Cougar Oil & Gas Canada (COUGF) 20-F/A 2010 FY Annual report (foreign) (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F/A1

(Mark One)
[   ]	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
[   ]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
[X]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from July 31, 2010 to December 31, 2010
[   ]	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: _______________

333-149325

Commission File Number

COUGAR OIL AND GAS CANADA INC.

(Exact name of registrant as specified in its charter)

N/A

(Translation of Registrant’s name into English)

Alberta, Canada

(Jurisdiction of incorporation or organization)

833 4th Avenue S.W., Suite 1120; Calgary, Alberta T2P 3T5 Canada

(Address of principal executive offices)

William S. Tighe

833 4th Avenue S.W., Suite 1120; Calgary, Alberta T2P 3T5 Canada

Tel: (403) 262-8044 E-mail: wmstighe@cougarenergyinc.com

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class	Name of each exchange on which registered
N/A	N/A

Securities registered pursuant to Section 12(g) of the Exchange Act:

Title of class

Common Shares

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Exchange Act:

Title of class

N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the close of the period covered by the annual report.

66,485,661 shares of common stock issued and outstanding as of March 21, 2011

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 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 Website, 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 the definitions of “large accelerated filer,” “accelerated filer” in Rule 12b-2 of the Exchange Act.

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	[X]	Other	[   ]
International Financial Reporting Standards as issued by the International Accounting Standards Board			[   ]

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

Item 17 [ ] 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]

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST 5 YEARS:

Indicate by check mark whether the issuer has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes [ ] No [ ]

ITEM 18. FINANCIAL STATEMENTS

Our audited financial statements for the five month periods ended December 31, 2010 and December 31, 2009, year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009 are provided herein starting on Page F-1.

COUGAR OIL AND GAS CANADA, INC

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets as of December 31, 2010 and 2009; and as of July 31, 2010 and 2009	F-2
Consolidated Statements of Operations for the five month periods ended December 31, 2010 and 2009; for the year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009	F-3
Consolidated Statement of Stockholders’ Equity from November 21, 2008 (date of inception) through December 31, 2010	F-4
Consolidated Statements of Cash Flows for the five month periods ended December 31, 2010 and 2009; for the year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009	F-5
Notes to Consolidated Financial Statements	F-6 - 28

Report of Independent Registered Public Accounting Firm

To the Board of Directors

Cougar Oil and Gas Canada, Inc.

Alberta, Canada

We have audited the accompanying consolidated balance sheets of Cougar Oil and Gas Canada, Inc. and subsidiaries (the “Company”) as of December 31, 2010, 2009 and July 31, 2010 and 2009 and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash flows for the five month periods ended December 31, 2010 and 2009 and year ended July 31, 2010 and November 21, 2008 (date of inception) through July 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based upon our audits.

We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cougar Oil and Gas Canada, Inc. at December 31, 2010, 2009 and July 31, 2010 and 2009 and the results of its operations and its cash flows for the five month periods ended December 31, 2010 and 2009 and year ended July 31, 2010 and November 21, 2008 (date of inception) through July 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1, the Company has suffered recurring losses since its inception and has a working capital deficiency. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ RBSM, LLP

New York, New York

March 30, 2011

F-1

COUGAR OIL AND GAS CANADA, INC.

CONSOLIDATED BALANCE SHEETS

(REPORTED IN CANADIAN DOLLARS)

	December 31,						July 31,
	2010			2009			2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	1,678		$	-		$	1,804		$	-
Accounts receivable		467,359			322,872			432,205			15,705
Accounts receivable, other		51,165			12,960			-			-
Prepaid expenses and deposits (note 2)		59,038			70,148			83,397			-
Total current assets		579,240			405,980			517,406			15,705
Oil and natural gas properties, full cost accounting (note 3)
Proved properties		9,212,427			7,184,463			8,587,053			-
Less: accumulated depreciation, depletion and amortization		(3,466,639	)		(2,276,463	)		(3,087,053	)		-
Net		5,745,788			4,908,000			5,500,000			-
Undeveloped properties excluded from amortization (note 3)		3,936,797			3,920,062			3,934,051			4,064,730
Furniture and fixtures, net		5,363			-			5,663			-
		9,687,948			8,828,062			9,439,714			4,064,730
Total assets	$	10,267,188		$	9,234,042		$	9,957,120		$	4,080,435
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	1,889,266		$	1,218,656		$	1,985,461		$	937,389
Operating line of credit (note 5)		2,025,000			-			1,425,000			-

Current maturities of long term debt (note 6)		818,906			566,311			672,124			-
Short term notes payable (note 6)		15,623			75,000			65,833			-
Related party obligations (note 10)		458,008			1,104,252			674,519			180,668
Total current liabilities		5,206,803			2,964,219			4,822,937			1,118,057
Long term debt (note 6)		2,707,186			3,526,092			3,051,978			-
Asset retirement obligations (note 7)		1,332,747			1,221,793			1,311,206			107,667
Total liabilities		9,246,736			7,712,104			9,186,121			1,225,724
Commitments and contingencies (note 11)
Stockholders' equity (notes 8 and 9)
Common stock, no par value; unlimited authorized; 64,047,111 and 44,997,979 shares issued and outstanding as of December 31, 2010 and 2009, respectively; 61,853,353 and 40,665,860 issued and outstanding as of July 31, 2010 and 2009, respectively		5,207,027			4,219,164			4,134,039			3,295,195
Additional paid in capital		622,174			128,210			320,863			69,279
Deficit		(4,810,977	)		(2,825,399	)		(3,683,623	)		(509,729	)
Other comprehensive income (loss)		2,228			(37	)		(280	)		(34	)
Total stockholders' equity		1,020,452			1,521,938			770,999			2,854,711
Total liabilities and stockholders' equity	$	10,267,188		$	9,234,042		$	9,957,120		$	4,080,435

The accompanying notes are an integral part of these financial statements

F-2

COUGAR OIL AND GAS CANADA, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(REPORTED IN CANADIAN DOLLARS)

										From November 21, 2008
	Five Months Ended			Five Months Ended			Year Ended			(date of inception)
	December 31,			December 31,			July 31,			Through July 31,
	2010			2009			2010			2009
REVENUE:
Oil sales, net of royalties	$	1,178,303		$	629,993		$	2,657,720		$	-
EXPENSES:
Operating		689,282			422,587			1,327,376			-
General and administrative		1,039,009			623,563			1,618,635			505,216
Impairment of oil and gas properties		-			2,030,267			2,132,179			-
Depletion and amortization		418,212			269,866			1,032,485			4,513
Total expenses		2,146,503			3,346,283			6,110,675			509,729
Net loss from operations		(968,200	)		(2,716,290	)		(3,452,955	)		(509,729	)
OTHER INCOME (EXPENSE):
Gain on settlement of operating agreement		-			516,000			516,000			.
Gain on asset retirement		933			-			77,419			-

Interest income		240			69			-			-
Interest expense		(160,326	)		(115,449	)		(314,358	)		-
Net loss before income taxes		(1,127,354	)		(2,315,670	)		(3,173,894	)		(509,729	)
Provision for income taxes (benefit) (note 13)		-			-			-			-
NET LOSS	$	(1,127,354	)	$	(2,315,670	)	$	(3,173,894	)	$	(509,729	)
Loss per common stock, basic and fully diluted	$	(0.02	)	$	(0.05	)	$	(0.06	)	$	(0.02	)
Weighted average number of outstanding shares, basic and fully diluted		62,083,745			43,071,212			52,044,457			22,262,318
Comprehensive loss:
Net loss	$	(1,127,354	)	$	(2,315,670	)	$	(3,173,894	)	$	(509,729	)
Foreign currency translation gain (loss)		2,508			(3	)		(246	)		(34	)
Comprehensive loss	$	(1,124,846	)	$	(2,315,673	)	$	(3,174,140	)	$	(509,763	)

The accompanying notes are an integral part of these financial statements

F-3

COUGAR OIL AND GAS CANADA, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FROM NOVEMBER 21, 2008 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2010
(REPORTED IN CANADIAN DOLLARS)
					Additional					Other
	Common stock				Paid in					Comprehensive
	Shares		Amount		Capital		Deficit			Income (loss)			Total
Balance, November 21, 2008 (date of inception)		45	$	-	$	-	$	-		$	-		$	-
Common stock issued in exchange for undeveloped properties from related party		38,076,933		2,821,287		-		-			-			2,821,287
Sale of common stock		2,588,882		473,908		-		-			-			473,908
Fair value of issued options		-		-		69,279		-			-			69,279
Foreign currency transaction loss		-		-		-		-			(34	)		(34	)
Net Loss		-		-		-		(509,729	)		-			(509,729	)
Balance, July 31, 2009		40,665,860		3,295,195		69,279		(509,729	)		(34	)		2,854,711
Foreign currency translation loss		-		-		-		-			(3	)		(3	)
Fair value of issued options						58,931								58,931
Sale of common stock		3,634,619		722,469		-		-			-			722,469
Common stock issued in exchange for oil & gas property		697,500		201,500										201,500
Net Loss		-		-		-		(2,315,670	)		-			(2,315,670	)
Balance, December 31, 2009		44,997,979		4,219,164		128,210		(2,825,399	)		(37	)		1,521,938

Common stock issued to acquire related party note receivable	648,444		1,357,714			-		-			-			1,357,714
Effect of merger with Cougar Oil and Gas Canada, Inc. (formerly Ore-More Resources, Inc.)	16,200,000		(1,446,838	)		-		-			-			(1,446,838	)
Common stock issued in exchange for exercise of warrants	6,930		3,999			-		-			-			3,999
Fair value of issued options	-		-			192,653		-			-			192,653
Foreign currency translation loss	-		-			-		-			(243	)		(243	)
Net loss	-		-			-		(858,224	)		-			(858,224	)
Balance, July 31, 2010	61,853,353		4,134,039			320,863		(3,683,623	)		(280	)		770,999
Common stock issued in exchange for exercise of warrants	2,007,918		590,220			-		-			-			590,220
Common stock issued for debt repayment to related party	185,840		482,768			-		-			-			482,768
Fair value of issued options						301,311								301,311
Foreign currency translation gain	-		-			-		-			2,508			2,508
Net loss	-		-			-		(1,127,354	)		-			(1,127,354	)
Balance, December 31, 2010	64,047,111	$	5,207,027		$	622,174	$	(4,810,977	)	$	2,228		$	1,020,452

The accompanying notes are an integral part of these financial statements

F-4

COUGAR OIL AND GAS CANADA, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(REPORTED IN CANADIAN DOLLARS)

										From November 21, 2008
	Five Months Ended			Five Months Ended			Year Ended			(date of inception)
	December 31,			December 31,			July 31,			Through July 31,
	2010			2009			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,127,354	)	$	(2,315,670	)	$	(3,173,894	)	$	(509,729	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, accretion and depletion		418,212			269,866			1,032,485			-
Impairment loss on oil and gas properties		-			2,030,267			2,132,179			-
Gain on settlement of operating agreement		-			(516,000	)		(516,000	)		-
Gain on asset retirement		(933	)		-			(77,419	)		-
Fair value of vested options for services rendered		301,311			58,931			251,584			69,279
Changes in operating assets and liabilities:
Accounts receivable		(86,319	)		(307,167	)		(416,328	)		(3,368	)
Prepaid and other		24,359			(70,148	)		(83,397	)		-

Accounts payable and accrued expenses		(96,196	)		281,267			1,047,891			937,390
Net cash used in operating activities		(566,920	)		(568,654	)		197,101			493,572
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of undeveloped properties		(642,853	)		(993,561	)		(2,887,649	)		(1,135,776	)
Purchase of equipment		(1,118	)					(6,858	)		-
Cash acquired from acquisition of Ore-More Resources, Inc.		-			-			7,708			-
Net cash used in investing activities		(643,971	)		(993,561	)		(2,886,799	)		(1,135,776	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock		-			722,469			722,469			473,908
Proceeds from exercise of warrants		590,220			-			3,999			-
Proceeds from operating line of credit		600,000			-			1,425,000			-
Proceeds from (repayments of) short term borrowing		(50,210	)		75,000			540,000			-
Proceeds from related party loans		266,257			910,625			-			168,330
Net repayments of long-term debt		(198,010	)		(145,876	)		-			-
Net cash provided by financing activities		1,208,257			1,562,218			2,691,468			642,238
Effect on foreign currency rate change on cash		2,508			(3	)		34			(34	)
Net increase in cash and cash equivalents		(126	)		-			1,804			-
Cash and cash equivalents-beginning of period		1,804			-			-			-
Cash and cash equivalents-end of period	$	1,678		$	-		$	1,804		$	-
Supplemental disclosures of cash flow information:
Taxes paid
Interest paid	$	160,012		$	115,148		$	303,807
Non cash financing activities:
Common stock issued in exchange for undeveloped property	$	-		$	201,500		$	201,500		$	2,821,287
Debt issued in exchange for related party debt	$	482,768		$	-		$	-		$	-
Property received in settlement of operating agreement	$	-		$	516,000		$	516,000		$	-
Gain on settlement of debt	$	-		$	-		$	77,419		$	-
Common stock issued to acquire related party receivable	$	-		$	-		$	1,357,714		$	-
Effect of Merger with Cougar Oil and Gas Canada, Inc. (formerly Ore-More)	$	-		$	-		$	(1,446,838	)	$	-
Transfer of notes payable to related party	$	-		$	-		$	490,000		$	-

The accompanying notes are an integral part of these financial statements

F-5

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements are as follows:

Basis and business presentation

Cougar Oil and Gas Canada, Inc. (“Cougar”, “we”, “us”, “our”), formerly Ore-More Resources, Inc., was incorporated under the laws of the Province of Alberta, Canada on June 20, 2007. Our principal activity is in the exploration, development, production and sale of oil and natural gas.

Our main operations are currently in the Alberta and British Columbia provinces of Canada. Our focus has developed into the specific projects of:

· Cougar Trout Properties, Alberta (Core Area) – farm-in and acquired lands in the Trout, Kidney and Equisetum fields;

· CRE Energy Project, Alberta - mineral leases, exploration and development opportunities within the CRE Energy Agreement and several current and proposed Northern Alberta Treaty Land Entitlement Claims;

· Lucy, British Columbia - Horn River Basin Muskwa shale gas project;

· Other Alberta properties.

The consolidated financial statements include the accounts of Cougar and Cougar Energy, Inc., a wholly-owned subsidiary, are thereafter collectively referred to as “we”, “us”, “our” or, the “Company”. All significant intercompany balances and transactions have been eliminated in consolidation.

Reverse Acquisition

In January 2010, the Company entered into a stock purchase Agreement (the “Agreement”) with Cougar Energy, Inc. (which we refer to as CEI) and Cougar then shareholders whereby CEI agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:

a) On January 20, 2010, the Company finalized stock purchase agreements effective January 18, 2010 by and between the Company and Zentrum Energie Trust AG, CAT Brokerage AG, LB (Swiss) Private Bank for its client, Mauschen Finanz Inc. and Rahn and Bodmer (collectively the “Vendors”), whereby the Company purchased from the Vendors shares and warrants of the common stock of CEI held by the Vendors. The Vendors tendered a total of 884,616 common shares of CEI and 884,616 warrants granting the right to the holder, which shall be the Company pursuant to the transfer, to purchase an additional 884,616 common shares of CEI on or before December 4, 2011. As consideration for the common shares and warrants of CEI tendered by the Vendors, the Company issued a total of 3,980,775 shares of its common stock to the Vendors and an equal number of warrants, entitling the holders to exercise a total of 5,348,085 warrants. The warrants have the following exercise prices and expiry dates:

· 1,246,155 warrants to purchase common shares exercisable at $0.288 per common share and expiring on March 4, 2011.

· 2,025,000 warrants to purchase common shares exercisable at $0.288 per common share and expiring on October 31, 2011.

· 2,076,930 warrants to purchase common shares exercisable at $0.577 per common share and expiring on December 4, 2011.

F-6

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

The shares and warrants were exchanged during the week ended January 30, 2010.

b) On January 25, 2010, the Company finalized a share purchase agreement between the Company and Kodiak Energy Inc. (“Kodiak”) whereby the Company purchased from Kodiak a total of 8,461,549 shares of the common

shares of CEI held by Kodiak. The share purchase agreement called for the Company to issue a total of 1.5 shares of common stock for each share of CEI tendered by Kodiak, resulting in the Company issuing a total of 12,692,324 (38,076,933 shares post split) shares of common stock. As further consideration for the acquisition of the CEI common shares, the Company forgave all current indebtedness owed to the Company by Kodiak and guaranteed by CEI, which was in the amount of $1,296,889 (Cdn $1,357,714). An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Company were cancelled.

Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of the Company. Subsequent to the completion of the reverse acquisition, the Company amended its article of incorporation and changed its name to Cougar Oil and Gas Canada, Inc.

The acquisition is accounted for as a “reverse acquisition”, since the stockholders of CEI owned a majority of the Company’s common stock immediately following the transaction and their management has assumed operational, management and governance control. The reverse acquisition transaction is recorded as a recapitalization of CEI pursuant to which CEI is treated as the surviving and continuing entity although the Company is the legal acquirer rather than a business combination. The Company did not recognize goodwill or any intangible assets in connection with this transaction. Accordingly, the Company’s historical consolidated financial statements are those of CEI from its date of inception on November 21, 2008.

Prior to the acquisition of CEI, the Company had operating assets and activities within the oil and gas industry, and therefore the acquisition of CEI is not characterized as a shell transaction under SEC rules and regulations.

Functional currency

The reporting and functional currency of the Companies is the Canadian dollar. When a transaction is executed in a foreign currency, it is re-measured into Canadian dollars based on appropriate rates of exchange in effect at the time of the transaction. The resulting foreign currency transactions gains (losses) are included in general and administrative expenses in the accompanying consolidated statements of operations.

At each balance sheet date, recorded balances that are denominated in a currency other than the functional currency of the Companies are adjusted to reflect the current exchange rate. The cumulative translation adjustments are included in accumulated other comprehensive income (loss) in the equity section of the consolidated balance sheet.

F-7

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Estimates

The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.

Reclassification

Certain reclassifications have been made to prior periods’ data to conform to the current year’s presentation. These reclassifications had no effect on reported income or losses.

Revenue Recognition

The Company uses the sales method of accounting for the recognition of natural gas and oil revenues. The Company is the operator on all of its properties. The Company has an agreement with the marketers of our product to sell, on its behalf, production from the properties for which it has working interest ownership. Since there is a ready market for natural gas, crude oil and natural gas liquids (“NGLs”), production is sold at various locations at which time title and risk of loss pass to the marketer.

The Company records its share of revenues based on sales volumes and contracted sales prices. The sales price for natural gas, natural gas liquids and crude oil are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. Historically, these adjustments have been insignificant. In addition, natural gas and crude oil volumes sold are not significantly different from the Company’s share of production.

The Company receives its share of revenue after all calculated crown royalties are paid on natural gas, crude oil and NGLs in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements. Private royalties are accrued and paid upon receipt of payment.

Cash and Cash Equivalents, and Concentrations of Credit Risk

Cash and cash equivalents represent cash in banks. The Company considers any highly liquid debt instruments purchased with a maturity date of three months or less to be cash equivalents. The Company’s accounts receivable are concentrated among entities engaged in the energy industry, within Canada. Financial instruments and related items, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, cash equivalents and receivables. The Company places its cash and temporary cash investments with credit quality institutions. At times, such investments may be in excess of the Canada Deposit Insurance Corporation insurance limit.

F-8

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Accounting for Bad Debts and Allowances

Bad debts and allowances are provided based on historical experience and management's evaluation of outstanding accounts receivable. Management periodically evaluates past due or delinquency of accounts receivable in evaluating its allowance for doubtful accounts. For oil and gas sales receivables we generally only consider booking an allowance if and when a specific instance of nonpayment occurs. Allowance for doubtful accounts was $nil at December 31, 2010 and 2009; July 31, 2010 and July 31, 2009.

Segment Information

The Company adopted Accounting Standards Codification subtopic Segment Reporting 280-10 (“ASC 280-10”). ASC 280-10 establishes standards for reporting information regarding operating segments in annual consolidated financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. ASC 280-10 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision making group, in making decisions concerning how to allocate resources and assess performance. The Company applies the management approach to the identification of our reportable operating segment as provided in accordance with ASC 280-10 and concluded that the Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations. The information disclosed herein, materially represents all of the financial information related to the Company's principal operating segment.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of properties within a relatively large geopolitical cost center in our case, by country, and are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs designated as unproven properties are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at December 31, 2010 and 2009 and July 31, 2010 and 2009. Unevaluated and undeveloped costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

F-9

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable country cost center. The Company has assessed the impairment for oil and natural gas properties for the full cost pool at each reporting date and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes is compared to (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues is based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test takes into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price is consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities from November 21, 2008 (date of inception) through December 31, 2010. Application of the ceiling test is required for reporting purposes, and any write-downs are not reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss as recognized in income.Abandonment of properties is accounted for as adjustments of capitalized costs with no recognized in current period operations.

Furniture and Fixtures

Furniture and fixtures are recorded at cost and depreciated on a straight-line basis over estimated useful lives of five years. Repair and maintenance costs are charged to expense as incurred while acquisitions are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of property, plant and equipment are recorded in the period incurred. The net book value of the property, plant and equipment that is retired or sold is charged to accumulated depreciation and amortization, and the difference is recognized as a gain or loss in the results of operations in the period the retirement or sale transpires.

Reserves

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. Under the SEC’s final rule, prior period reserves were not restated. The Company has used this guidance in reporting reserve information.

F-10

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Impairment of long lived assets

The Company has adopted Accounting Standards Codification subtopic 360-10, Property, Plant and Equipment (“ASC 360-10”). The Statement requires that long-lived assets and certain identifiable intangibles held and used by the Company be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Events relating to recoverability may include significant unfavorable changes in business conditions, recurring losses, or a forecasted inability to achieve break-even operating results over an extended period. The Company evaluates the recoverability of long-lived assets based upon forecasted undiscounted cash flows. Should impairment in value be indicated, the carrying value of intangible assets will be adjusted, based on estimates of future discounted cash flows resulting from the use and ultimate disposition of the asset. ASC 360-10 also requires assets to be disposed of be reported at the lower of the carrying amount or the fair value less costs to sell.

Fair Values

The Company has adopted Accounting Standards Codification subtopic 820-10, Fair Value Measurements and Disclosures (“ASC 820-10”). ASC 820-10 defines fair value, establishes a framework for measuring fair value, and enhances fair value measurement disclosure. ASC 820-10 delayed, until the first quarter of fiscal year 2009, the effective date for ASC 820-10 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of ASC 820-10 did not have a material impact on the Company’s financial position or operations. Refer to Note 12 for further discussion regarding fair valuation.

Income Taxes

The Company has adopted Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Temporary differences between taxable income reported for financial reporting purposes and income tax purposes are insignificant. The adoption of ASC 740-10 did not have a material impact on the Company’s consolidated results of operations or financial condition.

Comprehensive Income (Loss)

The Company adopted Statement of Accounting Standards Codification subtopic 220-10, Comprehensive Income (“ASC 220-10”) . ASC 220-10 establishes standards for the reporting and displaying of comprehensive income and its components. Comprehensive income (loss) is defined as the change in equity of a business during a period from transactions and other events and circumstances from non-owners sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. ASC 220-10 requires other comprehensive income (loss) to include foreign currency translation adjustments and unrealized gains and losses on available for sale securities.

F-11

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Net Loss per Share

The Company has adopted Accounting Standards Codification subtopic 260-10, Earnings Per Share (“ASC 260-10”) specifying the computation, presentation and disclosure requirements of earnings per share information. Basic loss per share has been calculated based upon the weighted average number of common shares outstanding. Stock options and warrants have been excluded as common stock equivalents in the diluted loss per share because their effect is anti-dilutive on the computation.

Fully diluted shares outstanding were 66,292,403 and 43,071,212 shares for the five months ended December 31, 2010 and 2009, respectively.

Fully diluted shares outstanding were 68,278,265 and 40,665,860 for the year ended July 31, 2010 and for the period November 21, 2008 (date of inception) through July 31, 2009, respectively.

Stock based compensation

Effective since inception, the Company has adopted Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”) which requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. This statement does not change the accounting guidance for share based payment transactions with parties other than employees provided in ASC 718-10. The Company implemented ASC 718-10 on November 21, 2008 (date of inception) using the modified prospective method.

As more fully described in Note 9 below, the Company granted equity based compensation over the years to employees of the Company under its equity plans. The Company granted non-qualified stock options of 625,000 and nil shares of common stock of the Company and nil (cancellations of 30,000) and 235,000 shares of the Company’s wholly owned subsidiary, Cougar Energy, Inc. during the five months ended December 31, 2010 and 2009, respectively, to employees and directors of the Company under the Employee Retention Plan. During the year ended July 31, 2010 and from November 21, 2008 (date of inception) through July 31, 2009, the Company granted non-qualified stock options to purchase 635,000 and nil shares of common stock of the Company and 920,000 (net of cancellations of 125,000) and nil shares of the Company’s wholly owned subsidiary, Cougar Energy, Inc., respectively, to employees and directors of the Company under the Employee Retention Plan.

As of December 31, 2010, there were outstanding employee stock options to purchase 2,240,000 shares of the Company's common stock, 310,004 shares of which were vested.

F-12

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Recent accounting pronouncements

In May 2010, the FASB (Financial Accounting Standards Board) issued Accounting Standards Update 2010-19 (ASU2010-19), Foreign Currency (Topic 830): Foreign Currency Issues: Multiple Foreign Currency Exchange Rates. The amendments in this Update are effective as of the announcement date of May 2010. The provisions of ASU 2010-19 did not have a material effect on the financial position, results of operations or cash flows of the Company.

In April 2010, the FASB (Financial Accounting Standards Board) issued Accounting Standards Update 2010-17 (ASU 2010-17), Revenue Recognition-Milestone Method (Topic 605): Milestone Method of Revenue Recognition. The amendments in this Update are effective on a prospective basis for milestones achieved in fiscal years, and interim periods within those years, beginning on or after June 15, 2010. Early adoption is permitted. If a vendor elects early adoption and the period of adoption is not the beginning of the entity’s fiscal year, the entity should apply the amendments retrospectively from the beginning of the year of adoption. The Company does not expect the provisions of ASU 2010-17 to have a material effect on the financial position, results of operations or cash flows of the Company.

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

Going concern uncertainty

These consolidated financial statements have been prepared assuming the Company will continue as a going concern, which presumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has not consistently generated positive cash flow since inception and has incurred operating losses and will need additional working capital for its future planned activities. The success of these programs is yet to be determined. These conditions raise doubt about the Company’s ability to continue as a going concern. Continuation of the Company as a going concern is dependent upon obtaining sufficient working capital to finance ongoing operations. The Company’s strategy to address this uncertainty includes seeking additional equity and debt financing; however, there are no assurances that any such financings can be obtained on favorable terms, if at all. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.

2. PREPAID EXPENSES AND DEPOSITS

Prepaid expenses and deposits were comprised of the following:

	December 31, 2010		December 31, 2009		July 31, 2010		July 31,  2009
Prepaid general and administrative expenses	$	20,043	$	-	$	50,340	$	-
Prepaid rent		27,885		27,885		27,885		-
Prepaid insurance		-		10,227		4,008		-
Deposits and other		11,110		32,036		1,164		-
Total	$	59,038	$	70,148	$	83,397	$	-

F-13

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

3. OIL AND GAS PROPERTIES

Major classes of oil and gas properties under the full cost method of accounting consist of the following:

	December 31,
	2010		2009
Proved properties, net of cumulative impairment charges	$	9,212,427	$	7,184,463
Unevaluated and Unproved properties		3,936,797		3,920,062
Gross oil and gas properties		13,149,224		11,104,525
Less: accumulated depletion, accretion and impairments		(3,466,639)		(2,276,463)
Net oil and gas properties	$	9,682,585	$	8,828,062

	July 31,
	2010		2009
Proved properties, net of cumulative impairment charges	$	8,587,053	$	-

Unevaluated and Unproved properties		3,934,051			4,064,730
Gross oil and gas properties		12,521,104			4,064,730
Less: accumulated depletion, accretion and impairments		(3,087,053	)		-
Net oil and gas properties	$	9,434,051		$	4,064,730

Unevaluated and Unproved Properties

The Company has certain unevaluated and unproved properties, valued at cost, that have been excluded from costs subject to depletion. These costs amounting to $3,936,797 as at December 31, 2010 (December 31, 2009 - $3,920,062, July 31, 2010-$3,934,051, July 31, 2009-$4,064,730) are subject to a test for impairment that is separate from the test applied to proved properties.

Included in the Company’s oil and gas properties are asset retirement obligations of $1,207,371 and $1,185,439, comprising both current and long term items as of December 31, 2010 and 2009, respectively and $1,222,105 and $94,982, comprising both current and long term items as of July 31, 2010 and 2009, respectively.

Quarterly, the Company assesses the value of unamortized capitalized costs within its cost center over the discounted present value of cash flows associated with its reserves. Any excess requires an immediate write-down of its capital costs by this amount, under the full cost ceiling test.

Impairment Charges

During the year ended July 31, 2010, total impairment charges under the full cost ceiling test were $2,132,179 and is reported within the expense category “Impairment of Oil and Gas Properties”. The most significant factor causing the full year charge was the write off during the year of reserves, which represented approximately 13% of carrying cost at July 31, 2009, together with earlier than expected depletion on a number of other wells, leading to other reserve reductions. Also oil prices continued to fall during the year ended July 31, 2010. Weighted average product prices in our July 31, 2010 reserves report, and used for the ceiling test at that date, were $69.87/bbl (CND).

During the five months ended December 31, 2010, total impairment charges under the full cost ceiling test were Nil (December 31, 2009 - $2,030,267- see above).

F-14

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

4. ACCOUNTS PAYABLE AND ACCRUED LIABLITIES

Accounts payable and accrued liabilities are comprised of the following:

	December 31,
	2010		2009
Accounts payable	$	1,185,027	$	922,130
Accrued expenses		604,886		158,320
Cash calls and Joint venture payables		99,353		134,769
Royalties and GST taxes payable		-		3,437
Total	$	1,889,266	$	1,218,656

	July 31,
	2010		2009
Accounts payable	$	1,598,827	$	901,031
Accrued expenses		264,913		-
Cash calls and Joint venture payables		111,390		36,358
Royalties and GST taxes payable		10,331		-
Total	$	1,985,461	$	937,389

F-15

5. OPERATING LINE OF CREDIT

During the year ended July 31, 2010 the Company reached formal agreement with a Canadian bank for two credit facilities. The first credit facility is a revolving demand loan facility in the amount of Cdn$1,500,000 bearing an interest at prime plus 3.5% per annum. The second credit facility is a $1,000,000 non-revolving acquisition/development demand loan bearing an annual interest rate of prime plus 3.0% per annum. Under the terms of the Agreement, the two credit facilities are committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves.

On October 14, 2010, the first credit facility revolving demand loan was increased from $1,500,000 to $2,500,000 and the second credit facility was then cancelled.

As at December 31, 2010, $2,025,000 of the revolving line was drawn (December 31, 2009 – nil, July 31, 2010-$1,425,000).

F-16

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

6. LONG TERM AND SHORT TERM NOTES PAYABLE

Long term and short term notes payable are comprised of the following:

	December 31,
	2010			2009
Obligation under purchase and sale agreement to acquire property from vendor, gross amount	$	3,930,000		$	4,700,000
Amount of discount to be accreted in the future (at 7.5% annually - .0625% per month)		(413,908	)		(683,597	)
Net carrying value		3,516,092			4,016,403
Less current portion		(808,906	)		(500,311	)
Long term portion	$	2,707,186		$	3,516,092

Current portion of long term debt-as above	$	808,906	$	500,311
Note payable-non- interest bearing, due on demand		10,000		66,000
Total current maturities of long term debt	$	818,906	$	566,311

	July 31,
	2010			2009
Obligation under purchase and sale agreement to acquire property from vendor, gross amount	$	4,210,000		$	-
Amount of discount to be accreted in the future (at 7.5% annually - .0625% per month)		(519,898	)		-
Net carrying value		3,690,102			-
Less current portion		(638,124	)
Long term portion	$	3,051,978		$	-

Current portion of long term debt-as above	$	638,124	$	-
Note payable-non- interest bearing, due on demand		34,000		-
Total current maturities of long term debt	$	672,124	$	-

On August 18, 2009, the Company entered into a Purchase and Sale Agreement to acquire certain oil and gas properties. The Gross purchase price of $6,000,000 is payable over a 54 month term with variable monthly payments. Amounts owing under the Purchase and Sale Agreement are non-interest bearing.

The Company recorded the obligation at present value using an interest rate of 7.5% per annum and is accreting using the effective interest method over the term of the obligation.

The Company has the right to prepay the vendor loan in full, without penalty, semi-annually commencing March 31, 2010 at a proportionate discount to the original purchase price. The indebtedness is secured by a debenture covering a fixed and floating charge over Cougar's interest in the acquired properties.

On January 6, 2010, the Company issued a $200,000 unsecured promissory note, due one year from the date of the note with interest at Bank of Canada prime plus 1%,. As of December 31, 2010, the balance under this promissory note was $Nil.

F-17

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

6. LONG TERM AND SHORT TERM NOTES PAYABLE

On December 19, 2009, the Company issued a $15,000 U.S. promissory note, due on demand with interest at Canada prime plus 2%. As of December 31, 2010, the balance under this promissory note was $15,623 CAN.

7. ASSET RETIREMENT OBLIGATIONS

The Company’s financial statements reflect the provisions of Accounting Standards Codification Subtopic 410-20, Asset Retirement Obligations (“ASC 410-20”) ASC 410-20 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by ASC 410-20, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the Consolidated Balance Sheet. Periodic accretion of discount of the estimated liability is recorded, as appropriate, as an expense in the Consolidated Statement of Operations and is included in depletion, depreciation and accretion. The Company’s asset retirement obligations relate to all of the wells. The Company has recognized an asset retirement liability of $1,332,747 and $1,221,793 at December 31, 2010 and 2009, respectively, and of $1,311,206 and $107,667 at July 31, 2010 and 2009, respectively.

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,023,859 (December 31, 2009 - $2,992,241, July 31, 2010-$3,067,453, July 31, 2009-$162,362). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 14 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and a rate of inflation of 2.5%.

Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties are as follows:

	December 31,
	2010		2009
Asset retirement obligations, beginning of the period	$	1,311,206	$	107,667
Additions		-		1,090,456
Accretion		37,207		23,670
Assets retired		(15,666)		-
Asset retirement obligations, end of period	$	1,332,747	$	1,221,793

	July 31,
	2010		2009
Asset retirement obligations, beginning of the period	$	107,667	$	-
Additions		1,127,123		103,154
Accretion		76,416		4,513
Asset retirement obligations, end of period	$	1,311,206	$	107,667

F-18

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

8. STOCKHOLDERS EQUITY

The Company is authorized to issue an unlimited number of no par value preferred and common stock.

As of December 31, 2010 and 2009, the Company had no preferred stock issued and outstanding and had outstanding common stock totaling 64,047,111 and 44,997,979 shares, respectively.

As of July 31, 2010 and 2009, the Company had issued and outstanding 61,853,353 and 40,665,860 shares of common stock, respectively.

On January 25, 2010, in connection with the reverse acquisition, the Company affected a three-for-one (3 to 1) stock split of its issued and outstanding shares of no par value common stock. All references in the consolidated financial statements and the notes to consolidated financial statements, number of shares, and share amounts have been retroactively restated to reflect the split.

During the period ended July 31, 2009, the Company issued an aggregate of 38,076,933 shares of common stock to acquire oil and gas properties. The fair value was determined based on the acquisition cost of Kodiak Energy, Inc., the Company’s parent.

During the period ended July 31, 2009, the Company sold 2,588,822 shares of the Company’s common stock for $473,908. This was the initial startup investment into the private subsidiary by early investors for non-liquid shares of Cougar Energy, Inc. Subsequent to the share exchange with Oremore, these shares were converted to shares of Cougar Oil and Gas Canada, Inc.

During the five months ended December 31, 2009, the Company issued 697,500 shares to acquire oil and gas property. As previously disclosed as the Mystahiya transaction

During the year ended July 31, 2010 (and December 31, 2010), the Company issued 6,930 shares of the Company’s common stock in exchange for exercise of warrants

During the five months ended December 31, 2009, the Company issued 3,634,619 shares of the Company’s common stock for cash totaling $722,469.

During the five months ended December 31, 2010, the Company issued 185,840 common shares, at fair value, in repayment of debt in the amount of $482,768, issued 2,007,918 common shares in exchange for the exercise of warrants and cash totaling $590,220 after expenses and 648,444 shares of the Company’s common stock in exchange for a related party note receivable. As previously disclosed – Kodiak Energy, Inc acquired debt instruments of Cougar Energy, Inc and then converted the debt to shares in Cougar Oil and Gas Canada, Inc.

9. STOCK OPTIONS AND WARRANTS

Options

Cougar Oil and Gas Canada Stock Option Plan

Cougar Oil and Gas Canada has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable 1/3 per year over the first three years of the term of the option.

F-19

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

9. STOCK OPTIONS AND WARRANTS (continued)

Transactions involving options issued to employees are summarized as follows:

	Number of Shares		Weighted Average Price Per Share
Outstanding at November 21, 2008		-	$	-
Granted		-		-
Exercised		-		-
Canceled or expired		-		-
Outstanding at December 31, 2008		-	$	-
Granted		-		-
Exercised		-		-
Canceled or expired		-
Outstanding at December 31, 2009		-	$
Granted		1,260,000		2.47
Exercised		-		-
Canceled or expired		-		-
Outstanding at December 31, 2010		1,260,000	$	2.47

A summary of options granted and outstanding under the plan is as follows:

December 31, 2010
Weighted average
Exercise Price		Shares
$	1.40		50,000
$	1.52		50,000
$	1.83		45,000
$	2.02		35,000
$	2.36		30,000
$	2.38		600,000
$	2.92		450,000
$	2.47		1,260,000

Outstanding								Exercisable
Number outstanding at December 31, 2010		Weighted Average  remaining Contractual  life		Weighted  average  Exercises  Price		Aggregate intrinsic value		Number outstanding at  December 31, 2010		Weighted average  Exercise price	Aggregate Intrinsic  Value
	35,000		4.25	$	2.02		-		-			-
	600,000		4.42	$	2.38		-		-			-
	50,000		4.78	$	1.40
	50,000		4.82	$	1.52
	45,000		4.91	$	1.83
	30,000		4.93	$	2.36
	450,000		4.96	$	2.92
	1,260,000			$	2.47

During the year ended July 31, 2010, the Company granted an aggregate of 635,000 stock options with an exercise price from $2.02 to $2.38 expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:		-0-	%
Volatility		100.0	%
Risk free rate:	2.61% to 2.89 %

During the five months ended December 31, 2010, the Company granted an aggregate of 625,000 stock options with an exercise price from $1.40 to $2.92 expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:		-0-	%
Volatility		100.0	%
Risk free rate:	1.94% to 2.56 %

F-20

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

9. STOCK OPTIONS AND WARRANTS (continued)

Cougar Energy, Inc. Stock Option Plan

Cougar Energy, Inc. (a wholly owned subsidiary of the Company) has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable 1/3 per year over the first three years of the term of the option.

Transactions involving options issued to employees are summarized as follows:

	Number of Shares		Weighted Average Price Per Share
Outstanding at November 21, 2008		-	$	-
Granted		-		-
Exercised		-		-
Canceled or expired		-		-
Outstanding at December 31, 2008		-	$	-
Granted		985,000		0.82
Exercised		-		-
Canceled or expired		-
Outstanding at December 31, 2009		985,000	$	0.82
Granted		60.000		-
Exercised		-		-
Canceled or expired		(55,000)		-
Outstanding at December 31, 2010		990,000	$	0.82

A summary of options granted and outstanding under the plan is as follows

December 31, 2010
Weighted average  Exercise
Price		Shares
$	0.65		725,000
$	1.30		265,000
$	0.82		990,000

Outstanding								Exercisable
Number  outstanding at December 31, 2010		Weighted  Average  remaining  Contractual life		Weighted  average  Exercises Price		Aggregate intrinsic value		Number outstanding at December 31,  2010		Weighted average  Exercise  price		Aggregate Intrinsic  Value
	725,000		3.04	$	0.65		-		310,004	$	0.65	-
	265,000		3.84	$	1.30		-		-		-	-
	990,000			$	0.82				310,004	$	0.65	-

During the year ended July 31, 2010, the Company granted an aggregate of 295,000 stock options (30,000 options cancelled during the five months ended December 31, 2010) with an exercise price of $1.30 expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:		-0-	%
Volatility		100	%
Risk free rate:	2.51% to 2.75 %

During the five months ended December 31, 2010, the Company did not grant any additional options.

The fair value of all employee options vesting in the five month periods ended December 31, 2010 and December 31, 2009 of $301,311 and $58,931, respectively, was charged to current period operations.

Subsequent to the period end, on January 1, 2011, Cougar Energy, Inc. merged with its parent, Cougar Oil and Gas Canada Inc. Both of the companies are Alberta corporations and were merged in a statutory amalgamation under Alberta corporate law. Upon that merger, and after giving effect to the Cougar Oil and Gas Canada/Cougar Energy Inc. share exchange at 1:1.5 and the subsequent 3:1 split of Cougar Canada Oil and Gas Canada Inc. shares, the 625,000 and 295,000 outstanding Cougar Energy, Inc. stock options exercisable at $.65 and $1.30 per share, respectively shown above became 2,812,500 and 1,327,500 outstanding Cougar Oil and Gas Canada stock options exercisable at $.144 and $.289 respectively.

F-21

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

9. STOCK OPTIONS AND WARRANTS (continued)

Warrants

The following table summarizes in warrants outstanding and related prices for the shares of the Company’s common stock issued to shareholders at December 31, 2010:

				Warrants Outstanding Weighted Average						Warrants Exercisable
				Remaining		Weighted				Weighted
		Number		Contractual		Average		Number		Average
Exercise Price		Outstanding		Life (years)		Exercise price		Exercisable		Exercise Price
$	0.288		1,907,655		0.57	$	0.288		1,907,655	$	0.288
$	0.577		2,301,003		0.62	$	0.577		2,301,003	$	0.577
	Total		4,208,658		0.60				4,208,658

Transactions involving the Company’s warrant issuance are summarized as follows:

	Number of Shares		Weighted Average Price Per Share
Outstanding at July 31 and December 31, 2009		-	$	-
Issued		6,223,506		0.98
Exercised		(6,930)		0.577
Canceled or expired
Outstanding at July 31, 2010		6,216,576		0.40
Issued		-		-
Exercised		(2,007,918)		0.29
Canceled or expired		-		-
Outstanding at December 31, 2010		4,208,658	$	0.35

10. RELATED PARTY TRANSACTIONS

From time to time, the Company’s majority shareholder, Kodiak Energy, Inc. has provided working capital to the Company. There are no formal repayment terms and the loan is interest free. As of December 31, 2010 and 2009, the balance due was $458,008 and $1,104,252, respectively and as of July 31, 2010 and 2009, the balance due was $674,519 and $180,668, respectively.

During the year ended July 31, 2009, the Company issued 38,076,933 of the Company’s common stock in exchange for oil and gas properties held by Kodiak Energy, Inc.; the Company’s parent. The valuation was recorded at the underlying cost of Kodiak and the deemed value of the land.

F-22

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

10. RELATED PARTY TRANSACTIONS (continued)

During the year ended December 31, 2010, the Company issued 185,840 common shares at fair value, in payment of debt totaling $482,768 held by Kodiak Energy, Inc. the Company’s parent.

The Company paid $25,000 to a company owned and controlled by the chairman of the Company for management consulting services during the five months ended December 31, 2010 ($35,000 during the year ended July 31, 2010). Of this amount, $21,000 was payable on December 31, 2010 ($10,500-July 31, 2010). The Company paid the wife of the chairman of the Company $13,560 for administration consulting services during the five months ended December 31, 2010 ($11,340 for the year ended July 31, 2010). Of this amount, $5,292 was outstanding on December 31, 2010 ($4,032 - July 31, 2010). These amounts were charged to General and Administrative Expense.

Cougar Energy Inc. paid management fees to Kodiak Energy, Inc. in the amount of $393,500 for the year ended July 31, 2009 and $190,000 July 31, 2010. Fees paid for the five months ended December 31, 2009 were $190,000 and December 31, 2010 $Nil.

During the five months ended December 31, 2010, the Company exchanged $425,000 and $90,000 debt owed to Zentrum and Menschen for debt owed to Kodiak Energy, Inc. the Company's parent.

These related party transactions were non arm's length transactions in the normal course of business and agreed to by the related parties and the Company based on negotiations and Board approval and accordingly had been measured at the exchange amounts.

11. COMMITMENTS AND CONTINGENCIES

Lease Commitments

As of December 31, 2010 and 2009, the Company had lease commitments for office space and equipment as shown below:

	2010		2009
Amounts payable in:
2010	$		$	125,481
2011		208,275		167,307
2012		208,275		167,307
2013		75,394		41,827

As of July 31, 2010 and 2009, the Company had lease commitments for office space and equipment as shown below:

	July 31, 2010		July 31, 2009
Amounts payable in:
2011	$	175,280	$	-
2012		175,280		-
2013		118,182		-

The Company relocated its offices in December 2009 and pays rent of approximately $14,000 per month until the lease expires in February 2013. The rent expense for the five months ended December 31, 2010 and 2009 is $67,732 and $nil, respectively. ($67,732--July 31, 2010 and $nil--July 31, 2009). The remaining lease commitments pertain to two trucks and a number of office computers.

F-23

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

11. COMMITMENTS AND CONTINGENCIES (continued)

Litigation

The Company is subject to other legal proceedings and claims, which arise in the ordinary course of its business. Although occasional adverse decisions or settlements may occur, the Company believes that the final disposition of such matters should not have a material adverse effect on its financial position, results of operations or liquidity. There was no outstanding litigation as of December 31, 2010.

12. FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

ASC 825-10 defines fair value as the price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. When determining the fair value measurements for assets and liabilities required or permitted to be recorded at fair value, the Company considers the principal or most advantageous market in which it would transact and considers assumptions that market participants would use when pricing the asset or liability, such as inherent risk, transfer restrictions, and risk of nonperformance. ASC 825-10 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. ASC 825-10 establishes three levels of inputs that may be used to measure fair value:

Level 1 - Quoted prices in active markets for identical assets or liabilities.

Level 2 – Observable inputs other than Level 1 prices such as quoted prices for similar assets or liabilities; quoted prices in markets with insufficient volume or infrequent transactions (less active markets); or model-derived valuations in which all significant inputs are observable or can be derived principally from or corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3 – Unobservable inputs to the valuation methodology that are significant to the measurement of fair value of assets or liabilities.

To the extent that valuation is based on models or inputs that are less observable or unobservable in the market, the determination of fair value requires more judgment. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, for disclosure purposes, the level in the fair value hierarchy within which the fair value measurement is disclosed is determined based on the lowest level input that is significant to the fair value measurement.

The carrying amounts of financial instruments, which include cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued expenses, other current liabilities, revolving credit facility and debt approximate their fair values due to their short maturities and variable interest rate on the revolving credit facility and fixed rates which approximate market rates on notes payable.

F-24

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

13. INCOME TAXES

For the five months ended December 31, 2010 and 2009:

The Company has adopted Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

For the five-month periods ended December 31, 2010 and 2009, a reconciliation of the income tax benefit at the combined Canadian federal and Alberta provincial statutory rate to the income tax benefit at the Company's effective tax rate is as follows.

	2010			2009
Combined statutory rate	28		%	29		%
Income tax benefit at combined statutory rate	$	315,658		$	693,586
Stock compensation expense		(119,835	)		(37,181	)
Impact of rate change		(32,581	)		(16,825	)
Other		(4,307	)		(9,765	)
Change in valuation allowance	$	158,935		$	629,815

The provision for income taxes differs from the amount of income tax determined by applying the applicable Canadian statutory rate to losses before income tax expense for the five month periods ended December 31, 2010 and 2009 as follows:

	December 31,
	2010			2009
Statutory federal income tax rate		18.00	%		19.21	%
Statutory provincial income tax rate		10.00	%		10.00	%
Stock compensation expense		(10.63	%)		(1.56	%)
Impact of rate change		(2.89	%)		(0.70	%)
Other		0.38	%		0.41	%
Net operating losses and other tax benefits for which no current benefit is being realized		(14.86	%)		(26.545	%)
Effective tax rate		0.00	%		0.00	%

F-25

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

13. INCOME TAXES (continued)

Deferred tax assets (liabilities) at December 31, 2010 and 2009 are comprised of the following:

	2010			2009
Deferred tax assets
Excess of capital assets tax deductions over book value	$	1,238,587		$	946,774
Non-capital operating losses		422,959			337,482
Asset retirement obligations		373,169			354,320
Total deferred tax assets		2,034,715			1,638,576
Deferred tax liabilities		-			-
Net deferred tax asset before valuation allowance		2,034,715			1,638,576
Less valuation allowance		(2,034,715	)		(1,638,576	)
Net deferred tax asset	$	-		$	-

As at December 31, 2010 and 2009, the Company's deferred tax asset attributable to its non-capital operating losses carried forward are $422,959 and $337,482 respectively and will expire in the years 2016 and 2017, if not utilized. Undeducted capital costs can be carried forward indefinitely. As reflected above, the calculated tax benefit has been fully offset by a valuation allowance based on management's determination that it is not more likely than not that some or all of this benefit will be realized. We do not have any unrecognized tax benefits or loss contingencies.

For the year ended July 31, 2010 and from November 21, 2008 (date of inception) through July 31, 2009:

For the years ended July 31, 2010 and 2009, a reconciliation of the income tax benefit at the combined Canadian federal and Alberta provincial statutory rate to the income tax benefit at the Company's effective tax rate is as follows.

	July 31, 2010			July 31, 2009
Combined statutory rate	28.42		%	29.21		%
Income tax benefit at combined statutory rate	$	904,937		$	148,883
Difference arising from additional tax deductible property cost		-			782,115
Impact of rate change		(26,755	)		-
Other		(247	)		2,388
Change in valuation allowance	$	877,935		$	933,386

The provision for income taxes differ from the amount of income tax determined by applying the applicable Canadian statutory rate to losses before income tax expense for the year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009 as follows:

F-26

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

13. INCOME TAXES (continued)

	July 31,
	2010			2009
Statutory federal income tax rate		18.42	%		19.21	%
Statutory provincial income tax rate		10.00	%		10.00	%
Difference arising from additional tax deductible property cost		.00	%		153.44	%
Other		(.76	%)		.46	%
Net operating losses and other tax benefits for which no current benefit is being realized		(27.66	%)		(183.11	%)
Effective tax rate		0.00	%		0.00	%

Deferred tax assets (liabilities) at July 31, 2010 and 2009 are comprised of the following:

	July 31, 2010			July 31, 2009
Deferred tax assets
Excess of capital assets tax deductions over book value	$	1,144,563		$	754,373
Non-capital operating losses		350,002			147,565
Asset retirement obligations		372,601			31,448
Total deferred tax assets		1,867,166			933,386
Deferred tax liabilities		-			-
Net deferred tax asset before valuation allowance		1,867,166			933,386
Less valuation allowance		(1,867,166	)		(933,386	)
Net deferred tax asset	$	-		$	-

As at July 31, 2010 and 2009, the Company's deferred tax asset attributable to its non-capital operating losses carried forward are $350,002 and $147,565 respectively and will expire in the years 2016 and 2017, if not utilized. Capital costs not deducted can be carried forward indefinitely. As reflected above, the calculated tax benefit has been fully offset by a valuation allowance based on management's determination that it is not more likely than not that some or all of this benefit will be realized. We do not have any unrecognized tax benefits or loss contingencies.

14. SUBSEQUENT EVENTS

On January 1, 2011, Cougar Oil and Gas Canada, Inc. was amalgamated with its wholly owned subsidiary, Cougar Energy, Inc. As a result of the amalgamation, the Company, which will continue under the name Cougar Oil and Gas Canada, Inc., has changed its financial reporting year end to December 31st.

Subsequent to December 31, 2010, the Company has issued a total of 3,823,170 common shares pursuant to the exercise of warrants with proceeds totaling $1,255,842.

F-27

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

14. SUBSEQUENT EVENTS (continued)

The Company received $900,000 from Kodiak Energy Inc. and issued an 18 months unsecured convertible note to Kodiak on January 31, 2011 in the same amount with an interest rate of prime plus 3% per annum. Kodiak will also receive a 1% gross over-riding royalty on two wells that the funds are intended to finance. The note is convertible into common shares of the Company at a price of $3.52 per share.

During February 2011, the Company received the initial draw down of 950,000 Swiss Francs ($985,388 CAN) on an unsecured note agreement with a maximum issuance of 4,700,000 Swiss Francs (approximately $5,000,000 CAN),

subject to certain conditions. The note has a term of 18 months and accrues interest at the rate of Bank of Canada prime plus 3% per annum.The holder of the note, Zentrum Energie Trust SA, has the option to convert the balance of the note plus accrued interest into common shares of Cougar at the rate of $3.00 per common share along with a warrant to purchase additional common shares on a 1:1 basis for a period of 4 years at a price of $3.90 per common share.

On March 4, 2011, Mr. David Wilson resigned as Chief Financial Officer due to health reasons. On the same date, Mr. Richard Carmichael was appointed as Mr. Wilson’s replacement. Mr. Carmichael is a Chartered Accountant who has held senior financial positions within the oil and gas exploration and production, and oil and gas service industries over the past 20 years.

On March 17, 2011 Cougar has entered into a two phase farm-in agreement with TAMM Oil and Gas Corporation (TAMM) which will ultimately result in Cougar earning a 50% working interest in approximately 47 sections or 30,000 acres of heavy oil prospective lands in the Manning area. This is in the same area as the heavy oil farm-in agreement previously announced by the Corporation on February 14, 2011. TAMM originally acquired these lands in 2008 and has a previously prepared independent third party estimate of 3.14 billion barrels of original oil in place for the prospect

The Farm-in agreement has two earning phases which will allow Cougar to become the operator and earn a 50% working interest in the prospect. The first phase of the farm-in is a work commitment to earn a 30% working interest of the TAMM prospect. The work commitment will consist of Cougar spending $2.5 million over the next 12 months on a work program consisting of seismic and drilling evaluation, and independent third party geological and project feasibility studies. Cougar will also become the operator of the project area once the first phase is completed.

The second phase of the farm-in will allow Cougar to earn an additional 20% working interest of the TAMM prospect and includes a work commitment to spend an additional $6.5 million over a 24 month period following the first phase. The work program will consist of drilling, coring, feasibility studies and updates to reserve/resource estimates.

F-28

The following supplemental information on oil and gas producing activities (unaudited) replaces in its entirety the information starting on page 60 (after the financial statements) through page 66 of the Form 20-F of the registrant as originally filed on March 31, 2011, to update and add certain of the data and disclosure therein to respond to comments of the Staff of the Securities and Exchange Commission.

AMENDED SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING

ACTIVITIES (UNAUDITED)

(All currency amounts in Canadian dollars))

In accordance with the Accounting Standards Update 2010-03, Extractive Activities - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, ("ASU 2010-03"), issued by the Financial Accounting Standards Board of the United States, this section provides supplemental information on oil and gas exploration and producing activities of the Company as of December 31, 2010 in the following tables. Since there were no reserves or revenue for the preceding year of 2008 there is no comparison tables provided for those years. Tables I through V provide historical cost information under US GAAP pertaining to capitalized costs related to oil and gas producing activities; costs incurred in oil and gas exploration and development; and results of operations related to oil and gas producing activities. Tables V through XV present information on the Company’s estimated net proved reserve quantities; standardized measure of discounted future net cash flows;

This statement of reserves data and other information (the “Statement”) is dated March 8, 2011 and is effective December 31, 2010. The preparation date of the information in this Statement was March 8, 2011.

1. The Third Party report on Reserves by GLJ Petroleum Consultants was prepared in accordance with requirements contained in Item 1202 (a) (8) of US Securities and exchange Commission Regulations S-K – the certificate is filed as Exhibit 10.8 herein. The report as filed does not satisfy the SEC reporting requirements in certain respects. We specifically make note that this Report is not in compliance with Regulation S-K Subpart 1202.

1

2. Description of Properties and Plan of Operations  

Trout Core Properties-

Over a period of 6 months in 2009, Cougar Energy, Inc. negotiated commercial terms for properties that management believes have the greatest upside through normal maintenance and enhanced recovery programs as well as future potential with additional drilling. These negotiations culminated at the end of September and beginning of October 2009 with Cougar Energy successfully acquiring the Trout Core Area properties from two private oil and gas companies. Operations commenced on these properties during the winter of 2009/10 consisting of a maintenance and work over programs. By December 31, 2009 we had reactivated four wells that were previously suspended. By July 31, 2010, we had optimized the surface and bottom hole equipment on nine wells and had 13 wells in production and completed substantial geological evaluation on the properties.

The following represents a summary of the acquisitions completed over calendar year of 2009 - 2010 of producing and non-producing properties in the Trout Core Area:

A. Private Company Production and Property Acquisition (completed October 1, 2009) Cougar Energy negotiated a purchase agreement with the private company consisting of cash for the P1 reserves and Cougar shares for the P2 reserves.

The acquisition included 2560 gross acres of land and a 65% working interest in six wells – 2 producing wells and 4 suspended wells located in the Kidney and Equisetum fields. Approximately 12 barrels per day (bbl/d) net production (20 bbl/d gross) of light oil at time of acquisition

B. Private Company Production and Property Acquisition (completed Sept. 30, 2009) Trout and Peerless Properties  

The agreed purchase price was Cdn$6,000,000 with an initial payment of Cdn$1,000,000 at closing. The purchase price was negotiated at $52.50 per barrel (bbl) when oil was currently selling at $75+/bbl. Included 7,100 gross acres of mineral rights with an average 85% working interest (all continued through production, no expiries). 85 bbl/d at time of acquisition with 13 pumping wellbores – 8 at time of acquisition 1 observation wellbore and 21 suspended wellbores, 8 single well batteries, 3 water disposal wellbores with associated facilities, 2 multi well batteries with existing fluid handling capacity in excess of 2500bbl/day (oil, gas and water handling and treating capability, approximately 38.7 km of pipelines) (oil and produced water), approximately 13 km2 of 3D seismic over the properties and approximately 84 km of 2D seismic over the properties and adjacent lands. The majority of this acquisition is outside the boundary of the Peerless Trout Lake First Nations. The current surface facilities have a replacement value of Cdn$6,500,000 with a depreciated value of Cdn$1,000,000. The overall project has an estimated Cdn$50,000,000 in replacement value including wells, facilities, pipelines, roads and power lines.

After operating costs, there is an average of Cdn$50 net back per barrel at current commodity prices. The cash portion of the acquisition cost was provided by Kodiak Energy and subsequent guarantees by Kodiak Energy and Cougar Energy. Kodiak Energy was able to borrow sufficient funds for the acquisition on behalf of Cougar Energy by way of a bridge loan. Cougar Energy then closed the acquisitions September 30 and October 1, 2009.

This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs, lower development costs and giving our schedule an 1-3 year leap forward to achieve our goals of creating a 3- 5,000bbl/d company in a short period of time. Without this kind of infrastructure, the initial production would have lower netbacks due to higher trucking costs and regular non-producing periods due to weather. In lieu of

this acquisition, a large amount of capital would have to be spent to bring facilities to this baseline, which we now have. At current costs, the infrastructure replacement value would be substantially in excess of Cdn$6,000,000. This capital will be spent on the drilling and development work, allowing for a more aggressive growth plan.

2

The existing area field personnel transferred to Cougar Energy and their many years of hands-on field expertise has already added value.

There are two batteries for the handling and treating of oil and the disposal of the produced water. The batteries are capable of handling an estimated 2,500 bbl/d with nominal refit costs. Many of the wells are piped into the batteries to lower the need for trucking which is especially important for the higher water cut wells – these pipelines can be expanded to further lower operating costs. The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in our control and not third party pipeline operator dependent. There are 37 wells, of which 13 were producing as of July 31, 2010 – the 21 suspended wells have potential upside, as discussed below. We have completed a substantial amount of due diligence and are comfortable with the projected estimated Cdn$50.00 netbacks from these properties at current commodity prices, and this provides for a safety margin much lower than the lowest price seen in the recent recession.

During 2010 the Company had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. The Companies monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day but this production potential has been curtailed as a result of ongoing maintenance and repair issues over the reporting period. As these maintenance and repair issues are resolved over the next year, it is anticipated production will increase accordingly. It is also anticipated production will increase as a result of the ongoing development drilling operations. We averaged $30.00/bbl for the year ended 2010 for operating costs including maintenance costs. We believe that through ongoing maintenance and upgrades, we will reduce those costs to the $25 Cdn range and perhaps as low as $17 Cdn which we have experienced for short periods of time. We continue to receive $50 plus as a net back after royalties and are net positive for operations at year end. Refer to the Companies reserves report for additional information regarding NPV and forecast production.

The Trout field is a technically complicated field to operate as a result of two common wellbore scenarios. These scenarios include managing very high water cuts which results in excessive equipment fatigue and the extremely corrosive uphole formations which result in multiple casing failures. The Company identified these two scenarios prior to purchasing the Trout properties and believes the technical complexity of the Trout field reduces competition from entering the area resulting in additional available economic upside. Through our close attention to detail, extensive operations/maintenance experience, both down hole and at surface – we have the ability to manage costs, technical problems at a level not typically possible by majors.

C. Private Company Production and Property Acquisition (completed October 1, 2009) as a default from partners in the Lucy farm out.

Two producing oil properties in the Crossfield and Alexander fields in Central Alberta are:

(a)	100% working interest in the Crossfield property – one producing well with single well battery with approximately five barrels per day (bbl/d) net production – production continues to be stable with no capital commitment required; and
(b)	90% BPO (before payout) & 55% APO (after payout) working interest in the Alexander property- one producing Wabamun oil well with a single well battery and one suspended well. The Alexander property had some minor repairs completed and was put back on production in June 2010. Production is currently approximately 15 barrels per day net production.

We acquired these properties as part of the default on the previous Lucy farm out. See additional information in the Lucy discussion.

Production from the Company’s new proved reserves commenced on October 1, 2009, and recognition of the associated revenue and cash flow began on that date.

D. Public Company Production and Property Acquisition (Completed May 28, 2010.) Trout Core Properties

3

The acquisition included additional working interest and a royalty interest in seven Cougar Energy operated wells and a royalty interest in one non-operated well. The acquisition added approximately nine barrels of net oil production per day and approximately $450,000 of proved reserves (reserve value estimate based on Cougar Energy's Dec. 31, 2009 independent reserve report).

The purchase price for the acquisition was Cdn$215,000 and was funded from cash flow and Cougar Energy's previously announced credit facilities. The existing revenue and the new revenue from planned work programs will result in an expected payback of less than 12 months.

E. Subsequent Maintenance Programs on all Properties

Prior to each of the acquisitions, we conducted a detailed review of the acquired properties in the public domain petroleum records over last five to seven years and made a comparison to other operators in the area. In most instances operations and geological teams foresaw a considerable potential to increase production through normal maintenance activities. These existing technologies have proven to be successful in other similar maintenance programs in the area, and we saw a potential to enhance the current production levels within the acquired property. Some of these normal maintenance activities include and are not limited to: (a) Cleanouts and or Acid wash of perforations; (b) setting of bridge plugs to seal off water and or R-perforating; (c) Plug off water sources with no resulting loss of production; (d) Drill out plugs and open up previously unproduced zones; (e) Repairs to wells with separated rods Pump and well site equipment optimization; (f) ongoing Water flood programs

F. Acquisition of Crown Leases (completed July 12, 2010) – for Cdn$215,000 within the Trout Core Area

These leases consisting of 5,377 acres (mineral rights) are located immediately adjacent to Cougar Canada's existing Trout leases and are all within the identified Trout Core area. The Company now holds approximately 15,000 acres of provincial mineral rights. The lease types are a standard provincial 5-year Petroleum and Natural Gas lease including all formations from surface to basement. These leases will also benefit from the recently announced Alberta royalty incentives, which include a 5% New Well Royalty Rate for the first year of production.

        G.     Acquisition of Seismic - Cougar has purchased and evaluated 10.4Km2 of high resolution Trout Core area 3D seismic data. From the review we identified five (5) drilling targets and proceeded with the permitting for a three (3) well Keg River light oil drilling program for the winter of 2010/2011. – two wells were licensed, leases built and one well spudded and drilled to depth. The well has been put on production for testing at time of filing.

    H.     Disposition of non-core property – Crossfield. October 20, 2010, Cougar Oil and Gas Canada, Inc. closed the final stage of its divestiture of the Crossfield assets for Cdn$210,000–which amount was the approximate current P1 reserve value. Proceeds of the divestiture was used for ongoing field development work in Trout.

4. Trout Operations Growth Plans – The Company has prepared a multifaceted development program that is designed to carry the Company forward with the overall goals of increasing production. The plan is to efficiently execute field programs that combine the optimization of existing wells and infrastructure with additional infill drilling and supplemented with land acquisitions and 3D seismic supported exploration drilling. This combination of field operations represents a balanced portfolio of risk versus reward, which can be easily adjusted depending on cash flow, commodity prices and financing.

Field Optimization – Following the acquisition of the properties in the Trout area all of the existing wellbores and production practices were reviewed to identify inefficient practices. Approximately thirty field optimization projects were identified during the field review. The projects were primarily focused around field management and deliverability of existing assets.

The Company has finished implementing approximately half of the optimization projects originally identified during the field review, which resulted in a production increase in excess of 250%. The projects implemented in the field have included repair and replacement of surface and down hole production equipment, implementation of chemical enhancement programs and debottlenecking of pipeline and infrastructure facilities. The Company plans to continue to execute the remaining field optimization programs over the next 12 months.

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During the last couple of months Cougar has been working on several well reactivations in the Trout production field.

The 10-21 reactivation involved deepening the existing well by approximately 15 meters to penetrate a previously unproduced Keg River oil formation. Last week the Corporation successfully installed a packer in the wellbore to shutoff an uphole water source which will allow for the Keg River to be efficiently produced. The well also had a temporary hydraulic pumpjack installed on it and this has been replaced with a conventional pumpjack which will allow a substantially larger production rate.

The 13-25 reactivation involved repairing a wellbore and pumpjack that had been shut in for over three years. The downhole work was successfully repaired with no problems but the pumpjack repair took longer due to time required to get the gear box repaired. A maintenance crew recently finished all of the repair work and the well is currently on production.

The 11-22 reactivation involved a series of downhole repairs and installation of surface equipment. The downhole work included replacing a badly corroded production liner and stimulating the productive Keg River zone with an acid wash. The surface equipment will be moved from another site once the snow has melted and the lease has dried up. It is anticipated the 11-22 reactivation will be finished in Q2.

The reactivated wells also benefit from a 5% royalty holiday for the first twelve months of production. The royalty incentive was put in place by the provincial government and provides for very attractive economics and a quicker project payout.

Infill Drilling – The majority of the wells on the Trout properties were drilled almost twenty years ago when oil prices were much lower and infrastructure was much less developed. Infill drilling is an important optimization technique in which new vertical, directional and horizontal wells are added to an existing pool to maximize the total oil recovery.

The Company recently acquired 12 Km2 of 3D seismic over a core area of the existing property which complements the 3D seismic acquired in the original acquisition. The Company has finished evaluating these two 3D seismic surveys over their Trout and Peerless properties and has identified an additional 4-5 infill drilling locations to increase the overall drainage of the oil reserves. These infill locations have an expected find and development (F&D) cost of $5-7 per barrel. The Company plans include the first 2-infill wells in Q1, 2011. See subsequent event notes.

The Company has evaluated the overall seismic mapping for the area and has planned an extensive 3D program to be initiated in Q1, 2011. The size of this 3D program coupled with the drill results will support additional drilling programs described below. See subsequent event notes

In December of 2010, the company initiated licensing of 2 wells for an infill drilling program for Q1 2011. The horizontal well was initiated in late February of 2011.

The drilling, completion and workover operations in the Trout field have finished and the equipment has been demobilized back to the Red Earth area in anticipation of spring road bans. The planned second new drill has been deferred until the Corporation’s Q3 drilling program. There was not enough time to drill the second well before the spring weather resulted in road bans being implemented in Alberta. If the drilling rig was not moved off before road bans the Corporation would have been responsible for a very large stand-by charge every day the drilling rig and

equipment was stranded by the road bans so the decision was made by management to demobilize the drilling equipment after the first well was finished.

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Cougar finished drilling the horizontal Keg River oil well on March 20th. The horizontal leg was successfully drilled in the top two (2) meters of a ten (10) meter thick Keg River zone and has approximately 400 meters of horizontal productive formation. Upon entering the Keg River formation there was an immediate loss of circulation and increase of wellbore gas indicating a substantial reservoir was encountered. Using electro-magnetic directional tools the Corporation was able to successfully steer the horizontal wellpath to the required endpoint.

Once the drilling rig moved off the horizontal location the service rig and production equipment were moved on and rigged up. The Keg River in the Trout field has excellent inflow capability due to the substantial porosity and permeability and as such does not require the costly and time consuming stimulation work required by most of the current tight oil plays. The completion operations for Cougar’s horizontal well consisted of landing the tubing string and swabbing in multiple spots along the toe to the heel of the horizontal wellbore to confirm and induce formation inflow. Throughout the swabbing test the fluid level was maintained in the casing indicating a strong inflow of formation fluids. The final production equipment including the bottom hole pump and rods was run and the well has been put on production. It is anticipated it will take several weeks to recover all of the lost drilling fluids and begin producing the Keg River reservoir fluids.

The new wells benefit from a 5% royalty holiday for the first twelve months of production. The royalty incentive was put in place by the provincial government and provides for very attractive economics and a quicker project payout.

Cougar has completed the initial review of the processed 3D seismic data that was acquired in January. The seismic data confirms the multi-well vertical and horizontal development potential of the existing Keg River and Granite Wash oil pools but the 3D seismic also identified several new undeveloped oil reservoirs. The development drilling locations are key to increasing production and cash flow and the new undeveloped reservoirs can add significant reserves for the company to pursue. The Corporation is finalizing the locations for the next drilling program and expects to begin the permitting process by the end of April once the next phase seismic review has been completed.

Additional Development – In addition to the production optimization and infill drilling projects, The Company has been aggressively planning out the future growth for the Company. These plans include the acquisition of existing assets in the area and the development of neglected production areas. The Company is continuously evaluating acquisition opportunities in the core area and will act on these opportunities if the project details and economics are synergistic. Development plans include the following:

(a) The Company has identified several neglected production areas and has implemented a strategy to acquire land from public or private landowner around these areas whenever possible. Once the land has been acquired the Company will typically perform some additional seismic acquisition and review and then proceed with the drilling operations.

(b) The Trout area has excellent well control to assist the modeling of the future drilling programs. The majority of the wells drilled in the area were cored which allows for a detailed rock evaluation in additional to the conventional well log information. There is an important blend of geological and geophysical analysis to identify the target formations and the structure required to trap the oil in place.

(c) The Company is also evaluating other production areas in western Canada as potential acquisition targets and secondary core areas.

Continued Development of the Trout Area through Systematic Operational Controls

As we develop our maintenance program through the Trout Area lands in north central Alberta, we will continue to utilize our economic model to drive efficiency and minimize costs. We will focus our maintenance program on industry best practices and continued technological enhancements to maximize our return on assets and capital deployed.

Consolidate the Trout Area

To further enhance our economies of scale, we intend to be aware of other acquisition opportunities in the area. Consistent with our strategy to improve our financial flexibility, we intend to make acquisitions utilizing either equity and/ or debt instruments.

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Develop Trout Area Assets

We intend to prudently develop this acreage position by redeploying cash flow generated from area operations. We are currently evaluating a series of developmental drilling locations in addition to several step-out drilling locations with the goal of adding incremental reserves and cash flow. As we are focused on locations in areas with existing infrastructure, we expect our development plan to have a near-term material impact on our proved reserves and production. We believe investing in this area is the most expedient way for us to improve our financial flexibility and return on capital.

Northern Alberta – First Nations Joint Ventures:

First Nation ventures provide additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure. The Company continues to actively work on the First Nation joint ventures with a goal of responsible development of the leased oil and natural gas mineral rights. Private First Nation land represents some of the largest unleased blocks of mineral rights in the province of Alberta. Cougar has identified this type of Joint Venture as a strategically critical growth opportunity. The Company had paid an exclusivity fee to an First Nation agent, which provides the opportunity to lease specific mineral rights. The Company is also currently working with other First Nation groups to develop mutually beneficial joint venture agreements, which will allow Cougar and the First Nations to explore and develop conventional oil and natural gas prospects on both private and public lands. These joint venture projects will generally be developed using traditional exploration and development techniques, which include leasing blocks of mineral rights and using seismic and drilling to develop the prospects. Further information regarding these joint ventures will be provided when available.

First Nation Joint Venture and status of CREEnergy Project

Kodiak has a well-developed relationship and track record with Aboriginal communities in Canada. This comes from a strong commitment by Kodiak management and personnel for open and honest communications and negotiations with the Aboriginal community leaders together with – a demonstrated respect for their culture, land and residents. Kodiak's reputation has also been recognized through negotiations with regulatory agencies, resulting in several of those agreements being used as templates with other companies and projects. Our reputation has become known outside the far north of Canada.

CREEnergy Oil and Gas Inc. (CREEnergy) represented that they were the authorized agent for multiple First Nations communities. Some of these new First Nations communities are in various stages of ratification from the Federal Government of Canada to satisfy outstanding Treaty Land Entitlement (TLE) claims. Within these new First Nations are approximately 15 townships or 540 sections of mineral rights for development in Alberta.

In order to advance economic sustainability for First Nations communities that CREEnergy represented, CREEnergy searched for an oil and gas partner to develop certain oil and gas projects. Kodiak was one of the industry companies shortlisted in the search. Through discussions, meetings and negotiations since May 2008, CREEnergy selected Kodiak as their joint venture partner to develop those resource projects. The joint venture agreement between CREEnergy and Kodiak was the result of the negotiations.

In December 2008, a strategic alliance and joint venture agreement was established between CREEnergy Oil and Gas Inc. (CREEnergy) and Kodiak Energy, Inc. (Kodiak). The Agreement was built on the foundation of respect for the First Nations communities, their Heritage, their Lands and the Environment. CREEnergy has agreed to work with Kodiak to develop oil and gas reserves within their lands for the benefit of both CREEnergy and Kodiak.

To develop and strengthen the relationship with CREEnergy, Kodiak formed a subsidiary company, Cougar Energy, Inc., to focus on this relationship. As a result, Cougar Energy, Inc became the operating entity for Kodiak in Western Canada. Cougar Energy Inc subsequently became Cougar Oil and Gas Canada, Inc.

Current Status

In June of 2010 – CREEnergy defaulted on its agreements with Cougar Oil and Gas Canada, Inc. and Cougar terminated any funding at that time. Cougar had met all the commitments and terms required by the agreements and

that was acknowledged by CREEnergy but CREEnergy could not deliver the leases as promised. Cougar continued to work to find a solution with CREEnergy, but as of yearend, discussions had broken down. Once Cougar became aware of the default of CREEnergy, Cougar opened negotiations directly with the Peerless Trout First Nation directly and has continued on with that process since. We have established a good working dialogue and created employment. In the 2011 Q1 Trout 3D seismic program Cougar became a major employer of local Peerless Trout Lake First Nation contractors and labourers for the duration of that project. We continue to work with the Chief and Council toward formalizing a Joint Venture. Cougar is exploring recourse against CREEnergy to recover funds advanced for the agreements.

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• Approximately 75,000 gross acres for access and development inside the land claim

• Approximately 90,000 gross acres for development outside the land claim in identified 2 mile perimeter currently tendered as Joint Venture – Cougar 85% and operator

– Light crude and natural gas prospects  

Project Status:

• Negotiations underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.

• In Parallel - Develop Joint Venture agreement to acquire, explore, develop and operate adjacent lands to the benefit of both Cougar and the Peerless Trout First Nation – Native Joint Ventures have priority with province over other industry and thus reduced competition for a Cougar/Peerless Trout First Nation JV.  

Operating Plan – 2011/2012:

• Negotiations underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.

• In Parallel - Develop Joint Venture agreement to acquire, explore, develop and operate adjacent lands to the benefit of both Cougar and the Peerless Trout First Nation – Native Joint Ventures have priority with province over other industry and thus reduced competition for a Cougar/Peerless Trout First Nation JV.  

Operating Plan – 2011/2012:

• Explore and develop lands already identified by 2D and 3D seismic acquired - targeting Keg River light oil prospects

• Acquire additional seismic and perform drilling programs

• Execute similar maintenance programs on existing wells as Trout properties

• Acquire additional lands adjacent to the land claim in a Joint Venture structure (anticipated model is 85/15 shared ownership).

Lucy, British Columbia

Our Muskwa Shale project in the Horn River Basin of north east British Columbia has prospects for natural gas that are comparable to many of the major developments currently under way in the area. With an investment in a fracture program on the two existing wells, a development into a producing property may be possible that may show the large recoverable reserves seen in the area.

The current intention is to perform the previously planned vertical and horizontal work programs for the license). In lieu of obtaining our own financing, we are actively enlisting joint venture partners to move the project forward by way of divesting part of our interest. Monthly the Company reviews the opportunity and balances the risk versus reward, which can be adjusted depending on cash flow, commodity prices and financing. When the stability of natural gas prices over a period of time that then translates into a netback on the Lucy prospect we will look to assign capital dollars to the project. Until then there is no expiry on the lease.

Manning Heavy Oil Project

See subsequent event notes

On March 17, 2011 Cougar has entered into a two phase farm-in agreement with TAMM Oil and Gas Corporation (TAMM) which will ultimately result in Cougar earning a 50% working interest in approximately 47 sections or 30,000 acres of heavy oil prospective lands in the Manning area. This is in the same area as the heavy oil farm-in agreement previously announced by the Corporation on February 14, 2011. TAMM originally acquired these lands in 2008 and has a previously prepared independent third party estimate of 3.14 billion barrels of original oil in place for the prospect.

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The Farm-in agreement has two earning phases which will allow Cougar to become the operator and earn a 50% working interest in the prospect. The first phase of the farm-in is a work commitment to earn a 30% working interest of the TAMM prospect. The work commitment will consist of Cougar spending $2.5 million over the next 12 months on a work program consisting of seismic and drilling evaluation, and independent third party geological and project feasibility studies. Cougar will also become the operator of the project area once the first phase is completed.

The second phase of the farm-in will allow Cougar to earn an additional 20% working interest of the TAMM prospect and includes a work commitment to spend an additional $6.5 million over a 24 month period following the first phase. The work program will consist of drilling, coring, feasibility studies and updates to reserve/resource estimates.

Cougar has also continued the preparation for the Manning area heavy oil farm-ins. The geological review has included core and log analysis and detailed geological mapping. Several drilling locations have been identified and the Corporation expects to begin the permitting process for these heavy oil prospects by the end of April.

Summary

The Company plans to develop and optimize its assets in Alberta and British Columbia. Due to the strength of the crude oil commodity prices Cougar will focus on the development of the crude oil properties over natural gas. A maintenance and development program has been prepared and will be implemented, as capital is available focusing on low risk work. The Company will also continue preparing for a planned two well drilling program and nine square mile seismic program in parallel to the maintenance programs.

5. Oil and Gas Leases and Development Rights

As of December 31, 2010, we had approximately 58 leases covering approximately 15,500 gross acres in the Trout Area. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount typically ranges from 12% to 30% resulting in a 70% to 88% net revenue interest to us.

The acquisition of oil and gas leases is a very competitive process, whether they are freehold or acquired from the Province and or other oil and gas operators and involves certain geological and business risks to identify productive areas.

In the even that such identified lands are held by other operators, a transaction may be completed whereby the lands are purchased outright for the company for cash, or shares or a land exchange – or where a capital expenditure is required such as drilling or seismic where by value is added to the land holding – and thus earn a working interest in the property. In some instances the Company may earn up to 100% working interest and the assignor of such leases will reserve an overriding royalty interest, ranging from 1% to 15%, which further reduces the net revenue interest available to us.

As of December 31, 2010, approximately 65% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

In the Trout Area, Alberta as of December 31, 2010, the Company holds oil and gas leases on approximately 15,500 gross acres, of which approximately 5,500 gross acres (35%) are not currently held by production. The approximate 5,000 acres had an expiry date in the third quarter of 2015. In the event where these lands are drilled and validated, the continuation of this acreage would also be for an indefinite period.

In the Alexander Area, Alberta as of December 31, 2010, the Company oil and gas leases on approximately 160 gross acres, of which no gross acres are currently held by production. There are no expiry issues for this lease.

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In Lucy, British Columbia as of December 31, 2010, we held oil and gas leases on approximately 1,920 gross acres, of which approximately 1,920 gross acres (100%) are not currently held by production. The Lucy mineral lease was extended as part of an approved Experimental Scheme application to the regulatory agency. The Lucy lease is currently extended indefinitely.

Table I: Properties with No Attributed Reserves

The following table summarizes information with respect to the Corporation’s properties to which no reserves have been specifically attributed:

Land Holdings Without Attributed Reserves as at December 31, 2010
	Unproved Properties (Hectares)
	Gross		Net
Total Canada		3,200		3,079
Total Other Countries		0		0

There are no material work commitments on the above undeveloped land holdings.

Table II: Capitalized costs related to oil and gas producing activities

	5 months ended December 31
	2010				2009	*
Property cost – land and acquisitions	$	10,080,381		$	9,911,760
Drilling and Completions		1,403,577			7,326
Facilities		263,721			(0	)
Long lived asset in regards to asset retirement obligation		1,207,371			1,185,439
Seismic		194,174			(0	)
Total capitalized costs		13,149,224			11,104,525
Accumulated depreciation, depletion, amortization and impairment losses		(3,466,639	)		(2,276,463	)
Net capitalized costs	$	9,682,585		$	8,828,062

*Note – only includes 3 months of costs for 2009 – October to December 2009.

Table III: Cost incurred in oil and gas exploration and development

For the 5 months ended December 31, 2010, the Company incurred the following costs on properties in Canada:

Property cost
Proved Properties	$	(206,609)
Unproved Properties		2,745
Exploration Costs		227,627
Development costs		619,088
Total capitalized costs	$	642,851

	5 months ended December 31,
Table IV: Results of operations for oil and gas producing activities	2010			2009	*
Sales	$	1,380,540	$	748,270

Royalties		(202,238	)		(118,278	)
Operating expenses		(689,282	)		(422,587	)
Depreciation, depletion, amortization and impairment losses		(379,586	)		(2,237,152	)
Taxes other than income tax		(0	)		(0	)
Income before income tax		109,434			(2,029,747	)
Income tax expense		(0	)		(0	)
Results of operation from producing activities	$	109,434		$	(2,029,747	)

 * Note – only includes 3 months of revenue for 2009 – October to December 2009.

(All currency amounts in millions Cdn.)

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The results of operations for producing activities for the 5 months ended December 31, 2009 and 2010 are shown above. Revenues include sales to unaffiliated parties. All revenues reported in this table include royalties where applicable. Income taxes are based on statutory tax rates, reflecting allowable deductions and tax credits. General corporate overhead and interest income and expense are excluded from the results of operations.

Reserves Categories

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although probable and possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are, by their nature, more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized by us. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.

“Net” reserves exclude royalties and interests owned by others and reflect contractual arrangements in effect at the time of the estimate.

Estimated Reserves

The following tables presents our estimated net proved, probable and possible oil and gas reserves relating to our oil and natural gas properties as of December 31, 2010, based on our reserve reports as of such date. The data was prepared by the independent petroleum-engineering firm GLJ Petroleum Consultants Ltd. (GLJ). Reserves at December 31, 2010 were determined using the unweighted arithmetic average of the first day of the month price for each month from January 2010 through December 2010, which we refer to as the 12-month average price as of December 31, 2010, of $73.93 per barrel of oil.

Reserves

Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially

over time as a result of numerous factors such as production history, additional development activity, and continual reassessment of the viability of production under various economic and political conditions.

Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir.

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The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.

For the United States, the primary impacts of the SEC’s final rule on our reserve estimates include: The use of the unweighted 12-month average of the first-day-of-the-month reference price of $69.87 per barrel for oil compared to average consolidated revenue of $74.64 (net of transportation) per barrel received for the months of October 1, 2009 to July 31, 2010 when we had sales. A reference price of $73.93 for December 31, 2010 was used in the most recent reserve evaluation – where the Company received 79.81 USD at December 31, 2010. – thus our comments as to subjective price points and that effect on estimates and ceiling tests and resultant write downs.

The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Science Degree in Geology and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG). He has more than 25 years of experience in reservoir geology.

All reserve information in this report is based on estimates prepared by GLJ, independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at GLJ meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas by the Society of Petroleum Engineers. GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Internal Controls for Reserves Reporting

A significant component of our internal controls in our reserve estimation effort is our practice of using an independent third-party reserve engineering firm to prepare 100% of our year-end proved reserves and, for 2010, our probable and possible reserves. The qualifications of this firm are discussed below under “Independence and Qualifications of Reserve Preparer.” The Board of Directors of the Company has reviewed the reserves estimates and procedures prior to acceptance of the report. The Board of Directors has sufficient technical training and experience to review and approve the report Our internal geologist is our Vice President, Exploration and reports to our President, Operations, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to our independent third party reserve engineers to estimate our year-end

reserves. Our internal geologist staff consists of one degreed geologist, with over 25 years of diversified geological experience in the Canadian oil and gas industry, including in the Western Canadian Sedimentary Basin. He is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG).

Independence and Qualifications of Reserve Preparer

We engaged GLJ Petroleum Consultants Ltd. (GLJ), third-party reserve engineers, to prepare our reserves as of December 31, 2010 in accordance with reserves definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (COGE), the Canadian Securities Administrators National Instrument 51-101 (NI 51-101) using Forecast Pricing Assumptions and, for the SEC, using Constant Pricing Assumptions. The technical person responsible for our reserve estimates at GLJ meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth by The Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA). GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own any interest in our properties and are not employed on a contingent fee basis.

Year-end reserves quantities for the year ended December 31, 2010 shown in the following tables were calculated using the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period covered by the report. The estimated impact of changing to the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period was not significant as the Company had no reserves prior to September 30, 2009. – There were no reserves as of July 31, 2009 or 2008 and thus a comparison table is not provided.

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6. Reserve quantities information

As required under SEC Regulation S-K, reserves are those quantities of oil and gas that are estimated to be economically producible under existing economic conditions. As specified, in determining economic production, constant product reference prices have been based on a 12 month average price, calculated as the unweighted arithmetic average of the first-day-of –the-month price for each month within the 12-month period prior to the effective date of this report. In the economic analysis, operating and capital costs are those costs estimated as applicable at the effective date of the report, with no future escalation. Where deemed appropriate, the capital costs and revised operating costs associated with the implementation of committed projects designed to modify specific field operations in the future may be included in economic projections.

Table V: The estimated net proved underground oil and gas reserves and changes thereto for the year ended December 31, 2010 are shown in the following table

Company had no reserves prior to September 30, 2009. –thus a comparison table is not provided.

Company Net Proved Reserves

(Mbbl)
Location of Reserves	Crude Oil Mbbl				Natural Gas MMcf				Natural Gas Liquids Mbbl				Oil Equivalent Mbbl				Proportion Oil Eq. Reserves
Country               Region	July 31, 2010		December 31, 2010		July 31,  2010		December 31, 2010		July 31, 2010		December 31, 2010		July 31, 2010		December  31, 2010		July 31,  2010			December 31, 2010
Canada               Alberta		285		372		0		0		0		0		285		372		100	%		100	%
TOTAL Company		285		372		0		0		0		0		285		372		100%			100	%

Table VIa. The estimated net proved underground oil and gas reserves by product for the year ended July 31, 2010 are shown in the following table.

OIL AND GAS RESERVES SUMMARY July 31, 2010 (Mbbl)
	Light and Medium Oil				Heavy Oil				Natural Gas				Natural Gas Liquids				Total Oil Equivalent
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
PROVED – Developed Producing		231		202		28		25		-		-		-		-		259		227
PROVED – Developed Non Producing		63		58		-		-		-		-		-		-		63		58
PROVED – Undeveloped						-		-		-		-		-		-
TOTAL PROVED		294		260		28		25		-		-		-		-		322		285
TOTAL PROBABLE		132		120		7		5		-		-		-		-		139		125

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Table VIb. The estimated net proved underground oil and gas reserves by product for the transition period ended December 31, 2010 are shown in the following table.

OIL AND GAS RESERVES SUMMARY December 31, 2010 (Mbbl)
	Light and Medium Oil				Heavy Oil				Natural Gas				Natural Gas Liquids				Total Oil Equivalent
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
PROVED – Developed Producing		201		180		23		20		-		-		-		-		223		200
PROVED – Developed Non Producing		82		75		-		-		-		-		-		-		82		75
PROVED – Undeveloped		118		97		-		-		-		-		-		-		118		97
TOTAL PROVED		401		352		23		20		-		-		-		-		424		372
TOTAL PROBABLE		283		237		7		5		-		-		-		-		290		242

Table VII: Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of ASU 2010-03. Estimated future cash inflows from production are computed by the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period covered by the report for the year ended July 31, 2010 to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditure will be incurred and when the reserves will be produced.

The information provided does not represent management’s estimate of the Company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made for the year ended December 31, 2010 and should not be relied upon as an indication of the Company’s future cash flows or value of its oil and gas reserves. As there was no reserves or revenue as of July 31, 2009 or 2008 - no comparison tables are provided.

Table VII(a) NET PRESENT VALUE OF FUTURE NET REVENUE Based on Constant Prices and Costs December 31, 2010
Reserves	Before Income Taxes Discounted at (% Per Year) $M Cdn
Category	December 31, 2010			July 31, 2010
		10	%		10	%
PROVED – Developed producing		3,536			4,731
PROVED – Developed Non-producing		1,097			426
PROVED – Undeveloped		2,788			0
TOTAL PROVED		7,421			5,157
TOTAL PROBABLE		6,362			2,753

  Notes:

  Numbers may not add exactly due to rounding.

  Numbers are M $ Cdn as reserve reports were calculated on that basis.

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Table VII (b) STANDARDIZED MEASURE OF DISCOUNTED FURTURE NET CASH FLOWS AND CHANGES RELATED TO PROVED OIL AND GAS RESERVES Based on Constant Prices and Costs At December 31, 2010
	Total			Canada
Future Cash Inflows	$	31,223			$	37,559
Future Production and development costs	$	(22,267	)		$	(25,919	)
Future income tax expenses		-				-
Future net cash flows	$	8,956			$	8,956
10% annual discount for estimating timing of cash flows	$	(1,535	)		$	(1,535	)
Standardized measure of discounted future net cash flows	$	7,421			$	7,421
Entity’s share equity method investees standardized measure of discounted future net cash flows	$	7,421			$	7,421

Notes: 1) Constant $ Case

2) Tax not calculated on Constant $ case; Operating revenue on constant $ case lower than on market forecast case by more than taxable income in years where taxes were incurred, therefore Constant $ case would likely incur no income taxes.

Table VII (c) CHANGES IN THE STANDARDIZED MEASURE FOR DISCOUNTED CASH FLOWS FOR THE AT DECEMBER 31, 2010.

Net change in sales and transfer prices and in production(lifting) costs related to future production		n/a
Changes in estimated future development costs		n/a
Sales and transfers of oil and gas produced during the period		n/a
Net change due to extensions, discoveries, and improved recovery		n/a
Net change due to purchases and sales of minerals in place		n/a
Net change due to revisions in quantity estimates		n/a
Previously estimated development costs incurred during the period		n/a
Accretion of discount		n/a
Other – unspecified		n/a
Net change in income taxes		n/a
Aggregate change in the standardized measure of discounted future net cash flows for the year	$	-

Note: information is not available from third party engineering report as filed.

Table VIII: Production Volumes, Sales Prices and Production Costs

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The following table sets forth information regarding our Canadian oil and natural gas properties. The oil and gas production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells.

SUMMARY OF NET REVENUE

December 31, 2010 (Undiscounted)

							Capital		Well Abandonment		Future Net
					Operating		Development		and Reclamation		Revenue Before
Reserves Category	Revenue		Royalties		Costs		Costs		Costs		Future Income Tax
Proved Reserves		31,833		3,808		15,833		2,732		503		8,956
Probable Reserves		21,802		3,569		7,693		1,731		62		8,747

Notes:

Numbers may not add exactly due to rounding.

Numbers are M $ Cdn.

Table IX: Reconciliation of Company Net Reserves by Principal Product Type – Mbbl

December 31, 2010 (Mbbl)
Factors	Total Oil						Light and Medium Oil						Heavy Oil
	Proved			Probable			Proved			Probable			Proved			Probable
July 31, 2010		285			125			260			120			25			5
Production		(19	)		0			(17	)		0			(2	)		0
Dispositions		(6	)		(2	)		(6	)		(2	)		0			0

Technical Revisions	14	*	(14	)*	17	*	(14	)*	(3	)*	0	*
Infill Drilling	98	*	133	*	98	*	133	*	0	*	0	*
December 31, 2010	372		242		352		237		20		5

Note: * Numbers not available for Constant Pricing Tables -  numbers presented are company estimates based on Forecast Pricing Tables.

Numbers may not add exactly due to rounding

Table X: The following table summarizes the Company’s working interests, as at December 31, 2010, in oil and gas wells located in Canada:

SUMMARY Oil and Gas Wells December 31, 2010
	Oil Wells Gross		Oil Wells Net		Natural Gas Wells Gross		Natural Gas Wells Net		Service Wells Gross		Service Wells Net		Total Gross		Total Net
Total Canada Producing (1)		15.0		10.83		0		0		0		0		15		10.83
Total Canada Non Producing (2)		36.0		29.47		2.0		.0875		4		3.63		42		33.975

Notes:

1. Includes wells that are temporarily shut-in but which are capable of production.

2. Includes wells that are not capable of production but that are not yet abandoned

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Additional Information Concerning Abandonment and Reclamation Costs –

The Company bases its estimates for the costs of abandonment and reclamation of surface leases, wells, facilities and pipelines on previous experience of management with similar well sites and facility locations in the area. Costs for abandonment of reserve wells are included in the GLJ Report as a deduction in arriving at future net revenue. As at December 31, 2010, management expected to incur such future costs on 47.915 net wells. Within the next five financial years, it is expected such costs will total $212, 000 in respect of abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The costs used by GLJ for abandonment of reserve wells based on industry averages in the area and regulatory published estimates. Surface lease reclamation is not considered and facilities costs were deemed recoverable with salvage of the equipment.

Table XI: Company Annual Abandonment Costs (M$ CAD) – Canada Operations

December 31, 2010
	2011		2012		2013		2014		2015		12yr Total		Total to 2021 10%  discount
Proved Producing		0		0		21		24		17		233		126
Total Proved		0		0		113		74		106		503		307

Table XII: Exploration and Development Activities – Canada Operations

For the year ended December 31, 2010, the Company completed the following exploratory and development wells:

Wells	Exploratory Gross	Exploratory  Net	Development Gross	Development Net	Extension Gross	Extension Net
Oil	0	0	0	0	0	0
Gas	0	0	0	0	0	0
Service	0	0	0	0	0	0
Dry	0	0	0	0	0	0
Total	0	0	0	0	0	0

Table XII: Production Estimates

The following table discloses the total volume of production estimated by GLJ for 2011 in the estimates of future net revenue from proved reserves disclosed about under the heading “Oil Reserves and net Present Value of Future net Revenue”

	Light and Medium Oil Bbl/d	Heavy Oil Bbl/d	Natural Gas Mmf/d	Natural Gas liquids Bbl/d	BOE	Property Allocation%
Trout	414	0	0	0	690,000	95.8%
Alexander	0	26	0	0	30,000	4.2%

1. Notes: Numbers may not add exactly due to rounding

Table XIII: Costs Incurred

For the financial year ended December 31, 2010, the Corporation incurred the following costs on properties in Canada:

Costs Incurred Year Ended December 31, 2010
(Canadian Dollars)
Property Acquisition costs:
Proved Properties	151,967.66
Unproved Properties	16,735.08
Exploration costs	277,627.77
Development costs	1,626,434.93
Total	2,022,765.44

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Production History

The following tables sets forth certain information in respect of production, revenue, royalties paid by Cougar Oil and Gas Canada, Inc for each quarter of its most recently completed financial period:

Table XIV: Average Daily Production and Cumulative

Light and Medium Oil	Fiscal Q1 2010		Fiscal Q2 2010		Fiscal Q3 2010		Fiscal Q4 2010		Total for Fiscal Year ended December 31, 2010
	Daily Ave Bbl/d	Total Bbl	Daily Ave Bbl/d	Total Bbl	Daily Ave Bbl/d	Total Bbl	Daily Ave Bbl/d	Total Bbl	Total Bbl
Trout Core Area	127.5	11,475.8	182.1	16,574.7	135.0	12,424.0	111.3	10,243.3	50,717.8
Crossfield	3.1	283.3	2.2	201.4	1.3	119.0	0	0	603.7
Alexander	0	0	.5	44.1	9.3	852.8	6.5	597.3	1,494.2

Table XV: Prices Received, Royalties Paid, Production Costs and netbacks – All amounts expressed in Canadian Dollars

1. Notes: Numbers may not add exactly due to rounding

Light and Medium Oil	Fiscal Q1, 2010	Avg. Price per barrel	Fiscal Q2, 2010	Avg. Price per barrel	Fiscal Q3, 2010	Avg. Price per barrel	Fiscal Q4, 2010	Avg. Price per barrel	Total for Fiscal Year ended December 31, 2010
Revenue received	901,662	76.68	1,199,747	71.33	956,832	71.43	802,504	74.03	3,860,745
Royalties Paid	146,332	12.44	231,485	13.76	155,096	11.58	121,802	11.24	654,715
Production costs	316,361	26.90	478,686	28.46	364,435	27.21	434,589	40.29	1,594,071
Net back	438.969	37.33	489,576	29.11	437,301	32.64	246,113	22.70	1,611,959

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ITEM 19. EXHIBITS

Number	Description
3.1	Articles of Incorporation	Filed by reference to Exhibit 3.1 filed with Form F-1filed with the SEC on February 20, 2008
3.2	Articles of Amendment	Incorporated by reference to the Exhibits 3.2 filed with the Form F-1 filed with the SEC on February 20, 2008
3.3	Bylaws	Incorporated by reference to the Exhibits 3.3 filed with the Form F-1 filed with the SEC on February 20, 2008
3.4	Articles of Amendment (Name Change)	Filed by reference to Exhibit 1.1filed with Form F-6 dated February 2010
4.1	Form of Share Certificate	Incorporated by reference to the Exhibits 4.1 filed with the Form F-1 filed with the SEC on February 20, 2008
10.2	Purchase Agreement with Sword and loan agreements –	Filed by reference to 10.5 with Form K-8 filed by Kodiak Energy on October 6, 2009
10.3	Purchase Agreement with Mistahiya	filed by reference to 10.6 with Form K-8 filed by Kodiak Energy on October 6, 2009
10.4	Share purchase agreement between Registrant and Kodiak Energy, Inc	incorporated by reference to Exhibits
10.5	Code of Conduct Policy	filed by reference to 10.5 with Form 20-f filed November 24, 2010
10.6	Cougar Oil and Gas Canada, Inc Stock Option Plan	filed by reference to 10.6 with Form 20 F filed November 24, 2010
10.7	Credit line agreement with Canadian Western	filed by reference to 10.7 with Form 20-F filed November 24, 2010
10.8	Certificate of GLJ reserve evaluation	filed by reference to 10.8 with Form 20_F/A filed December 5, 2011
12.1	Certification required by Rule 13a-14(a) or Rule 15d-14(a) – Principal Executive Officer	filed by herewith
12.2	Certification required by Rule 13a-14(a) or Rule 15d-14(a) – Principal Financial Officer	filed by herewith
13.1	Certification required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350) – Principal Executive Officer	filed by herewith
13.2	Certification required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350) – Principal Financial Officer	filed by herewith

SIGNATURES

The issuer hereby certifies that it meets all 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.

COUGAR OIL AND GAS CANADA,INC.

Date: December 9, 2011	By:	/s/ William S Tighe
		Name: William S. Tighe

Title: Chairman of the Board

(Principal Executive Officer and Principal Financial Officer)

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