shares and 1,128,094 shares underlying presently exercisable warrants. 1,128,094 shares and 564,047 warrants are being held in escrow until such time that we receive a NI 51-101 compliant report from an independent engineering firm indicating at least 100,000 boe of proven reserves on either the Murphy Lease or any formation below the San Miguel formation on the Matthews Lease.

(9)	Includes 2,243,881 shares and 173,000 shares underlying presently exercisable warrants. Adam Gottbetter has voting and investment power with respect to the shares owned by Gottbetter Capital Group, Inc.

As of the date of the filing of this Annual Report, to the knowledge of our management, there are no arrangements which, could at a subsequent date result in a change in control of us. As of such date, and except as disclosed herein, our management has no knowledge that we are owned or controlled directly or indirectly by another company or any foreign government.

Amendments to our Stock Option Plan (as amended, the "Plan") were adopted by our board of directors on January 8, 2010 and approved by a majority of our shareholders voting at the Annual and Special Meeting held on February 9, 2010. The Plan was adopted in order that we may be able to provide incentives for directors, officers, employees, consultants and other persons (an "Eligible Individual") to participate in our growth and development by providing us with the opportunity through share options to acquire an ownership interest in us. Directors and officers currently are not remunerated for their services except as stated in "Executive Compensation" above.

The maximum number of common shares which may be set aside for issue under the Plan is currently 4,846,152 common shares, provided that the board has the right, from time to time, to increase such number subject to the approval of our shareholders and any relevant stock exchange or other regulatory authority. The maximum number of common shares which may be reserved for issuance to any one person under the plan is 5% of the common shares outstanding at the time of the grant less the number of shares reserved for issuance to such person under any options for services or any other stock option plans. Any common shares subject to an option, which are not exercised, will be available for subsequent grant under the Plan. The option price of any common shares cannot be less than the closing sale price of such shares quoted on any trading system or on such stock exchange in Canada on which the common shares are listed and posted for trading as may be selected for such purpose by the board of directors, on the day immediately preceding the day upon which the grant of the option is approved by the board of directors.

At our Annual and Special Meeting slated to be held on February 24, 2011 shareholders will be asked to approve a further amendment to our Plan which was adopted by our board of directors on December 21, 2010 to increase the number of common shares which may be set aside for issue under the Plan to 6,170,205 common shares. Options granted under the Plan may be exercised during a period no exceeding five years, subject to earlier termination upon the optionee ceasing to be an Eligible Individual, or, in accordance with the terms of the grant of the option. The options are non-transferable and non-assignable except between an Eligible Individual and a related corporation controlled by such Eligible Individual upon the consent of the board of directors. The Plan contains provisions for adjustment in the number of shares issuable there under in the event of subdivision, consolidation, reclassification, reorganization or change in the number of common shares, a merger or other relevant change in the Company’s capitalization. The Company does not have any other long-term incentive plans, including any supplemental executive retirement plans.

ITEM 7 MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.	MAJOR SHAREHOLDERS

There are 30,876,273 issued and outstanding shares of our common stock as of January 31, 2011. As of January 31, 2011, to the best of our knowledge, no persons hold directly or indirectly or exercise control or direction over, shares of our common stock carrying 5% or more of the voting rights attached to all issued and outstanding shares of the common stock except as stated under Item 6.E above or set out in the table below. The shares of our common stock owned by our major shareholders have identical voting rights as those owned by our other shareholders.

Name	Number of Shares			Percentage
James Cassina		12,065,046	(1)		32.68	%
Core Energy Enterprises Inc. (2)		4,073,208	(3)		12.38	%
Tonbridge Financial Corp.		5,483,414	(4)		16.31	%
Eric Johnson		3,384,282	(5)		8.08	%
Gottbetter Capital Group, Inc.		2,416,881	(6)		7.78	%
Benchmark Enterprises LLC		1,743,418	(7)		5.54	%

(1)	Includes 2,036,604 shares and 2,036,604 shares underlying presently exercisable warrants owned by Core Energy Enterprises Inc. Also includes 3,995,919 shares and 3,995,919 shares underlying presently exercisable warrants owned directly by James Cassina.

(2)	James Cassina has voting and investment power with respect to the shares of our common stock owned by Core Energy Enterprises Inc.

(3)	Includes 2,036,604 shares and 2,036,604 shares underlying presently exercisable warrants.

(4)	Includes 2,741,707 shares underlying 2,741,707 presently exercisable warrants. David Yuhasz has voting and investment power with respect to the shares owned by Tonbridge Financial Corp.

(5)

Includes 2,256,188 shares and 1,128,094 shares underlying presently exercisable warrants. 1,128,094 shares and 564,047 warrants being held in escrow until such time that we receive a NI 51-101 compliant report from an independent engineering firm indicating at least 100,000 boe of proven reserves on either the Murphy Lease or any formation below the San Miguel formation on the Matthews Lease.

(6)	Includes 2,243,881 shares and 173,000 shares underlying presently exercisable warrants. Adam Gottbetter has voting and investment power with respect to the shares owned by Gottbetter Capital Group, Inc.

(7)

Includes 1,162,279 shares and 581,139 shares underlying presently exercisable warrants. 581,140 shares and 290,570 warrants being held in escrow until such time that we receive a NI 51-101 compliant report from an independent engineering firm indicating at least 100,000 boe of proven reserves on either the Murphy Lease or any formation below the San Miguel formation on the Matthews Lease. Andrew Godfrey has voting and investment power with respect to the shares owned by Benchmark Enterprises LLC.

The following table discloses the geographic distribution of the majority of the holders of record of our common stock as of date of January 31, 2010.

Country	Number of Shareholders		Number of Shares		Percentage of Shareholders			Percentage of Share
Canada		1,077		12,413,786		96.40	%		40.21	%
USA		32		7,506,951		2.86	%		24.31	%
All Other		8		10,955,536		0.74	%		35.48	%
Total		1,117		30,876,273		100	%		100	%

We are not directly or indirectly owned or controlled by another corporation, by any foreign government or by any other natural or legal person. There are no arrangements known to us, the operation of which may at a subsequent date result in a change in the control of us.

B.	RELATED PARTY TRANSACTIONS

During the fiscal year ended August 31, 2010 and through the date of the filing of this Annual Report, we have entered into the related party transactions described below.

From May 1, 2009 to June 18, 2010 we paid a management fee of $2,500 per month to our former President, Sandra Hall.

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

At August 31, 2010 the we have a secured promissory note in the amount of $1,021,044 (US$960,000) payable to Benchmark Enterprises LLC (``Benchmark``). At August 31, 2010 interest accrued on the secured note of $26,862 (US$25,249) is included in accounts payable. Benchmark is a shareholder of ours.

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

Inter-Company Balances

As at August 31, 2010, the inter-company balance due from our wholly owned subsidiary 1354166 Alberta was $88,000. As at August 31, 2010, the inter-company balance due from our wholly owned subsidiary Dyami Energy was $1,073,005. As of January 31, 2011, the inter-company balance due from 1354166 Alberta is $88,000 and the inter-company balance due from Dyami Energy is $2,948,823.

C.	INTERESTS OF EXPERTS AND COUNSEL

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 8 FINANCIAL INFORMATION

A.	CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION

The financial statements required as part of this Annual Report are filed under Item 17 of this Annual Report.

Litigation

There are no pending legal proceedings to which we or our subsidiary is a party or of which any of our property is the subject. There are no legal proceedings to which any of the directors, officers or affiliates or any associate of any such directors, officers or affiliates of either our company or our subsidiary is a party or has a material interest adverse to us.

Dividends

We have not paid any dividends on our common stock during the past five years. We do not intend to pay dividends on shares of common stock in the foreseeable future as we anticipate that our cash resources will be used to finance growth.

B.	SIGNIFICANT CHANGES

There have been no significant changes that have occurred since the date of our annual financial statements included with this Annual Report except as disclosed in the Annual Report.

ITEM 9 THE OFFER AND LISTING

Common Shares

Our authorized capital consists of an unlimited number of common shares without par value, of which 30,876,273 were issued and outstanding as of January 31, 2011. All shares are initially issued in registered form. There are no restrictions on the transferability of our common shares imposed by our constating documents. Holders of our common shares are entitled to one vote for each common share held of record on all matters to be acted upon by our shareholders. Holders of common shares are entitled to receive such dividends as may be declared from time to time by our board of directors, in their discretion. In addition we are authorized to issue an unlimited number of preferred shares, with such rights, preferences and privileges as may be determined from time to time by our board of directors. There were no preferred shares outstanding at January 31, 2011.

Our common shares entitle their holders to: (i) vote at all meetings of our shareholders except meetings at which only holders of specified classes of shares are entitled to vote, having one vote per common share, (ii) receive dividends at the discretion of our board of directors; and (iii) receive our remaining property on liquidation, dissolution or winding up.

A.	OFFER AND LISTING DETAILS

Our common stock became eligible for trading on October 22, 2009 on the Over the Counter Bulletin Board ("OTCBB") under the symbol (“EGNKF”). Following the amalgamation on November 30, 2009 with our wholly owned subsidiary 1406768 Ontario, we changed our name to Eagleford Energy Inc. and commenced trading under the symbol (“EFRDF”). Prior to our common stock being listed on the OTCBB, our common stock had not publicly traded since 1990.

The following table set forth the reported high and low bid prices for shares of our common stock on the OTCBB in US dollars for the periods indicated.

	Period (1)	High		Low
Fiscal Year August 31, 2010	Year Ended August 31, 2010	$	1.30	$	0.05

Fiscal Year 2010 By Quarter	First Quarter ended 11/30/2009	$	0.00	$	0.00
	Second Quartered Ended 02/28/2010	$	0.05	$	0.05
	Third Quartered Ended 05/31/2010	$	0.00	$	0.00
	Fourth Quartered Ended 08/31/2010	$	1.30	$	0.73

Calendar Year 2010 by Month	August	$	1.30	$	0.90
	September	$	1.20	$	0.80
	October	$	1.81	$	1.01
	November	$	2.03	$	1.60
	December	$	2.00	$	1.75

Calendar Year 2011 by Month	January	$	1.89	$	1.02

Notes

(1)	Our stock commenced trading on the OTBCC on October 22, 2009.

(2)	The closing price on the OTCBB for our common stock on January 31, 2011 was $1.35.

There is currently only a limited public market for the common stock in the United States. There can be no assurance that a more active market will develop in the future.

B.	PLAN OF DISTRIBUTION

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

MARKETS

See Item 9.A.

D.	SELLING SHAREHOLDERS

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

DILUTION

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

F.	EXPENSES OF THE ISSUE

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 10 ADDITIONAL INFORMATION

A.	SHARE CAPITAL

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

B.	MEMORANDUM AND ARTICLES OF ASSOCIATION

Certificate of Incorporation

We were incorporated under the Business Corporations Act (Ontario) on September 22, 1978 under the name Bonanza Red Lake Explorations Inc. The corporation number as assigned by Ontario is 396323.

Articles of Amendment dated January 14, 1985

By Articles of Amendment dated January 14, 1985, our Articles were amended as follows:

1. The minimum number of directors of the Company shall be 3 and the maximum number of directors of the Company shall be 10.

2. (a) Delete the existing objects clauses and provide that there are no restrictions on the business we may carry on or on the powers that we may exercise;

(b) Delete the term "head office" where it appears in the articles and substitute therefor the term "registered office";

The following special provisions shall be applicable to the Company:

Subject to the provisions of the Business Corporations Act, as amended or re-enacted from time to time, the directors may, without authorization of the shareholders:

(i)

borrow money on the credit of the Company;

(ii)

issue, re-issue, sell or pledge debt obligations of the Company;

(iii)

give a guarantee on behalf of the Company to secure performance of an obligation of any person;

(iv)

mortgage, hypothecate, pledge or otherwise create a security interest in all or any property of the Corporation owned or subsequently acquired, to secure any obligation of the Company; and

(v)

by resolution, delegate any or all such powers to a director, a committee of directors or an officer of the Company.

3. (a) Provide that the Company is authorized to issue an unlimited number of shares;

(b) Provide that the Company is authorized to issue an unlimited number of preference shares.

Articles of Amendment dated August 16, 2000

By Articles of Amendment dated August 16, 2000 our articles were amended to consolidate our issued and outstanding common shares on the basis on one common share for every three issued and outstanding common shares in our capital, and change our name from Bonanza Red Lake Explorations Inc. to Eugenic Corp.

Our Articles of Amendment state that there are no restrictions on the business that may carry on, but do not contain a stated purpose or objective.

Articles of Amalgamation dated November 30, 2009

By Articles of Amalgamation dated November 30, 2009 we amalgamated with our wholly owned subsidiary Eagleford Energy Inc. (formerly: 1406768 Ontario Inc.) and changed the entity’s name to Eagleford Energy Inc.

Bylaws

No director of ours is permitted to vote on any resolution to approve a material contract or transaction in which such director has a material interest. (Bylaws, Article 43).

Neither our Articles nor our Bylaws limit the directors’ power, in the absence of an independent quorum, to vote compensation to themselves or any members of their body. The Bylaws provide that directors shall receive remuneration as the board of directors shall determine from time to time. (Bylaws, Article 44).

Under our Articles and Bylaws, our board of directors may, without the authorization of our shareholders, (i) borrow money upon our credit; (ii) issue, reissue, sell or pledge debt obligations of ours; whether secured or unsecured (iii) give a guarantee on behalf of us to secure performance of obligations; and (iv) charge, mortgage, hypothecate, pledge or otherwise create a security interest in all currently owned or subsequently acquired real or personal, movable or immovable, tangible or intangible, property of ours to secure obligations.

Annual general meetings of our shareholders are held on such day as is determined by resolution of the directors. (Bylaws, Article 6). Special meetings of our shareholders may be convened by order of our Chairman of the Board, our President if he/she is a director, a Vice-President who is a director, or the board of directors. (Bylaws, Article 6). Shareholders of record must be given notice of such special meeting not less than 10 days or more than 50 days before the date of the meeting. Notices of special meetings of shareholders must state the nature of the business to be transacted in detail and must include the text of any special resolution or bylaw to be submitted to the meeting. (Bylaws, Article 8). Our board of directors is permitted to fix a record date for any meeting of the shareholders that is between 21 and 50 days prior to such meeting. (Bylaws, Article 9). The only persons entitled to admission at a meeting of the shareholders are shareholders entitled to vote, our directors, our auditors, and others entitled by law, by invitation of the chairman of the meeting, or by consent of the meeting. (Bylaws, Article 13).

Neither our Articles nor our Bylaws discuss limitations on the rights to own securities or exercise voting rights thereon, and there is no provision of our Articles or Bylaws that would delay, defer or prevent a change in control of us, or that would operate only with respect to a merger, acquisition, or corporate restructuring involving us or any of its subsidiaries. Our Bylaws do not contain a provision indicating an ownership threshold above which shareholder ownership must be disclosed.

Other Provisions

Neither our Articles nor our Bylaws discuss the retirement or non-retirement of directors under an age limit requirement or the number of shares required for director qualification.

Neither our Articles nor our Bylaws require that a director hold a share in the capital of the Company as qualification for his/her office.

Neither our Articles nor our Bylaws contain sinking fund provisions, provisions allowing us to make further capital calls with respect to any shareholder of ours, or provisions which discriminate against any holders of securities as a result of such shareholder owning a substantial number of shares.

C.	MATERIAL CONTRACTS

During the two year period preceding the filing date of this Annual Report, we entered into no material contracts other than contracts entered into in the ordinary course except for the following:

On February 27, 2009, we purchased all of the issued and outstanding shares issued in the capital stock of 1354166 Alberta Ltd., a company incorporated on October 3, 2007 in the Province of Alberta Canada (the "Transaction"). In connection therewith, we issued to the shareholders of 1354166 an aggregate of 8,910,564 units (each a "Unit") at $0.05 per unit or an aggregate of $445,528 and following the closing repaid $118,000 of shareholder loans in 1354166 by cash payment. Each unit is comprised of one share of our common stock (each a "Share") and one purchase warrant (each a "Warrant"). Each Warrant is exercisable until February 27, 2014 to purchase one additional share of our common stock at a purchase price of $0.07 per share. The shareholders of 1354166 and 1354166 itself are arm's-length parties to us. 1354166 is a private company that has a 5.1975% working interest held in trust through a joint venture partner in a natural gas unit located in the Botha area of Alberta, Canada.

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

On November 5, 2010 we terminated the agreement with Garwood dated June 10, 2010 and as a result 36,430 warrants were cancelled out of the 333,333 warrants issued exercisable at $1.00 expiring December 10, 2011 and 18,215 warrants were cancelled out of the 166,667 warrants issued exercisable at $1.50 expiring June 10, 2012.

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

On August 31, 2010, we acquired 100% the issued and outstanding membership interests of Dyami Energy LLC, a Texas limited liability corporation for consideration of $4,218,812. (US$3,965,422) satisfied by (i) the issuance of 3,418,467 units of the Company. Each unit is comprised of one common share and one-half a purchase warrant. Each full warrant is exercisable into one additional common share at US$1.00 per share on or before August 31, 2014 (the “Units’) and (ii) the assumption of $1,021,344 (US$960,000) of Dyami Energy debt by way of a secured promissory note. The note bears interest at 6% per annum, is secured by the Leases and is payable on December 31, 2011 or upon the Company closing a financing or series of financings in excess of US$4,500,000.

D.	EXCHANGE CONTROLS

There are no governmental laws, decrees or regulations in Canada that restrict the export or import of capital, or affect the remittance of dividends, interest or other payments to a non-resident holder of our common stock, other than withholding tax requirements (See "Taxation" below).

Except as provided in the Investment Canada Act, there are no limitations imposed under the laws of Canada, the Province of Ontario, or by our constituent documents on the right of a non-resident to hold or vote our common stock.

The Investment Canada Act (the "ICA"), which became effective on June 30, 1985, regulates the acquisition by non-Canadians of control of a Canadian business enterprise. In effect, the ICA requires review by Investment Canada, the agency which administers the ICA, and approval by the Canadian government, in the case of an acquisition of control of a Canadian business by a non-Canadian where: (i) in the case of a direct acquisition (for example, through a share purchase or asset purchase), the assets of the business are CDN $5 million or more in value; or (ii) in the case of an indirect acquisition (for example, the acquisition of the foreign parent of the Canadian business) where the Canadian business has assets of CDN $5 million or more in value or if the Canadian business represents more than 50% of the assets of the original group and the Canadian business has assets of CDN $5 million or more in value. Review and approval are also required for the acquisition or establishment of a new business in areas concerning "Canada's cultural heritage or national identity" such as book publishing, film production and distribution, television and radio production and distribution of music, and the oil and natural gas industry, regardless of the size of the investment.

As applied to an investment in us, three methods of acquiring control of a Canadian business would be regulated by the ICA: (i) the acquisition of all or substantially all of the assets used in carrying on the Canadian business; (ii) the acquisition, directly or indirectly, of voting shares of a Canadian corporation carrying on the Canadian business; or (iii) the acquisition of voting shares of an entity which controls, directly or indirectly, another entity carrying on a Canadian business. An acquisition of a majority of the voting interests of an entity, including a corporation, is deemed to be an acquisition of control under the ICA. An acquisition of less than one-third of the voting shares of a corporation is deemed not to be an acquisition of control. An acquisition of less than a majority, but one-third or more, of the voting shares of a corporation is presumed to be an acquisition of control unless it can be established that on the acquisition the corporation is not, in fact, controlled by the acquirer through the ownership of voting shares. For partnerships, trusts, joint ventures or other unincorporated entities, an acquisition of less than a majority of the voting interests is deemed not to be an acquisition of control.

In 1988, the ICA was amended, pursuant to the Free Trade Agreement dated January 2, 1988 between Canada and the United States, to relax the restrictions of the ICA. As a result of these amendments, except where the Canadian business is in the cultural, oil and gas, uranium, financial services or transportation sectors, the threshold for direct acquisition of control by US investors and other foreign investors acquiring control of a Canadian business from US investors has been raised from CDN $5 million to CDN $150 million of gross assets, and indirect acquisitions are not reviewable.

In addition to the foregoing, the ICA requires that all other acquisitions of control of Canadian businesses by non-Canadians are subject to formal notification to the Canadian government. These provisions require a foreign investor to give notice in the required form, which notices are for information, as opposed to review, purposes.

E. TAXATION

Certain Canadian Federal Income Tax Consequences

The following discussion describes the principal Canadian federal income tax consequences applicable to a holder of our common shares which are traded on the OTCBB, who, at all material times, is a resident of the United States for purposes of the Canada-United States Income Tax Convention (the "Treaty") entitled to the full benefit of the Treaty and is not a resident, or deemed to be a resident, of Canada, deals at arm's length and is not affiliated with the Company, did not acquire our common shares by virtue of employment, is not a financial institution, specified financial institution, registered non-resident insurer, authorized foreign bank, partnership or a trust as defined in the Income Tax Act (Canada) (the "ITA"), holds our common shares as capital property and as beneficial owner, and does not use or hold, is not deemed to use or hold, his or her common shares in connection with carrying on a business in Canada and, had not, does not and will not have a fixed base or permanent establishment in Canada within the meaning of the Treaty (a "non-resident holder").

This description is based upon the current provisions of the ITA, the regulations thereunder (the "Regulations"), management's understanding of the current publicly announced administration and assessing policies of Canada Revenue Agency, and all specific proposals (the "Tax Proposals") to amend the ITA and Regulations announced by the Minister of Finance (Canada) prior to the date hereof. This description is not exhaustive of all possible Canadian federal income tax consequences and, except for the Tax Proposals, does not take into account or anticipate any changes in law, whether by legislative, governmental or judicial action, nor does it take into account any income tax laws or considerations of any province or territory of Canada or foreign tax considerations which may differ significantly from those discussed below.

The following discussion is for general information only and is not intended to be, nor should it be construed to be, legal or tax advice to any holder of common shares of the Company, and no opinion or representation with respect to the Canadian Federal Income Tax consequences to any such holder or prospective holder is made. Accordingly, holders and prospective holders of common shares are urged to consult with their own tax advisors about the federal, provincial and foreign tax consequences of purchasing, owning and disposing of common shares.

Dividends

Dividends paid on our common shares to a non-resident holder will be subject to a 25% withholding tax pursuant to the provision of the ITA. The Treaty provides that the normal 25% withholding tax rate is generally reduced to 15% on dividends paid on shares of a corporation resident in Canada (such as the Company) to beneficial owners who are residents of the United States. However, if the beneficial owner is a resident of the United States and is a corporation which owns at least 10% of the voting stock of the Company, the withholding tax rate on dividends is reduced to 5%.

Capital Gains

A non-resident of Canada is subject to tax under the ITA in respect of a capital gain realized upon the disposition of a share of a corporation if the shares are considered to be "taxable Canadian property" of the holder within the meaning of the ITA and no relief is afforded under an applicable tax treaty. For purposes of the ITA, a common share of the Company will be taxable Canadian property to a non-resident holder if more than 50% of the fair market value of the common share during the 60 month period immediately preceding the disposition of the common share, was derived directly or indirectly from real or immovable property situated in Canada, Canadian resource properties or any options or interests in such properties.

In the case of a non-resident holder to whom shares of our common stock represent taxable Canadian property and who is a resident in the United States and not a former resident of Canada, no Canadian taxes will be payable on a capital gain realized on such shares by reason of the Treaty unless the value of such shares is derived principally from real property situated in Canada within the meaning of the Treaty at the time of the disposition.

Certain United States Federal Income Tax Consequences

The following is a general discussion of certain possible United States Federal income tax consequences, under current law, generally applicable to a US Holder (as defined below) of our common shares. This discussion does not address all potentially relevant Federal income tax matters and does not address consequences peculiar to persons subject to special provisions of Federal income tax law, such as those described below as excluded from the definition of a US Holder. In addition, this discussion does not cover any state, local or foreign tax consequences (See “Certain Canadian Federal Income Tax Consequences” above).

The following discussion is based upon the sections of the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, published Internal Revenue Service (“IRS”) rulings, published administrative positions of the IRS and court decisions that are currently applicable, any or all of which could be materially and adversely changed, possibly on a retroactive basis, at any time. In addition, this discussion does not consider the potential effects, both adverse and beneficial, of recently proposed legislation which, if enacted, could be applied, possibly on a retroactive basis, at any time. The following discussion is for general information only and it is not intended to be, nor should it be construed to be, legal or tax advice to any holder or prospective holder of common shares, and no opinion or representation with respect to the United States Federal income tax consequences to any such holder or prospective holder is made. Accordingly, holders and prospective holders of common shares are urged to consult their own tax advisors about the Federal, state, local, and foreign tax consequences of purchasing, owning and disposing of common shares.

U.S. Holders

As used herein, a “U.S. Holder” means a holder of common shares who is a citizen or individual resident (as defined under United States tax laws) of the United States; a corporation created or organized in or under the laws of the United States or of any political subdivision thereof; an estate the income of which is taxable in the United States irrespective of source; or a trust if (a) a court within the United States is able to exercise primary supervision over the trust’s administration and one or more United States persons have the authority to control all of its substantial decisions or (b) the trust was in existence on August 20, 1996 and has properly elected to continue to be treated as a United States person. This summary does not address the United States tax consequences to, and U.S. Holder does not include, persons subject to specific provisions of federal income tax law, including but not limited to tax-exempt organizations, qualified retirement plans, individual retirement accounts and other tax-deferred accounts, financial institutions, insurance companies, real estate investment trusts, regulated investment companies, broker-dealers, non-resident alien individuals, persons or entities that have a “functional currency” other than the U.S. dollar, persons who hold common shares as part of a straddle, hedging or a conversion transaction, and persons who acquire their common shares as compensation for services. This discussion is limited to U.S. Holders who own common shares as capital assets and who hold the common shares directly (e.g., not through an intermediary entity such as a corporation, partnership, limited liability company, or trust). This discussion does not address the consequences to a person or entity of the ownership, exercise or disposition of any options, warrants or other rights to acquire common shares.

Distributions on Our Common Shares

Subject to the discussion below regarding passive foreign investment companies (“PFICs”), the gross amount of any distribution (including non-cash property) by us (including any Canadian taxes withheld therefrom) with respect to common shares generally should be included in the gross income of a U.S. Holder as foreign source dividend income to the extent such distribution is paid out of current or accumulated earnings and profits of ours, as determined under United States Federal income tax principles. Distributions received by non-corporate U.S. Holders may be subject to United States Federal income tax at lower rates than other types of ordinary income (generally 15%) in taxable years beginning on or before December 31, 2010 if certain conditions are met. These conditions include the Company not being classified as a PFIC, it being a “qualified foreign corporation,” the U.S. Holder’s satisfaction of a holding period requirement, and the U.S. Holder not treating the distribution as “investment income” for purposes of the investment interest deduction rules. To the extent that the amount of any distribution exceeds our current and accumulated earnings and profits for a taxable year, the distribution first will be treated as a tax-free return of capital to the extent of the U.S. Holder’s adjusted tax basis in our common shares and to the extent that such distribution exceeds the Holder’s adjusted tax basis in our common shares, will be taxed as capital gain. In the case of U.S. Holders that are corporations, such dividends generally will not be eligible for the dividends received deduction.

If a U.S. Holder receives a dividend in Canadian dollars, the amount of the dividend for United States federal income tax purposes will be the U.S. dollar value of the dividend (determined at the spot rate on the date of such payment) regardless of whether the payment is later converted into U.S. dollars. In such case, the U.S. Holder may recognize additional ordinary income or loss as a result of currency fluctuations between the date on which the dividend is paid and the date the dividend amount is converted into U.S. dollars.

Disposition of Common Shares

Subject to the discussion below regarding PFIC’s, gain or loss, if any, realized by a U.S. Holder on the sale or other disposition of our common shares (including, without limitation, a complete redemption of our common shares) generally will be subject to United States Federal income taxation as capital gain or loss in an amount equal to the difference between the U.S. Holder’s adjusted tax basis in our common shares and the amount realized on the disposition. Net capital gain (i.e., capital gain in excess of capital loss) recognized by a non-corporate U.S. Holder (including an individual) upon a sale or other disposition of our common shares that have been held for more than one year will generally be subject to a maximum United States federal income tax rate of 15% subject to the PFIC rules below. Deductions for capital losses are subject to certain limitations. If the U.S. Holder receives Canadian dollars on the sale or disposition, it will have a tax basis in such dollars equal to the U.S. dollar value. Generally, any gain or loss realized on a subsequent disposition of the Canadian dollars will be U.S. source ordinary income or loss.

U.S. “Anti-Deferral” Rules

Passive Foreign Investment Company (“PFIC”) Regime. If we, or a non-U.S. entity directly or indirectly owned by us (“Related Entity”), has 75% or more of its gross income as “passive” income, or if the average value during a taxable year of ours or the Related Entity’s “passive assets” (generally, assets that generate passive income) is 50% or more of the average value of all assets held by us or the Related Entity, then the United States PFIC rules may apply to U.S. Holders. If we or a Related Entity is classified as a PFIC, a U.S. Holder will be subject to increased tax liability in respect of gain recognized on the sale of his, her or its common shares or upon the receipt of certain distributions, unless such person makes a “qualified electing fund” election to be taxed currently on its pro rata portion of our income and gain, whether or not such income or gain is distributed in the form of dividends or otherwise, and we provide certain annual statements which include the information necessary to determine inclusions and assure compliance with the PFIC rules. As another alternative to the foregoing rules, a U.S. Holder may make a mark-to-market election to include in income each year as ordinary income an amount equal to the increase in value of its common shares for that year or to claim a deduction for any decrease in value (but only to the extent of previous mark-to-market gains). We or a related entity can give no assurance as to its status as a PFIC for the current or any future year. U.S. Holders should consult their own tax advisors with respect to the PFIC issue and its applicability to their particular tax situation.

Controlled Foreign Corporation Regime (“CFC”) . If a U.S. Holder (or person defined as a U.S. persons under Section 7701(aX301 of the Code) owns 10% or more of the total combined voting power of all classes of our stock (, a “U. S. Shareholder”) and U.S. Shareholders own more than 50% of the vote or value of our Company, we would be a “controlled foreign corporation”.. This classification would result in many complex consequences, including the required inclusion into income by such U. S. Shareholders of their pro rata shares of “Subpart F income” of our Company (as defined by the Code) and our earnings invested in “US property” (as defined by the Code). In addition, under Section 1248 of the Code, gain from the sale or exchange of our common shares by a US person who is or was a U. S. Shareholder at any time during the five year period before the sale or exchange may be treated as ordinary income to the extent of earnings and profits of ours attributable to the stock sold or exchanged. It is not clear the CFC regime would apply to the U.S. Holders of our common shares, and is outside the scope of this discussion.

Foreign Tax Credit

A U.S. Holder who pays (or has withheld from distributions) Canadian income tax with respect to us may be entitled to either a deduction or a tax credit for such foreign tax paid or withheld, at the option of the U.S. Holder. Generally, it will be more advantageous to claim a credit because a credit reduces United States federal income tax on a dollar-for-dollar basis, while a deduction merely reduces the taxpayer’s income subject to tax. This election is made on a year-by-year basis and generally applies to all foreign taxes paid by (or withheld from) the U.S. Holder during that year.

There are significant and complex limitations which apply to the credit, among which is the general limitation that the credit cannot exceed the proportionate share of the U.S. Holder’s United States income tax liability that the U.S. Holder’s foreign source income bears to its worldwide taxable income. This limitation is designed to prevent foreign tax credits from offsetting United States source income. In determining this limitation, the various items of income and deduction must be classified into foreign and domestic sources. Complex rules govern this classification process.

In addition, this limitation is calculated separately with respect to specific “baskets” of income such as passive income, high withholding tax interest, financial services income, shipping income, and certain other classifications of income. Foreign taxes assigned to a particular class of income generally cannot offset United States tax on income assigned to another class. Under the American Jobs Creation Act of 2004 (the “Act”), this basket limitation will be modified significantly after 2006.

Unused foreign tax credits can generally be carried back one year and carried forward ten years. U.S. Holders should consult their own tax advisors concerning the ability to utilize foreign tax credits, especially in light of the changes made by the Act.

Backup Withholding

Payment of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries generally are subject to information reporting requirement and to backup withholding unless the US Holder (i) is a corporation or other exempt recipient or (ii) in the case of backup withholding, provides a correct taxpayer identification number and certifies that no loss of exemption from backup withholding has occurred

The amount of any backup withholding from a payment to a US Holder will be allowed as a credit against the US Federal income tax liability of the US Holder and may entitle the US Holder to a refund, provided that the required information is furnished to the IRS.

F. DIVIDENDS AND PAYING AGENTS

Not Applicable. This Form 20-F is being filed as an Annual Report filed under the Exchange Act.

G. STATEMENT BY EXPERTS

Not Applicable. This Form 20-F is being filed as an Annual Report filed under the Exchange Act.

H. DOCUMENTS ON DISPLAY

The documents and exhibits referred to in this Annual Report are available for inspection at the registered and management office at 1 King Street West, Suite 1505, Toronto, Ontario M5H 1A1 during normal business hours.

I. SUBSIDIARY INFORMATION

Not Applicable. This Form 20-F is being filed as an Annual Report filed under the Exchange Act.

ITEM 11 QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

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

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

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

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

• focusing on a limited number of core properties.

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

Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility to commodity prices. These conditions worsened in 2008 and continued through 2009 and into 2010 , causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially. These factors have negatively impacted company valuations and may impact the performance of the global economy going forward. Although economic conditions improved towards the latter portion of 2009 and during 2010as 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.

(i)	Commodity Price Risk

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

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

Commodity Price Sensitivity:

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

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

(ii)	Foreign Exchange Risk

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

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

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

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

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

(iii)

Interest Rate Risk

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

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

ITEM 12 DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A. DEBT SECURITIES

Not applicable.

B. WARRANTS AND RIGHTS

Not applicable.

C. OTHER SECURITIES

Not Applicable.

D. AMERICAN DEPOSITORY SHARES

Not Applicable.

PART II

ITEM 13 DEFAULTS, DIVIDENDS ARREARAGES AND DELINQUENCIES

Not applicable.

ITEM 14

MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

Not applicable.

ITEM 15 CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Under the supervision and with the participation of our senior management, including our chief executive officer and chief financial officer, James Cassina, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this annual report (the “Evaluation Date”). Based on this evaluation, our chief executive officer and chief financial officer concluded as of the Evaluation Date that our disclosure controls and procedures were effective such that the information relating to us, required to be disclosed in our Securities and Exchange Commission (“SEC”) reports (i) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and (ii) is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles.

Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (ii) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on our financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Management assessed the effectiveness of our internal control over financial reporting as of August 31, 2010 based on the framework established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on that assessment, management concluded that, as of August 31, 2010, our internal control over financial reporting was effective based on the criteria established in Internal Control—Integrated Framework.

Limitations on Effectiveness of Controls and Procedures

Our management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer), does not expect that our disclosure controls and procedures or our internal controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Our control systems are designed to provide such reasonable assurance of achieving their objectives. Further, the design of a control system must reflect the fact that there are resource constraints and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our Company have been detected. These inherent limitations include, but are not limited to, the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the quarter ended August 31, 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 16 [RESERVED]

A. AUDIT COMMITTEE FINANCIAL EXPERT

Our Board of Directors has determined that Mr. Milton Klyman is an "audit committee financial expert", as defined in Item 16A of Form 20-F and is independent. Milton Klyman is the Chairman of the Audit Committee. He is a self-employed financial consultant and has been a Chartered Accountant since 1952. Milton Klyman is a Life Member of the Institute of Chartered Accountants of Ontario, a Life member of the Canadian Institute of Mining Metallurgy and Petroleum and a Fellow of the Institute of Chartered Secretaries and Administrators.

B. CODE OF ETHICS

Upon written request to us at our registered and management office attention: the President, we will provide by mail, to any person without charge a copy of our Code of Ethics.

C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

It is the policy of the Audit Committee that all audit and non-audit services are pre-approved prior to engagement. Before the initiation of each audit, the principal accountant submits a budget of the expected range of expenditures to complete their audit engagement (including Audit Fees and Tax Fees) to the Audit Committee for approval. In the event that the principal accountant exceeds these parameters, the individual auditor is expected to communicate to management the reasons for the variances, so that such variances can be ratified by the Audit Committee. As a result, 100% of expenditures within the scope of the noted budget are approved by the Audit Committee.

During fiscal 2010 and 2009 there were no hours performed by any person other than the primary accountant’s fulltime permanent employees.

Since the commencement of the Company's most recently completed financial year, no recommendations were made by the Audit Committee to nominate or compensate an external auditor.

External Auditor Service Fees (By Category)

The aggregate fees billed or accrued for professional fees rendered by Schwartz Levitsky Feldman LLP, Chartered Accountants for the years ended August 31, 2010 and August 31, 2009 are as follows:

Nature of Services	Fees Paid to Auditor in Year- ended August 31, 2010		Fees Paid to Auditor in Year- ended August 31, 2009
Audit Fees(1)	$	37,000	$	32,000
Audit-Related Fees(2)	$	3,870	$	31,976	(5)
Tax Fees(3)	$	5,000	NIL
All Other Fees(4)	Nil		Nil
TOTALS	$	45,870	$	63,976

Notes:

"Audit Fees" include fees necessary to perform the annual audit and any quarterly reviews of the Company's financial statements management discussion and analysis. This includes fees for the review of tax provisions and for accounting consultations on matters reflected in the financial statements. This also includes audit or other attest services required by legislation or regulation, such as comfort letters, consents, reviews of securities filings and statutory audits.

"Audit-Related Fees" include fees for assurance and related services that are reasonably related to the performance of the audit or review of the Company's financial statements and that are not included in "Audit Fees".

"Tax Fees" include fees for all professional services rendered by the Company's auditors for tax compliance, tax advice and tax planning.

"All Other Fees" include all fees for products and services provided by the Company's auditors not included in "Audit Fees", "Audit-Related Fees" and "Tax Fees".

Included in Audit-Related Fees are fees of $31,249 from the Company’s former auditor BDO Dunwoody LLP for review of the Company’s Registration Statement with the United States Securities and Exchange Commission on Form 20-F.

D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not Applicable.

E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

Not applicable.

F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not Applicable.

G. CORPORATE GOVERNANCE

Not applicable.

PART III

ITEM 17

FINANCIAL STATEMENTS

The following attached consolidated financial statements are included in this Annual Report on Form 20-F beginning on page F-1:

1. Consolidated Audited Financial Statements of Eagleford Energy Inc. (formerly: Eugenic Corp.) for the years ended August 31, 2010, 2009 and 2008, comprised of the following:

(a)

Auditor’s Report of Schwartz Levitsky Feldman LLP, Chartered Accountants for the years ended August 31, 2010, 2009 and 2008;

(b)

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

(c)

Consolidated Statements of Loss, Comprehensive Loss and Deficit for the years ended August 31, 2010, 2009 and 2008;

(d)

Consolidated Statements of Shareholders’ Equity for the years ended August 31, 2010, 2009 and 2008

(e)

Consolidated Statements of Cash Flows for the years ended August 31, 2010, 2009 and 2008;

(f)

Notes to Consolidated Financial Statements.

ITEM 18

FINANCIAL STATEMENTS

We have elected to provide financial statements pursuant to Item 17.

ITEM 19

EXHIBITS

The following exhibits are included in the Annual Report on Form 20-F:

1.1*	Certificate of Incorporation of Bonanza Red Lake Explorations Inc. (presently known as Eagleford Energy Inc.) dated September 22, 1978

1.2*	Articles of Amendment dated January 14, 1985

1.3*	Articles of Amendment dated August 16, 2000

1.4*	Bylaw No 1 of Bonanza Red Lake Explorations Inc. (presently known as Eagleford Energy Inc.)

1.5*	Special By-Law No 1 – Respecting the borrowing of money and the issue of securities of Bonanza Red Lake Explorations Inc. (presently known as Eagleford Energy Inc.)

1.6***

Articles of Amalgamation dated November 30, 2009

4.1*	2000 Stock Option Plan

4.2*	Code of Business Conduct and Ethics

4.3*	Audit Committee Charter

4.4*	Petroleum and Natural Gas Committee Charter

4.5*	Compensation Committee Charter

4.6*	Purchase and Sale Agreement dated February 5, 2008 among Eugenic Corp., 1354166 Alberta Ltd., and the Vendors of 1354166 Alberta Ltd.

4.7 **

Amended Audit Committee Charter

4.8****

Amended Stock Option Plan

4.9	Asset Purchase Agreement between Eagleford Energy Inc., and Source Re-Work Program Inc., dated May 12, 2010

4.10	Addendum dated June 10, 2010 to the Asset Purchase Agreement between Eagleford Energy Inc., and Source Re-Work Program Inc., dated May 12, 2010

4.11	Addendum 2 dated June 30, 2010 to the Asset Purchase Agreement between Eagleford Energy Inc., and Source Re-Work Program Inc., dated May 12, 2010

4.12*****

Acquisition Agreement among Eagleford Energy Inc., Dyami Energy LLC and the Members of Dyami Energy LLC dated August 10, 2010

4.13	Financial Advisory Services Agreement between Eagleford Energy Inc. and GarWood Securities, LLC dated June 10, 2010

8.1	Subsidiaries of Eagleford Energy Inc.

12.1/12.2

Section 302 Certification of Chief Executive and Financial Officer

13.1/13.2

Section 906 Certification of Chief Executive and Financial Officer

Previously filed by Registrant on April 29, 2009 as part of Registration Statement on Form 20 F (SEC File No. 0 53646)

Previously Filed by Registrant as part of Amendment #2 to Registration Statement on Form 20F/A on July 14, 2009 (SEC File No. 0-53646)

***

Previously Filed by Registrant on Form 6-K on December 1, 2009

****

Previously filed by Registrant on Form 20F/A on March 12, 2010

*****

Previously filed by Registrant on Form 6-K on September 16, 2010

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.

EAGLEFORD ENERGY INC.

By:	/s/ James Cassina
	Name: James Cassina
	Title: President and Chief Executive Officer

Date: February 11, 2011

INDEX TO FINANCIAL STATEMENTS

1. Audited Consolidated Financial Statements of Eagleford Energy Inc. for the years ended August 31, 2010, 2009 and 2008, comprised of the following:

	(a)	Auditor’s Report of Schwartz Levitsky Feldman LLP, Chartered Accountants for the years ended August 31, 2010, 2009 and 2008;	F-2 –F-3

	(b)	Consolidated Balance Sheets as at August 31, 2010 and 2009;	F-4

	(c)	Consolidated Statements of Loss, Comprehensive Loss and Deficit for the years ended August 31, 2010, 2009 and 2008;	F-5

	(d)	Consolidated Statements of Shareholders’ Equity for the years ended August 31, 2010, 2009 and 2008;	F-6

	(e)	Consolidated Statements of Cash Flows for the years ended August 31, 2010, 2009 and 2008;	F-7

	(f)	Notes to Audited Consolidated Financial Statements.	F-8 – F-39

F-1

AUDITORS’ REPORT

To the Shareholders of

Eagleford Energy Inc.

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

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

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

/s/ “SCHWARTZ LEVITSKY FELDMAN LLP”

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

F-2

COMMENTS BY AUDITORS FOR U.S. READERS

ON CANADA - - U.S. REPORTING DIFFERENCE

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

/s/ “SCHWARTZ LEVITSKY FELDMAN LLP”

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

F-3

Consolidated Balance Sheets

(Expressed in Canadian Dollars)

August 31	2010			2009

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

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

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

On behalf of the Board:

(signed) “James Cassina” Director

(signed) “Milton Klyman” Director

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

F-4

Consolidated Statements of Loss, Comprehensive Loss and Deficit

(Expressed in Canadian Dollars)

For the years ended August 31	2010			2009			2008

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

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

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

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

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

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

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

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

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

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

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

F-5

Consolidated Statements of Shareholders’ Equity

(Expressed in Canadian Dollars)

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

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

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

F-6

Consolidated Statements of Cash Flows

(Expressed in Canadian Dollars)

For the years ended August 31	2010			2009			2008

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

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

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

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

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

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

Non-cash transactions (Note 20)

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

F-7

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

1. Nature of Business

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

Going Concern

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

2. Significant Accounting Policies

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

F-8

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

2. Significant Accounting Policies (cont’d)

Principles of Consolidation

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

Oil and Gas Interests

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

Depletion and Depreciation

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

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

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

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

Impairment Test

F-9

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

2.	Significant Accounting Policies (cont’d)

Revenue Recognition

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

Royalties

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

Transportation

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

Environmental and Site Restoration Costs

Foreign Currencies

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

Marketable Securities

F-10

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

2.	Significant Accounting Policies (cont’d)

Financial Instruments

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

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

Cash and cash equivalents

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

Accounting Estimates

Income Taxes

F-11

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

2.	Significant Accounting Policies (cont’d)

Non-Monetary Transactions

Stock Based Compensation

Loss Per Share

Warrants

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

3. Change in Accounting Policy and Future Accounting Changes

(a) EIC Credit Risk

F-12

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

(b) Financial Instruments – Disclosures

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

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

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

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

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

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

(d) General Standard of Financial Statement Presentation

F-13

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

(e) Future Accounting Changes

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

F-14

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

(e) Future Accounting Changes (cont’d)

4.	Business Combinations

2010 Acquisition

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

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

F-15

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

4.	Business Combinations (cont’d)

2010 Acquisition (cont’d)

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

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

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

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

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

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

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

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

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

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

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

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

F-16

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

4.	Business Combinations (cont’d)

2010 Acquisition (cont’d)

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

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

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

2009 Acquisition

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

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

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

F-17

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

5.	Segmented Information

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

Geographic information:

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

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

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

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

6.	Marketable Securities

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

7.	Oil and Gas Interests

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

F-18

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

7.	Oil and Gas Interests (cont’d)

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

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

Alberta, Canada

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

Mathews Lease, Zavala County, Texas, USA

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

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

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

The royalties payable under the Matthews Lease are 25%.

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

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

F-19

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

7.	Oil and Gas Interests (cont’d)

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

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

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

Murphy Lease, Zavala County, Texas, USA

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

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

F-20

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

7.	Oil and Gas Interests (cont’d)

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

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

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

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

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

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

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

F-21

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

8. Asset Retirement Obligation

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

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

9. Share Capital and Contributed Surplus

Authorized:

Unlimited number of common shares

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

Issued:

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

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

F-22

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

F-23

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

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

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

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

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

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

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

F-24

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

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

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

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

Stock Option Plan

Contributed Surplus

Contributed surplus transactions for the respective years are as follows:

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

F-25

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

10. Related Party Transactions and Balances

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

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

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

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

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

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

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

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

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

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

F-26

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

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

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

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

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

11. Loan Payable

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

12. Secured Notes Payable

Current

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

F-27

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

12. Secured Notes Payable (cont’d)

Long Term

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

13. Seasonality and Trend Information

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

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

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

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

F-28

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

14. Financial Instruments and Risk Factors

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

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

	2010				2009
	Amount		Fair Value		Amount		Fair Value
Financial assets

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

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

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

Credit Risk

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

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

F-29

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

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

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

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

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

Liquidity Risk

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

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

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

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

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

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

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

F-30

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

(1) Translated at current exchange rate.

Market Risk

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

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

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

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

• focusing on a limited number of core properties.

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

F-31

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

(i) Commodity Price Risk

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

Commodity Price Sensitivity

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

(ii) Foreign Exchange Risk

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

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

F-32

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

(ii) Foreign Exchange Risk (cont’d)

(iii) Interest Rate Risk

15. Capital Management

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

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

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

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

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

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

F-33

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

16. Income Taxes

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

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

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

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

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

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

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

F-34

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

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

Oil and Gas Interests

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

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

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

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

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

Adoption of New Accounting Policies

Financial Accounting Standards Board’s Codification of US GAAP

F-35

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

Business combinations

Non-controlling interests

Derivative Instruments and Hedging Activities

Subsequent events

F-36

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

The Fair Value Measurement of Liabilities

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

Equity method investees

Future U.S. Accounting Policy Changes

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

F-37

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

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

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

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

18. Contractual Obligations and Commitments

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

19. Subsequent Events

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

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

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

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

F-38

Notes to Consolidated Financial Statements

(Expressed in Canadian Dollars)

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

19. Subsequent Events (cont’d)

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

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

20. Non-Cash Transactions

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

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

21. Comparative Figures

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

F-39

INDEX TO EXHIBITS

1.1*	Certificate of Incorporation of Bonanza Red Lake Explorations Inc. (presently known as Eagleford Energy Inc.) dated September 22, 1978

1.2*	Articles of Amendment dated January 14, 1985

1.3*	Articles of Amendment dated August 16, 2000

1.4*	Bylaw No 1 of Bonanza Red Lake Explorations Inc. (presently known as Eagleford Energy Inc.)

1.5*	Special By-Law No 1 – Respecting the borrowing of money and the issue of securities of Bonanza Red Lake Explorations Inc. (presently known as Eagleford Energy Inc.)

1.6***

Articles of Amalgamation dated November 30, 2009

4.1*	2000 Stock Option Plan

4.2*	Code of Business Conduct and Ethics

4.3*	Audit Committee Charter

4.4*	Petroleum and Natural Gas Committee Charter

4.5*	Compensation Committee Charter

4.6*	Purchase and Sale Agreement dated February 5, 2008 among Eugenic Corp., 1354166 Alberta Ltd., and the Vendors of 1354166 Alberta Ltd.

4.7**

Amended Audit Committee Charter

4.8****

Amended Stock Option Plan

4.9	Asset Purchase Agreement between Eagleford Energy Inc., and Source Re-Work Program Inc., dated May 12, 2010

4.10	Addendum dated June 10, 2010 to the Asset Purchase Agreement between Eagleford Energy Inc. and Source Re-Work Program Inc., dated May 12, 2010

4.11	Addendum 2 dated June 30, 2010 to the Asset Purchase Agreement between Eagleford Energy Inc. and Source Re-Work Program Inc., dated May 12, 2010

4.12*****

Acquisition Agreement among Eagleford Energy Inc., Dyami Energy LLC and the Members of Dyami Energy LLC dated August 10, 2010

4.13	Financial Advisory Services Agreement between Eagleford Energy Inc. and GarWood Securities, LLC dated June 10, 2010

8.1	Subsidiaries of Eagleford Energy Inc.

12.1/12.2

Section 302 Certification of Chief Executive and Financial Officer

13.1/13.2

Section 906 Certification of Chief Executive and Financial Officer


*	Previously filed on April 29, 2009 by Registrant as part of Registration Statement on Form 20-F (SEC File No. 0-53646)

**	Previously Filed by Registrant as part of Amendment #2 to Registration Statement on Form 20F/A on July 14, 2009 (SEC File No. 0-53646)

***	Previously Filed by Registrant on Form 6 K on December 1, 2009

****	Previously filed by Registrant on Form 20F/A on March 12, 2010

*****

Previously filed by Registrant on Form 6-K on September 16, 2010

Form: 20-F

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