- Quarterly Report (10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]	QUARTERLY REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2009

OR

[ ]	TRANSITION REPORT UNDER SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to_____________

Commission file number 333 - 38558

KODIAK ENERGY, INC.

(Exact name of registrant as specified in its charter)

	Delaware		65-0967706
	(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Suite 405, 505 8th Avenue S.W. Calgary, AB T2P 1G2
(Address of principal executive offices - Zip code)

(403) 262-8044
(Registrant's telephone number, including area code)

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 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 is a large accelerated filer, and accelerated Filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large Accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer	o	Accelerated Filer	x
Non-Accelerated Filer (Do not check if a smaller reporting company)	o	Smaller Reporting Company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of The Exchange Act) Yes X No ___

APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Check whether the registrant filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes X No ___

APPLICABLE ONLY TO CORPORATE ISSUERS

State the number of shares outstanding of each of the registrant's classes of common equity, as of the latest practicable date: 110,023,998 common shares, $.001 par value, as at May 8, 2009.

Transitional Small Business Disclosure Format (Check one): Yes No X

KODIAK ENERGY, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3

ITEM 1.	FINANCIAL STATEMENTS	3

	Consolidated Balance Sheets	3

	Consolidated Statement of Shareholders’ Equity (unaudited)	4

	Consolidated Statements of Operations (unaudited)	5

	Consolidated Statements of Cash Flows (unaudited)	6

	Notes to Consolidated Financial Statements (unaudited)	7

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION	32

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42

ITEM 4.	CONTROLS AND PROCEDURES	42

PART II.	OTHER INFORMATION	44

ITEM 1.	LEGAL PROCEEDINGS	44

ITEM 1A.	RISK FACTORS	44

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	50

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	50

ITEM 5.	OTHER INFORMATION	50

ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K	50

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK ENERGY, INC.

Consolidated Balance Sheets

(Exploration Stage Company Going Concern Uncertainty – Note 1)

	March 31, 2009 (Unaudited)			December 31, 2008 (Audited)
Assets

Current Assets:
Cash and Short Term Deposits	$	5,432		$	75,175
Accounts Receivable (Note 5)		78,261			64,325
Prepaid Expenses and Deposits		98,822			106,062
		182,515			245,562

Other Assets (Note 6)		281,111			290,903

Capital Assets (Note 7):
Unproved Oil & Gas Properties Excluded From Amortization – Based on Full Cost Accounting		36,300,864			36,559,367
Property & Equipment		67,374			75,565
		36,368,238			36,634,932

Total Assets	$	36,831,864		$	37,171,397

Liabilities and Shareholders' Equity

Current Liabilities:
Accounts Payable		1,240,723			984,590
Accrued Liabilities		24,303			122,842
Note Payable to Related Party (Note 8)		18,235			32,841
		1,283,261			1,140,273

Long-term Liabilities (Note 9)		37,915			39,262

Asset Retirement Obligations (Note 10)		198,935			199,574

		1,520,111			1,379,109
Commitments and Contingencies (Note 16)

Shareholders' Equity
Share Capital (Note 13):
Authorized 300,000,000 Common Shares Par Value .001 Each and 10,000,000 Preferred Shares; Issued and Outstanding 110,023,998 Common Shares and nil Preferred Shares		110,024			110,024
Additional Paid in Capital		49,411,783			49,296,114
Other Comprehensive Loss		(5,388,829	)		(4,903,762	)
Deficit Accumulated during the Exploration Stage		(9,210,623	)		(8,710,088	)
		34,922,355			35,792,288
Minority Interest Equity (Note 12)		389,398			-
Total Shareholders' Equity		35,311,753			35,792,288

Total Liabilities and Shareholders’ Equity	$	36,831,864			37,171,397

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Shareholders’ Equity

Three Months Ended March 31, 2009

(Exploration Stage Company Going Concern Uncertainty – Note 1)

	Number of Common Shares	Amount	Additional Paid in Capital			Deficit Accumulated During the Exploration Stage			Accumulated Other Comprehensive Loss			Minority Interest	Total Shareholders’ Equity

Balance at December 31, 2008	110,023,998	110,024	$	49,296,114		$	(8,710,088	)	$	(4,903,762	)	-	$	35,792,288

Contributions												394,525		394,525
Net loss	-	-		-			(500,535	)		-		(4,062)		(500,535	)
Foreign currency translation	-	-		-			-			(485,067	)	-		(485,067	)

Comprehensive loss	-	-		-			(500,535	)		(485,067	)	-		(985,602	)

Share issue costs	-	-		(36,378	)		-			-				(36,378	)
Stock-based Compensation	-	-		152,047			-			-				152,047
Balance at March 31, 2009	110,023,998	110,024	$	49,411,783		$	(9,210,623	)	$	(5,388,829	)	389,398	$	35,311,753

(See accompanying notes to the consolidated financial statements)

Kodiak Energy Inc.

Unaudited Consolidated Statements of Operations

(Exploration Stage Company Going Concern Uncertainty – Note 1)

	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008 (Restated – Note 2)			Cumulative Since Inception April 7, 2004 to March 31, 2009


REVENUE DURING THE EVALUATION PERIOD	$	-		$	-		$	28,424

EXPENSES
Operating		1,170			274			44,931
General and Administrative		493,462			512,165			6,571,052
Stock-based Investor Relations		-			-			337,500
Depletion, Depreciation and Accretion Including Ceiling Test Impairment Write-downs		7,788			11,704			2,657,982
Interest		211			-			904,522
		502,631			524,143			10,515,987

Loss Before Other Expenses(Income)		(502,631	)		(524,143	)		(10,487,563	)

Other Expenses (Income)
Loss from valuation adjustment		-			-			25,000
Interest Income		(198	)		(56,986	)		(178,352	)
Loss on disposition of assets		2,164			-			6,309
		1,966			(56,986	)		(147,043	)
Net Loss before taxes		(504,597	)		(467,157	)		(10,340,520	)

Deferred income tax recovery		-			926,000			1,125,835

Net Income (Loss) before Minority Interest		(504,597	)		458,843			(9,214,685	)

Minority Interest		(4,062	)		-			(4,062	)

Net Loss (Earnings)	$	(500,535	)	$	458,843		$	(9,210,623	)

Basic and diluted income (loss) per share (Note 15)	$	(.005	)	$	.004

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Cash Flows

(Exploration Stage Company Going Concern Uncertainty – Note 1)

	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008 (Restated – Note 2)			Cumulative Since Inception April 7, 2004 to March 31, 2009

Operating Activities:

Net Income (Loss)	$	(500,535	)	$	458,843		$	(9,210,623	)

Adjustments to reconcile net loss to net cash used in operating activities:
Minority Interest		(4,062	)		-			(4,062	)
Depletion, Depreciation and Accretion		7,788			11,704			2,657,982
Loss on Disposal of Fixed Assets		(2,164	)		-			(2,164	)
Deferred Income Taxes (Recovery)		-			(926,000	)		(1,125,835	)
Stock-Based Investor Relations Expense		-			-			337,500
Stock-Based Compensation		152,047			190,136			1,539,376
Non-cash Interest Expense		-			-			808,811
Bad debts written off		-			-			11,908
Contributions to Capital		-			-			900
Non-Cash Working Capital Changes (Note 20)		203,075			603,464			445,789
Net Cash Provided (Used In) From Operating Activities		(143,851	)		338,147			(4,540,418	)

Investment Activities:
Additions To Capital Assets (Note 17)		236,460			(5,273,670	)		(16,551,206	)
Decrease (Increase) In Other Assets		9,792			16,031			(281,111	)
Net Cash From (Used In) Investment Activities)		246,252			(5,257,639	)		(16,832,317	)

Financing Activities:
Shares Issued and Issuable (Note 13)		(79,190	)		(123,062	)		23,768,122
Notes Payable		-			-			2,567,500
Minority Interest Contribution		393,460			-			393,460
Long term Liabilities		(1,347	)		(64,368	)		37,915
Net Cash Provided By Financing Activities		(312,923	)		(187,430	)		26,766,997

Foreign Currency Translation		(485,067	)		(79,220	)		(5,388,829	)

Net Cash Decrease		(69,743	)		(5,186,142	)		5,432

Cash beginning of period		75,175			8,983,682			-

Cash end of period	$	5,432		$	3,797,540		$	5,432

Cash is comprised of:
Balances with banks	$	5,432		$	1,842,014		$	5,432
Short-term deposits	$	-		$	1,955,526		$	-
	$	5,432		$	3,797,540		$	5,432

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 2009 and 2008

Stated in US dollars

1. ORGANIZATION, BASIS OF PRESENTATION AND GOING CONCERN UNCERTAINTY

The accompanying consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”) as at March 31, 2009 and December 31, 2008 and for the three months ended March 31, 2009 and 2008 and for the cumulative period from April 7, 2004 (inception)until March 31, 2009, and are presented in accordance with generally accepted accounting principles in the United States of America (“U. S. GAAP”).

The Company was incorporated under the laws of the state of Delaware on December 15, 1999 under the name “Island Critical Care, Corp.” with authorized common stock of 50,000,000 shares with a par value of $0.001. On December 30, 2004 the name was changed to “Kodiak Energy, Inc.” and the authorized common stock was increased to 100,000,000 shares with the same par value. On January 17, 2005 the Company affected a reverse split of 100 outstanding shares for one share. These consolidated financial statements have been prepared showing post split shares from inception. The Company was engaged in the development of the manufacture and distribution of medical instrumentation and it became inactive after the bankruptcy outlined below. During 2006, the Company increased its authorized capital to 300,000,000 common shares. In December, 2008, the Company increased its authorized capital to include 10,000,000 preferred shares.

The Company is in the exploration stage and its efforts have been principally devoted to the raising of capital, organizational infrastructure development and the acquisition of oil and gas properties for the purpose of future extraction of resources.

The information in these consolidated financial statements should be read in conjunction with December 31, 2008 consolidated financial statements.

Bankruptcy

On February 5, 2003 the Company filed a petition for bankruptcy in the District of Prince Edward Island, Division No. 01-Prince Edward Island Court No. 1713, Estate No. 51-104460, titled “Island Critical Care Corp.”. The Company emerged from bankruptcy pursuant to a Bankruptcy Court Order entered on April 7, 2004 with no remaining assets or liabilities and adopted Fresh Start Accounting.

The terms of the bankruptcy settlement included the authorization for the issuance of 150,000 post split restricted common shares in exchange for $25,000, which was paid into the bankruptcy court by the recipient of the shares.

The Company emerged from bankruptcy as an exploration stage company.

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 generated positive cash flow from operations since inception and has incurred operating losses and will need additional working capital for completion of its planned 2009 and future activities. These conditions raise substantial 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 management of the Company has developed a strategy to address this uncertainty, including additional equity and/or debt financing; however, there are no assurances that any such financing can be obtained on favorable terms, if at all. These consolidated 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. RESTATEMENT

In March, 2009, we determined that it was necessary to restate our financial statements as at December 31, 2007. The purpose of the restatement was to correct an error in measurement and an error in the application of US GAAP in the course of recording the following 2007 transactions:

Issue of common shares of the Company in consideration for the acquisition of properties.

On September 28, 2007, the Company issued to Thunder River Energy, Inc. (“Thunder”) 7,000,000 common shares of the Company as partial consideration for the acquisition of properties. The shares issued were recorded at a negotiated price per share of US$2.00 or $14,000,000. In the course of a review by the Securities and Exchange Commission (“SEC”) of the Company’s Form 10-Q for the Fiscal Quarter Ended September 30, 2007 and Form 10-K for the Fiscal Year Ended December 31, 2007, the SEC questioned the measurement date and the $2.00 per share value at which the transaction was recorded. Following an exchange of correspondence and discussions between the Company and the SEC during 2008 and 2009 regarding this issue, the Company has determined that the acquisition should have been recorded at a value per share of $2.50 or $17,500,000, which represents the fair value of exactly comparable common shares issued at the same $2.50 price per share as a private placement financing for 2,756,000 common shares which closed on September 28, 2007, the same date that the Thunder transaction closed. Management believes that the $2.50 Kodiak share price to be the most reliable measurement for the fair value of the shares issued and that September 28, 2008 to be the appropriate measurement date because that was the date when the parties’ closing conditions were satisfied and Thunder’s (the counterparty’s) performance was complete. The result of the restatement adjustment was an increase of $3,500,000 in the recorded acquisition cost and related issuance of common shares.

Issue of flow-through common shares of the Company at a premium.

On September 28, 2007, October 3, 2007 and October 30, 2007, the Company issued on a Canadian flow-through share basis 2,251,670 common shares of the Company at US$3.00 per share or $6,755,010, which amount represented a premium of $.50 per share or $1,125,835 when compared to other non-flow through shares issued at the same time at $2.50 per share. At the time of the transactions, the issues of the flow through common shares were recorded as appropriate credits to par value of common shares and additional paid in capital. Following recent discussions with the Company’s tax consultant, the Company has determined that the $1,125,835 premium on flow-through common shares issued should have, in accordance with US GAAP, been recorded as a liability at the time the shares were issued rather than as additional paid in capital. A $147,000 portion of the premium liability discharged during the period October 1, 2007 to December 31, 2007, when flow-through eligible expenditures amounting to $879,922 were incurred by the Company, was recognized as a reduction of deferred tax expense.

Effects of the restatement by line item follow:

Consolidated December 31, 2007 Balance Sheet

	As Previously			Impact
	Reported			of Errors			Restated

Cash and Short Term Deposits	$	8,983,682			-		$	8,983,682
Accounts Receivable		1,214,253			-			1,214,253
Prepaid Expenses and Deposits		90,475			-			90,475
Total current assets		10,288,410			-			10,288,410

Other Assets		359,353			-			359,353

Unproved Oil and Gas Properties		23,967,351			3,500,000			27,467,351
Furniture and Fixtures		75,654			-			75,654
Total Property, Plant and Equipment		24,043,005			3,500,000			27,543,005

Total Assets	$	34,690,768			3,500,000			38,190,768

Accounts Payable	$	1,547,273			-			1,547,273
Accrued Liabilities		755,282			-			755,282
Premium on Flow-through Shares Issued		-			978,835			978,835
Total current liabilities		2,302,555			978,835			3,281,390

Long Term Liabilities (Note 9)		110,955			-			110,955

Asset Retirement Obligations		151,814			-			151,814

Deferred Income Taxes (Note 11)		57,000			(57,000	)		-

Share Capital		106,692			-			106,692
Additional Paid in Capital		39,143,392			2,374,165			41,517,557
Other Comprehensive Loss		(342,201	)		-			(342,201	)
Deficit Accumulated during the Exploration Stage		(6,839,439	)		204,000			(6,635,439	)
Total Shareholders’ Equity		32,068,444			2,578,165			34,646,609

Total Liabilities and Shareholders’ Equity	$	34,690,768			3,500,000			38,190,768

Consolidated Statement of Operations – Year Ended December 31, 2007

	As Previously Reported			Impact of Errors			As Restated
Income During the Evaluation Period	$	225		$	-		$	225

Expenses:
Operating		20,543			-			20,543
General and Administrative		2,470,230			-			2,470,230
Stock-based Investor Relations		-						-
Depletion, Depreciation and Accretion including Ceiling Test Impairment Writedowns		218,841			-			218,841
Interest		94,083			-			94,083
		2,803,697			-			2,803,697

Loss Before Other Income		2,803,472			-			2,803,472
Interest Income		(84,809	)		-			(84,809	)

Loss before Income Taxes	$	(2,718,663	)	$	-		$	(2,718,663	)
Provision (Recovery) of Deferred Taxes		57,000			(204,000	)		(147,000	)

Net Loss		(2,775,663	)		(204,000	)		(2,571,663	)

Basic & Diluted Loss per Share	$	(0.03	)	$	-		$	(0.03	)

Consolidated Statement of Shareholders' Equity Period April 7, 2004 (Date of Inception) to December 31, 2007

	Par Value		Additional Paid in Capital		Deficit Accumulated during the Development Stage			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance December 31, 2007 as Previously Reported		106,692	$	39,143,392	$	(6,839,439	)	$	(342,201	)	$	32,068,444

Impact of Errors		-		2,374,165		204,000			-			2,578,165

Balance December 31, 2007 as Restated		106,692		41,517,557	$	(6,635,439	)	$	(342,201	)	$	34,646,609

Consolidated Statement of Cash Flow – Year Ended December 31, 2007

	As Previously Reported			Impact of Errors			As Restated
Operating Activities
Net Loss	$	(2,775,663	)	$	204,000		$	(2,571,663	)
Depletion, Depreciation and Accretion including Ceiling Test Impairment Write-downs		218,841			-			218,841
Stock-Based Compensation		643,994			-			643,994
Provision for Deferred Income Taxes		57,000			(204,000	)		(147,000	)
Bad Debts Written Off		11,908			-			11,908
Non-Cash Working Capital Changes		(660,101	)		-			(660,101	)
Net Cash Used in Operating Activities		(2,504,021	)		-			(2,504,021	)

Investing Activities
Additions to Capital Assets		(7,508,553	)		-			(7,508,553	)
Additions to Other Assets		(309,493	)		-			(309,493	)
Cash Used in Investing Activities		(7,818,046	)		-			(7,818,046	)

Financing Activities
Shares Issued and Issuable		19,068,495			-			19,068,495
Long Term Liabilities		110,955			-			110,955
Cash Provided by Financing Activities		19,179,450			-			19,179,450

Foreign Currency Translation		(321,987	)					(321,987	)
Net Change in Cash		8,535,336						8,535,336

Cash and Cash Equivalents Beginning of Year		448,346						448,346

Cash and Cash Equivalents End of Year	$	8,983, 682		$	-		$	8,983,682

Following are the effects by line item that the 2007 restatement had on the March 31, 2008 Balance Sheet and results of operations and cash flow for the Three Months Ended March 31, 2008:

Consolidated March 31, 2008 Balance Sheet

	As Previously			Impact
	Reported			of Errors			Restated

Cash and Cash Equivalents	$	3,797,540			-		$	3,797,540
Accounts Receivable		380,179			-			380,179
Prepaid Expenses and Deposits		82,058			-			82,058
Total current assets		4,259,777			-			4,259,777

Other Assets		343,322			-			343,322

Unproved Oil and Gas Properties		31,755,309			3,500,000			35,255,309
Furniture and Fixtures		74,271			-			74,271
Total Property, Plant and Equipment		31,829,580			3,500,000			35,329,580

Total Assets	$	36,432,679			3,500,000			39,932,679

Accounts Payable	$	1,435,683			-			1,435,683
Accrued Liabilities		2,951,165			-			2,951,165
Premium on Flow-through Shares Issued		-			52,835			52,835
Total current liabilities		4,386,848			52,835			4,439,683

Long Term Liabilities (Note 9)		46,587			-			46,587

Asset Retirement Obligations		239,635			-			239,635

Deferred Income Taxes (Note 11)		52,000			(52,000	)		-
		4,725,070			835			4,725,905

Share Capital		106,692			-			106,692
Additional Paid in Capital		39,323,934			2,374,165			41,698,099
Other Comprehensive Loss		(421,421	)		-			(421,421	)
Deficit Accumulated during the Exploration Stage		(7,301,596	)		1,125,000			(6,176,596	)
Total Shareholders’ Equity		31,707,609			3,499,165			35,206,774

Total Liabilities and Shareholders’ Equity	$	36,432,679			3,500,000			39,932,679

Consolidated Statement of Shareholders' Equity Period April 7, 2004 (Date of Inception) to March 31, 2008

					Deficit
					Accumulated			Accumulated
			Additional		during the			Other			Total
	Par		Paid in		Development			Comprehensive			Shareholders'
	Value		Capital		Stage			Loss			Equity

Balance March 31, 2008 as Previously Reported	$	106,692	$	39,323,934	$	(7,301,596	)	$	(421,421	)	$	31,707,609

Impact of Errors		-		2,374,165		1,125,000			-			3,499,165

Balance March 31, 2008 as Restated	$	106,692	$	41,698,099	$	(6,176,596	)	$	(421,421	)	$	35,206,774

Consolidated Statement of Operations – Three Months Ended March 31, 2008

	As Previously Reported			Impact of Errors		As Restated
Income During the Evaluation Period	$	-		$	-	$	-

Expenses:
Operating		274			-		274
General and Administrative		512,165			-		512,165
Depletion, Depreciation and Accretion		11,704			-		11,704
		524,143			-		524,143

Loss From Operations		(524,143	)		-		(524,143	)
Interest Income		56,986			-		56,986
Loss before Taxes	$	(467,157	)	$	-	$	(467,157	)
Recovery of Deferred Taxes		5,000			921,000		926,000

Net Income (Loss)		(462,157	)		921,000		458,843

Basic & Diluted Loss per Share	$	(0.004	)	$	-	$	0.004

Consolidated Statement of Cash Flow – Three Months Ended March 31, 2008

	As Previously Reported			Impact of Errors			As Restated
Operating Activities
Net Loss	$	(462,157	)	$	921,000		$	458,843
Depletion, Depreciation and Accretion including Ceiling Test Impairment Write-downs		11,704			-			11,704
Stock-Based Compensation		190,136			-			190,136
Deferred Income Tax Recovery		(5,000	)		(921,000	)		(926,000	)
Non-Cash Working Capital Changes		603,464			-			603,464
Net Cash Provided by Operating Activities		338,147			-			338,147

Investing Activities
Additions to Capital Assets		(5,273,670	)		-			(5,273,670	)
Decrease in Other Assets		16,031			-			16,031
Cash Used in Investing Activities		(5,257,639	)		-			(5,257,639	)

Financing Activities
Shares Issued and Issuable		(123,062	)		-			(123,062	)
Long Term Liabilities		(64,368	)		-			(64,368	)
Cash Used in Financing Activities		(187,430	)		-			(187,430	)

Foreign Currency Translation		(79,220	)					(79,220	)
Net Change in Cash		(5,186,142	)					(5,186,142	)

Cash and Cash Equivalents Beginning of Year		8,983,682						8,983,682

Cash and Cash Equivalents End of Year	$	3,797,540		$	-		$	3,797,540

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, Kodiak Petroleum ULC, Kodiak Petroleum (Montana), Inc., and Kodiak Petroleum (Utah), Inc. and its 93.8% owned subsidiary Cougar Energy, Inc. (formerly 1438821 Alberta Ltd.). In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All intercompany accounts and transactions have been eliminated.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with U. S. GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Although these estimates are based on the knowledge of current events and actions the Company may undertake in the future, they may ultimately differ from actual results. Included in these estimates are assumptions about allowances for valuation of deferred tax assets. Accounts receivable are stated after evaluation as to their collectability and an appropriate allowance for doubtful accounts is provided where considered necessary. The provision for asset retirement obligation, depletion and depreciation, as well as management’s impairment assessment on its oil and gas properties and other long lived assets are based on estimates and by their nature, these estimates are subject to measurement uncertainty and the effect on the consolidated financial statements of changes in these estimates, in future periods, could be significant. These estimates and assumptions are reviewed periodically and, as adjustments become necessary, they are reported in earnings in the periods in which they become known. The current economic environment has increased the degree of uncertainty in these estimates and assumptions.

Joint Venture Operations

In instances where the Company’s oil and gas activities are conducted jointly with others, the Company’s accounts reflect only its proportionate interest in such activities.

Cash and Cash Equivalents

Cash consists of balances with financial institutions and investments in money market instruments, which have terms to maturity of three months or less at time of purchase.

Oil and Gas Properties

Under the full cost method of accounting for oil and gas operations, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities. Proceeds from the sale of oil and gas properties are applied against capitalized costs with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion and depreciation in a particular country, in which case a gain or loss on disposal is recorded.

Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. Oil and gas reserves and production are converted into equivalent units on the basis of 6,000 cubic feet of natural gas to one barrel of oil. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.

An impairment loss is recognized in net earnings if the carrying amount of a cost center exceeds the “cost center ceiling”. The carrying amount of the cost center includes the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes and the cost center ceiling is the present value of the estimated future net cash flows from proved oil and natural gas reserves discounted at ten percent (net of related tax effects) plus the lower of cost or fair value of unproved properties included in the costs being amortized (and/or the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves).

Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred.

Property and Equipment

Property and equipment is recorded at cost. Depreciation of assets is provided by use of a declining balance method over the estimated useful lives of the related assets. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred.

Asset Retirement Obligations

The Company recognizes a liability for asset retirement obligations in the period in which they are incurred and in which a reasonable estimate of such costs can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites. The asset retirement obligation is measured at fair value and recorded as a liability and capitalized as part of the cost of the related long-lived asset as an asset retirement cost. The asset retirement obligation accretes until the time the asset retirement obligation is expected to settle while the asset retirement costs included in oil and gas properties are amortized using the unit-of-production method.

Amortization of asset retirement costs and accretion of the asset retirement obligation are included in depletion, depreciation and accretion. Actual asset retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded in depletion, depreciation and accretion.

Environmental

Oil and gas activities are subject to extensive federal, provincial, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. To date, the Company has not recognized any environmental obligations as production has been insignificant and we have not actively produced since October, 2006.

Income Taxes

The Company accounts for income taxes in accordance with SFAS No. 109, "Accounting for Income Taxes". Under the asset and liability method of SFAS No. 109 deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Per Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), "Accounting for Uncertainty in Income Taxes", (See Note 3) under the asset liability method, it is the Company’s policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At March 31, 2009, the Company believes it has appropriately accounted for any unrecognized tax benefits. To the extent the Company prevails in matters for which a liability for an unrecognized benefit is established or is required to pay amounts in excess of the liability, the Company’s effective tax rate in a given financial statement period may be affected. Interest and penalties associated with the Company’s tax positions are recorded as Interest Expense.

Flow-through Shares

The Company finances a portion of its Canadian exploration programs with flow-through common shares issued pursuant to certain provisions of the Income Tax Act (Canada) (the “Act”). Under the Act, where the proceeds are used for eligible expenditures, the related income tax deductions may be renounced to subscribers. Accordingly, the tax credits associated with the renunciation of such expenditures are recorded as an increase to deferred income tax liabilities. Any premium received from subscribers on the sale of such flow-through common shares is recorded initially as a current liability and then discharged and recognized as a reduction of deferred income taxes when the flow-through eligible expenditures relating to the flow-through premium are incurred by the Company.

Stock-Based Compensation

The Company records compensation in the consolidated financial statements for share based payments using the fair value method pursuant to Financial Accounting Standards Board Statement (FASB) No. 123R "Accounting for Stock-Based Compensation". The fair value of share-based compensation to employees is determined using an option pricing model at the time of grant. Fair value for common shares issued for goods or services rendered by non-employees are measured based on the fair value of the goods or services received. Stock-based compensation expense is included in general and administrative expense with a corresponding increase to Additional Paid in Capital. Upon the exercise of the stock options, consideration paid together with the previously recognized Additional Paid in Capital is recorded as an increase in share capital.

Foreign Currency Translation

The functional currency for the Company’s foreign operations is the Canadian dollar. The translation from the applicable foreign currencies to U.S. dollars is performed for balance sheet accounts using current exchange rates in effect at the balance sheet date, while income, expenses and cash flows are translated at the average exchange rates for the period. The resulting translation adjustments are recorded as a component of other comprehensive loss. Gains or losses resulting from foreign currency transactions are included in other income/expenses.

Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title passes from the Company to its petroleum and/or natural gas purchaser and collectability is reasonably assured.

Earnings/Loss Per Common Share

Basic earnings/loss per common share is computed by dividing net earnings/loss by the weighted average number of common shares outstanding for the period. Diluted earnings/loss per common share is computed after giving effect to all dilutive potential common shares that were outstanding during the period. Dilutive potential common shares consist of incremental shares issuable upon exercise of stock options and warrants, contingent stock, conversion of debentures and preferred stock outstanding. The dilutive effect of potential common shares is not considered in the earnings/loss per share calculations for these periods if the impact would have been anti-dilutive.

4. RECENT ACCOUNTING PRONOUNCEMENTS

In December 2007, FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51” (SFAS 160). This statement requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. Changes in a parent’s ownership interest that result in deconsolidation of a subsidiary will result in the recognition of a gain or loss in net income when the subsidiary is deconsolidated. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interests. For the Company, SFAS No. 160 was effective January 1, 2009. The Company has determined there was no significant impact on its consolidated results of operations, cash flows or financial position on adopting SFAS 160.

In September 2008, the EITF reached a consensus for exposure on Issue No. 08-6, “Equity Method Investment Accounting Considerations”. This issue addresses the accounting for equity method investments as a result of the accounting changes prescribed by SFAS 141(R) and SFAS 160. The issue includes clarification on the following: (a) transaction costs should be included in the initial carrying value of the equity method investment, (b) an impairment assessment of an underlying indefinite-lived intangible asset of an equity method investment need only be performed as part of any other-than-temporary impairment evaluation of the equity method investment as a whole and does not need to be performed annually, (c) the equity method investee’s issuance of shares should be accounted for as the sale of a proportionate share of the investment, which may result in a gain or loss in income, and (d) a gain or loss should not be recognized when changing the method of accounting for an investment from the equity method to the cost method. For the Company, this issue was effective January 1, 2009. The impact of this issue will not have a material effect on our consolidated financial statements.

The following new accounting standards have been issued, but have not yet been adopted by the Company:

In May 2008, FASB issued SFAS No. 162 (“SFAS No. 162”), “The Hierarchy of Generally Accepted Accounting Principles”. SFAS No. 162 identifies the sources of account principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States . SFAS No. 162 is effective 60 days following the SEC approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles.” Adoption of SFAS 162 will not be a change in the Company’s current accounting practices; therefore, it will not have a material impact on the Company’s consolidated financial condition or results of operations.

On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules change the way oil and gas companies report their reserves in the financial statements. The rules are intended to reflect changes in the oil and gas industry since the original disclosures were adopted in 1978. Definitions were updated to be consistent with Petroleum Resource Management System (PRMS). Other key revisions include a change in pricing used to prepare reserve estimates, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and significant new disclosures. The revised rules will be effective for our annual report on Form 10-K for the fiscal year ending December 31, 2009. The SEC is precluding application of the new rules in quarterly reports prior to the first annual report in which the revised disclosures are required and early adoption is not permitted. We are currently evaluating the effect the new rules will have on our financial reporting and anticipate that the following rule changes could have a significant impact on our results of operations as follows:

	•		The price used in calculating reserves will change from a single-day closing price measured on the last day of the Company’s fiscal year to a 12-month average price, and will affect our depletion and ceiling test calculations.

	•		Several reserve definitions have changed that could revise the types of reserves that will be included in our year-end reserve report.

	•		Many of our financial reporting disclosures could change as a result of the new rules.

5. ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	March 31, 2009		December 31, 2008

Non-operating Partner joint venture accounts	$	2,229	$	1,193
Operator cash call advances		-		-
Government of Canada Goods and Services Tax Claims		15,835		16,733
Other		60,197		46,399
	$	78,261	$	64,325

6. OTHER ASSETS

Other assets represent long term deposits required by regulatory authorities for environmental obligations relating to well abandonment and site restoration activities.

	March 31, 2009		December 31, 2008

Alberta Energy and Utility Board Drilling Deposit	$	71,178	$	73,507
British Columbia Oil and Gas Commission Deposit		209,933		217,396
	$	281,111	$	290,903

7. CAPITAL ASSETS

	Cost		Accumulated Depreciation and Depletion		Net Book Value March 31, 2009
Oil and Gas Properties:
Canada	$	26,959,024	$	1,915,307	$	25,043,717
United States		11,756,014		498,867		11,257,147

Sub-total		38,715,038		2,414,174		36,300,864

Furniture and Fixtures		141,113		73,739		67,374

Total	$	38,856,151	$	2,487,913	$	36,368,238

	Cost		Accumulated Depreciation and Depletion		Net Book Value December 31, 2008
Oil and Gas Properties:
Canada	$	27,244,206	$	1,935,428	$	25,308,778
United States		11,749,456		498,867		11,250,589

Sub-total	$	38,993,662		2,434,295		36,559,367

Furniture and Fixtures		148,025		72,460		75,565

Total	$	39,141,687	$	2,506,755	$	36,634,932

During the three months ended March 31, 2009, the Company has capitalized $47,104 (March 31, 2008 - $ 107,783) of general and administrative personnel costs attributable to acquisition, exploration and development activities.

Unproved Properties

Included in oil and gas properties are the following costs related to Canadian and United States unproved properties, valued at cost, that have been excluded from costs subject to depletion.

	March 31, 2009		December 31, 2008
Canada
Land acquisition and retention	$	13,725,661	$	13,767,463
Geological and geophysical costs		8,944,686		9,126,315
Exploratory drilling		2,231,861		2,270,617
Tangible equipment and facilities		53,970		55,066
Other		87,539		89,317
	$	25,043,717	$	25,308,778

United States
Land acquisition and retention	$	8,165,458	$	8,158,899
Geological and geophysical costs		941,835		941,836
Exploratory drilling				1,974,346
Tangible equipment and facilities		95,699		95,699
Other		79,809		79,809
	$	11,257,147	$	11,250,589
	$	36,300,864	$	36,559,367

Work programs are being planned for 2009 for our British Columbia and Alberta properties in Canada. Further work programs are being considered for our other unproved properties but the timing and availability of financing for those programs is uncertain. It is estimated by management that the unproved property costs associated with our Canadian properties, which in the aggregate constitutes $25,043,717 of our total unproved property costs as at March 31, 2009, will be included in costs subject to depletion during 2009 or 2010.

Ceiling Test

The Company has performed ceiling tests for its Canadian and United States Unproved Property geographical cost centers and has determined that no impairment exists as at March 31, 2009. As at December 31, 2008 and 2007, the carrying values of the Company’s unproved properties in its Canadian cost centers were assessed by management and costs attributable to certain properties were determined to be unsupportable. Consequently, ceiling test impairment write-downs as of December 31, 2008 of $284,391 (2007 - $174,380) were recorded and included in depletion, depreciation and accretion for those years. As at December 31, 2008, the carrying values of the Company’s unproved properties in its United States cost centers were assessed by management and costs attributable to certain properties were determined to be unsupportable. Consequently, ceiling test impairment write-downs as of December 31, 2008 of $498,867 was recorded and included in depletion, depreciation and accretion. No impairment existed in the United States cost center as at December 31, 2007.

8. NOTE PAYABLE TO RELATED PARTY

On November 24, 2008 the Company borrowed Cdn. $40,000 from Sicamous Oil & Gas Consultants Ltd., a company controlled by William S. Tighe, CEO, President and COO of the Company, under a terms of a demand note bearing interest at the Royal Bank of Canada prime rate plus 1% per annum. In January, 2009, a Cdn. $20,000 repayment was made and in March, 2009 a further Cdn, $3,000 advance was received leaving a balance owing as at March 31, 2009 of Cdn $23,000 or U.S. $18,235.

9. LONG TERM LIABILITIES

As at March 31, 2009, the Company held $ 37,915 (December 31, 2008 - $39,262) in funds advanced by partners for their share of a drilling deposit required to be lodged by the Company with the British Columbia Oil and Gas Commission (See Note 5) as security for future well abandonment and site restoration activities.

10. ASSET RETIREMENT OBLIGATIONS

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

Asset Retirement Obligations, December 31, 2008	$	199,574
Obligations incurred		-
Obligations retired		(3,827	)
Accretion		3,188
Asset retirement obligations, March 31, 2009	$	198,935

At March 31, 2009, the estimated total undiscounted amount required to settle the asset retirement obligations was $ 294,126 (December 31, 2008 - $302,273). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 8 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%.

11. INCOME TAXES

At March 31, 2009, the Company's deferred tax asset is attributable to its net operating loss carry forward of approximately $2,987,000 (December 31, 2008 - $2,802,000), which will expire if not utilized in the years 2024 to 2029. As reflected below, this 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.

For the periods ended March 31, 2009, March 31, 2008 and for the cumulative period April 7, 2004 (Date of Inception) to March 31, 2009, a reconciliation of income tax benefit at the U.S. federal statutory rate to income tax benefit at the Company's effective tax rates is as follows.

	2009			2008 Restated			Cumulative
Income tax benefit at statutory rate	$	(189,000	)	$	(162,000	)	$	3,718,000	)
Permanent Differences		-			-			(414,000	)
State tax benefit, net of federal taxes		-			(12,000	)		60,000
Foreign taxes, net of federal benefit		-			-			(2,532,000	)
Revision to tax account estimates		-			-			(177,000	)
Other		-			-			(2,000	)
Change in valuation allowance		189,000			174,000			(653,000	)
Deferred tax asset before the following		-			-			-
Deferred tax credit arising from flow-through share premiums		-			(926,000	)		(1,125,835	)
Deferred tax benefit at effective rate	$	-		$	(926,000	)	$	(1,125,835	)

Deferred tax assets (liabilities) at March 31, 2009 and December 31, 2008 are comprised of the following:

	2009			2008
Deferred tax assets
Deferred costs	$	-		$	-
Net operating loss carryover		2,987,000			2,802,000
Other		75,000			75,000
Total deferred tax asset		3,062,000			2,877,000

Deferred tax liabilities
Excess of U.S. tax deductions over book amounts written off		151,000			345,000

Net deferred tax asset before valuation allowance		2,911,000			2,532,000
Less valuation allowance for net deferred tax asset		(2,911,000	)		(2,532,000	)

Net deferred tax asset	$	-		$	-

The valuation allowance of $2,911,000 (2008 - $2,532,000) includes $1,882,000 (2008 -$1,691,000) relating to currency revaluation adjustments that are included in the Comprehensive Loss in Shareholders' Equity.

12. MINORITY INTEREST

Following is a summary of the interest of the minority shareholders of Cougar Energy, Inc., a controlled subsidiary of the Company and in which the Company holds a 93.8% interest as at March 31, 2009.

Private placement investments made by minority interest shareholders of Cougar during the three months ended March 31, 2009	$	393,460
Minority interest shareholders' share of loss for three months ended March 31, 2009		4,062

Due to minority interests as at March 31, 2009	$	389,398

13. SHARE CAPITAL

Authorized:

March 31, 2009 and December 31, 2008 – 300,000,000 common shares at $0.001 par value and 10,000,000 preferred shares with no par value.

The following share capital transactions occurred during the periods:

Issued	Number		Par Value		Additional Paid in Capital
Balance December 31, 2008		110,023,998	$	110,024	$	49,296,114
Share Issue Costs (a)		-		-		(36,378	)
Stock-based compensation (Note 14)		-		-		152,047
Balance March 31, 2009		110,023,998	$	110,024	$	49,411,783

(a) Share Issue Costs relate to costs of issuing common shares of the Company'scontrolled subsidiary, Cougar Energy, Inc.

The following common shares were reserved for issuance:

	Expiry Price ($)	Equivalent Shares Outstanding		Weighted Average Years to Expiry		Option Shares Vested

Stock Options (see summary below)	$ 0.69-$ 2.58		1,796,666		2.71		1,128,337
Warrants (see summary below)	$ 1.50-$ 3.50		4,893,200		1.78		-
Thunder Acquisition (Note 16)			9,000,000				-
Total Shares Reserved			15,689,866				-

Stock Option Plan

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 equally over the first three years of the term of the option.

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

	Expiry Date	Number of Options			Weighted Average Exercise Price		Total Exercise Value

Granted to five directors and one officer Oct. 23, 2006	Oct. 23/11		1,280,000		$	1.50	$	1,920,000
Cancellation of an officer’s option			(280,000	)	$	1.50		(420,000	)
Granted to an employee Dec. 1, 2006	Dec. 1/11		125,000		$	1.28		160,000
Granted to an officer Jan. 3, 2007	Jan. 3/12		280,000		$	1.29		361,200
Granted to three senior advisors Apr. 2, 2007	Apr. 12/12		300,000		$	1.75		525,000
Granted to a consultant Dec. 1, 2007	Dec. 1/12		100,000		$	2.58		258,000
Granted to an employee Mar. 24, 2008	Mar. 24/13		25,000		$	1.86		46,500
Cancellation of two senior advisors' options			(133,334 )		$	1.75		(233,333	)
Granted to two consultants and two employees Oct. 16, 2008	Oct. 16/11		100,000		$	0.69		69,000
Balance March 31, 2009			1,796,666		$	1.50		2,686,367

Warrants

During 2006, 2007 and 2008, the Company, as part of certain private placement financings, issued warrants that are exercisable in common shares of the Company. A summary of such outstanding warrants follows:

	Exercise Price		Expiry Date	Equivalent Shares Outstanding		Weighted Average Years to Expiry
Issued June 30, 2006		$2.70-$3.50	June 30/11		1,130,000		2.25
Issued May 10, 2007		$1.50	May 10/09		2,320,400		0.11
Issued October 3, 2007		$3.00	Apr. 3/09		26,800		0.01
Issued October 30, 2007		$2.50	Apr. 30/09		80,000		0.08
Issued October 30, 2007		$3.00	Apr. 30/09		4,000		0.08
Issued November 1, 2007		$2.50	May 1/09		32,000		0.08
Issued June 18, 2008		$3.50	Jun. 18/10		1,300,000		1.20
Balance March 31, 2009					4,893,200		1.01

During the three months ended March 31, 2009, warrants exercisable into 1,229,814 common shares of the Company expired unexercised.

14. STOCK-BASED COMPENSATION

In accordance with FASB No. 123R, the Company uses the Black-Scholes option pricing method to determine the fair value of each stock option granted and the amount is recognized as additional expense in the statement of operations over the vesting period of the option. The fair value of each option granted has been estimated using the following average assumptions:

	2009	2008
Risk free interest rate	2.96%	2.96-3.05%
Expected holding period	3 years	3 years
Share price volatility	75%	75%
Estimated annual common share dividend	-	-

No options were granted during the three months ended March 31, 2009. The fair value of options granted in 2008 totaled $60,600. The amount of stock-based compensation expense recorded during the three months ended March 31, 2009 is estimated to be $152,047 (December 31, 2008 – $674,226). The unvested value of options expiring during the period was $ nil (December 31, 2008 - $349,127) leaving a balance of the fair value of the options to be expensed in future periods of $422,156 (December 31, 2008 - $574,203) over a vesting period of three years.

15. EARNINGS (LOSS) PER SHARE

A reconciliation of the numerator and denominator of basic and diluted earnings (loss) per share is provided as follows:

	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008 (Restated – Note 2)

Numerator:
Numerator for basic and diluted loss per share
Net (Loss) Earnings	$	(500,535	)	$	458,843

Denominator:
Denominator for basic loss per share
Weighted average shares outstanding		110,023,998			106,692,498
In the money stock options		-			491,067
In the money warrants		-			875,965
Contingent Thunder shares		2,500,000			4,500,000

Denominator for diluted loss per share
Weighted average shares outstanding		112,523,998			112,559,530

Basic and diluted (loss) earnings per share	$	(0.005	)	$	0.004

Of the contingent shares related to the property acquisition described in note 16, only 2.5 million shares of the 11 million total contingent shares are assumed to be issued for purposes of the diluted loss per share calculations. The 6.5 million shares relating to the significant discovery and production milestones have been excluded because the effect of their inclusion would be anti-dilutive.

16. COMMITMENTS AND CONTINGENCIES

Thunder Acquisition Commitments

On September 28, 2007 the Company purchased from Thunder River Energy, Inc. (“Thunder”) certain unproved properties in Canada (Exploration License - "EL 413") and the United States (New Mexico) in consideration for cash and common shares of the Company. As part of the transaction, the Company has committed to issue, in the future, up to 9 million additional common shares of the Company upon the achievement of certain milestones in connection with the acquired properties, including 4 million shares to be issued as follows: 1 million shares upon the spudding of a shallow depth well (1,500 meters TD) by June 30, 2010; 1.5 million shares upon the spudding of a medium depth well (2,500 meters TD) before lease expiry in 2009 and 1.5 million shares upon conversion of any part of EL 413 to a Significant Discovery Lease. If, as a result of the Company’s exploration and development activities on the acquired properties, reserves in place exceed 100 million barrels, then, for each excess 10 million barrels in place, 100,000 additional shares could be issued, up to a maximum of 5 million additional shares. The purchase agreement also included a commitment of the Company to issue 2 million shares to Thunder upon the completion of a seismic program on the property by June 30, 2008. Such program was completed and in July, 2008, 2 million shares were issued to Thunder. The Company has negotiated a right to extend the license by paying rentals or performing additional work on the license area.

CREEnergy Alberta Lands Commitment

During 2008, the Company , on behalf of Cougar Energy, Inc., entered into an agreement with CREEnergy Oil & Gas Inc., under the terms of which the Company committed to exclusivity rights payments aggregating Cdn. $1 million of which $525,000 has been paid as at March 31, 2009 (December 31, 2008 - $300,000) and $50,000 subsequent to March 31, 2009.

Vehicle Lease Commitments

As of March 31, 2009 and December 31, 2008, the Company had the following vehicle lease commitments as follows:

	March 31,		December 31,
	2009		2008
Amounts payable in:
2009	$	19,575	$	26,099
2010		23,856		23,856
2011		3,172		3,172

17. FINANCIAL INSTRUMENTS

The Company, as part of its operations, carries a number of financial instruments. It is management’s opinion that the Company is not exposed to significant interest, credit or currency risks arising from these financial instruments except as otherwise disclosed.

The Company’s financial instruments, including cash and short term deposits, accounts receivable, accounts payable, accrued liabilities and related party note payable are carried at values that approximate their fair values due to their relatively short maturity periods.

18. RELATED PARTY TRANSACTIONS

During the three months ended March 31, 2009, the Company paid $24,107 (March 31, 2008 - $ 29,963), including $8,036 owing as at March 31, 2009 (December 31, 2008 - $ 9,988), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services rendered by him. Of this amount, $6,910 (March 31, 2008 - $ 13,704) was capitalized to Unproved Oil and Gas Properties and $17,197 (March 31, 2008 - $16,259) was charged to General and Administrative Expense.

During the three months ended March 31, 2009, the Company paid $38,263 (March 31, 2008 - $62,391), including $1,373 owing as at March 31, 2009 (December 31, 2008 - $30,430), to the Chief Financial Officer of the Company for services rendered by him. These amounts were charged to General and Administrative Expense.

These related party transactions were 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.

As at March 31, 2009, the Company was indebted to Sicamous Oil & Gas Consultants Ltd., a company controlled by William S. Tighe, CEO, President and COO of the Company, for a loan payable in the amount of $18,235 (Cdn. $23,000) (December 31, 2008 - $32,841 (Cdn. $40,000). (See Note 8).

As at March 31, 2009 and December 31, 2008, the Company was indebted to Segment Engineering Inc., a company controlled by Greg Juneau, a director of the Company since December, 2008, in the amount of $53,630 (Cdn. $67,644) for rent and other administrative services provided in 2008.

As at March 31, 2009 and December 31, 2008, no other amounts were owing to any related parties.

19. SEGMENTED INFORMATION

The Company’s geographical segmented information is as follows:

	Three Months Ended March 31, 2009
	U. S.		Canada		Total

Revenue during the Evaluation Period	$	-		-		-
Net Loss Before Tax		16,447		488,150		504,597
Capital Assets		11,257,147		25,111,091		36,368,238
Total Assets		11,262,603		25,569,261		36,831,864
Capital Expenditures		6,558		236,335		242,893

	Three Months Ended March 31, 2008
	U. S.		Canada		Total

Revenue during the Evaluation Period	$	-		-		-
Net Loss Before Tax (Restated – Note 2)		14,705		452,452		467,157
Capital Assets		8,810,212		23,019,368		31,829,580
Total Assets		9,367,187		27,065,492		36,432,679
Capital Expenditures		1,730,967		5,979,619		7,710,586

20. CHANGES IN NON-CASH WORKING CAPITAL

	Three Months Ended Mar. 31, 20 09			Three Months Ended Mar. 31, 2 008			Cumulative Since Inception April 7, 2004 to Mar. 31, 2009

Operating Activities:
Accounts Receivable	$	(7,006	)		648,919			(70,138	)
Prepaid Expenses and Deposits		5,896			(10,457	)		(108,863	)
Accounts Payable		308,670			21,131			581,432
Accrued Liabilities		(104,485	)		(56,129	)		18,358
Other		-			-			25,000

Total	$	203,075			603,464			445,789

Investing Activities:

The total changes in investing activities non-cash working capital accounts, which is detailed below, pertains to capital asset additions and has been included in that caption in the Statement of Cash Flow:

Accounts Receivable	$	(6,293	)	185,155		(7,486	)
Prepaid Expenses and Deposits		1,344		18,874		20,041
Accounts Payable		(19,022	)	(19,253	)	651,756
Accrued Liabilities		-		2,252,012		-

Total	$	(23,971	)	2,436,788		664,311

Financing Activities:

The total changes in financing activities non-cash working capital accounts, which is detailed below, pertains to shares issued and issuable and has been included in that caption in the Statement of Cash Flow:

Accounts Receivable	$	(637	)	-		(637	)
Prepaid Expenses and Deposits		-		-		(10,000	)
Accounts Payable		(33,515	)	(113,468	)	7,536
Accrued Liabilities		5,946		-		5,946
Due to Related Party		(14,606	)	-		18,235
Flow-through Share Premium Liability		-		-		1,125,835

Total	$	(42,812	)	(113,468	)	1,146,915

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

Forward Looking Statements

From time to time, we or our representatives have made or may make forward-looking statements, orally or in writing. Such forward-looking statements may be included in, but not limited to, press releases, oral statements made with the approval of an authorized executive officer or in various filings made by us with the Securities and Exchange Commission. Words or phrases "will likely result", "are expected to", "will continue", "is anticipated", "estimate", "project or projected", or similar expressions are intended to identify "forward-looking statements". Such statements are qualified in their entirety by reference to and are accompanied by the above discussion of certain important factors that could cause actual results to differ materially from such forward-looking statements.

Management is currently unaware of any trends or conditions other than those previously mentioned in this management's discussion and analysis that could have a material adverse effect on the Company's consolidated financial position, future results of operations, or liquidity. However, investors should also be aware of factors that could have a negative impact on the Company's prospects and the consistency of progress in the areas of revenue generation, liquidity, and generation of capital resources. These include: (i) variations in revenue, (ii) possible inability to attract investors for its equity securities or otherwise raise adequate funds from any source should the Company seek to do so, (iii) increased governmental regulation, (iv) increased competition, (v) unfavorable outcomes to litigation involving the Company or to which the Company may become a party in the future and, (vi) a very competitive and rapidly changing operating environment. The risks identified here are not all inclusive. New risk factors emerge from time to time and it is not possible for management to predict all of such risk factors, nor can it assess the impact of all such risk factors on the Company's business or the extent to which any factor or combination of factors may cause actual results to differ materially from those contained in any forward-looking statements. Accordingly, forward-looking statements should not be relied upon as a prediction of actual results.

The financial information set forth in the following discussion should be read in conjunction with management’s discussion and analysis contained in our 2008 Annual Report on Form 10-K as well as the consolidated financial statements and notes thereto included elsewhere herein.

Plan of Operation

During the quarter ended March 31, 2009, the Company has focused its efforts on financing opportunities and furthering its plans regarding its Lucy, B.C. and Cree Energy rights in Alberta. After financing is in place, which is expected to be during the second quarter of 2009, the Company plans to accelerate the aggressive development of its asset base even further as well as identify additional assets for addition to our overall land base.

The Company expects to finance its future capital expenditure programs with combinations of debt, farmouts, equity financings and some divestitures. The Company has no secured debt at this time. A description of the company’s recent and planned activities for its core properties is included below.

Kodiak Energy, Inc. is a petroleum and natural gas exploration and development company whose primary objective is to identify, acquire and develop working interests in undeveloped or underdeveloped petroleum and natural gas prospects. We are focused on prospects located in Canada and the United States. The prospects we hold are generally under leases and include partial and full working interests. In all of our core properties, Kodiak is the operator and majority interest owner. In two properties, we have the option to perform certain exploratory drilling to earn additional interests. The prospects are subject to varying royalties due to the state, province or federal governments and, in some instances, to other royalty owners in the prospect. None of our core properties are exposed to the recent Alberta Royalty Review changes.

The Company plans to engage in seismic data collection and well drilling programs on a number of prospects in which it has an interest or right to acquire percentage interests over the next two years. Drilling programs will be conducted where the seismic data supports the effort and expense and further drilling will be based on the results of the initial wells. A number of our prospects are located in the vicinity of petroleum and natural gas infrastructure, thereby providing the opportunity to tie-in to existing or planned pipelines. This will be important in lowering the overall cost of development and marketing any natural resources located in a prospect.

The Company currently has no petroleum or natural gas reserves or production. The company will begin recording revenue when production from proved reserves commences.

Core Properties

Canada

Lucy – Northern British Columbia

The Corporation is the operator and 80% working interest owner of a 1,920 acre lease located in Northeastern British Columbia. The Corporation believes the lease is situated on the southeast edge of the Horn River Basin and the Muskwa Shale gas prospect. Industry continues to show increased interest in this shale gas play with several comparisons of the Muskwa Shale gas potential as an analogue of the Barnett Shale gas potential.

The Corporation has been involved in two previous drilling operations on the lease. In the fourth quarter of 2006, Kodiak farmed in as a non-operated partner, paying 10% to earn 7.5%, on a drilling operation in the Lucy (Gunnell) area. This first drilling operation, designed to target a Middle Devonian reef prospect, had several operational problems and was unsuccessful.

After performing an internal review of seismic and drilling data, it was determined there was a seismic anomaly on the southern half of the lease. This anomaly was identified on several different seismic lines and a decision was made to drill a well on that part of the lease to evaluate both the anomaly as the primary target and the Muskwa Shale, seen in the first well but not evaluated by the operator at that time.

In the third quarter of 2007, the Corporation served partners with an independent operations notice which resulted in the Corporation increasing its working interest in the lease to 80%. In the first quarter of 2008, a second drilling operation was completed and a vertical well was cased. It was determined that the Middle Devonian seismic anomaly was not a reef buildup and the wellbore was cased due to encountering significant gas shows in the previously identified Muskwa Shale with a formation thickness of approximately sixty meters.

The Corporation submitted an application to the British Columbia Oil & Gas Commission (“OGC”) for an experimental scheme to test the Muskwa Shale gas potential. On August 12, 2008, Kodiak received the final approval of the Lucy experimental scheme application. The Corporation has prepared a multi-phase work program designed to test the deliverability of the Muskwa Shale gas formation using vertical and horizontal drilling and completion techniques. Kodiak’s proposed work program would allow for early production into a pipeline in order to monitor long-term deliverability rates and pressures of horizontal and vertical test wells on the periphery of the Horn River Basin.

These results would be some of the first commercial production results for a Horn River Basin shale gas project and would provide information that would help define the effective exploration area of the Basin and assist in the validation of adjoining properties in a divestiture process, should that occur.

Kodiak contracted an industry-recognized shale gas assessment laboratory to prepare and analyze the drill cuttings from the 2008 well in order to evaluate the Muskwa Shale interval for gas potential. The shale gas assessment is conducted by performing various tests on the rock cuttings that were obtained while drilling the well in order to determine the type, quality and amount of both adsorbed and free gas.

The most important conclusion from the drill cutting analysis is that the information received continues to support the evaluation of Kodiak’s Muskwa (Evie) Shale gas prospect. The laboratory data is consistent with other public industry and government data on the Muskwa Shale. It should also be noted that the numbers obtained on the laboratory analysis of drill cuttings may be conservative due to the nature of sampling drill cuttings on a drilling rig. Another significant point is that all three wells on the Kodiak lease, drilled deep enough to penetrate the Muskwa Shale, had elevated gas detector readings while penetrating the shales.

The prospect is still in the early stages of delineation and no assurance can be given that its exploitation will be successful. However, based on well cuttings and drilling data, Kodiak’s internal technical analysis has estimated the volume of adsorbed and free gas in the Muskwa (Evie) shales to have potential net reserves of 41 bcf per section or 123 bcf total. Based on estimated 25% recovery factor on the three sections of land, we estimate a total of 30.75 bcf recoverable contingent resources. In calculating this number, the Corporation used all of the laboratory analysis findings and wellbore information obtained during the drilling operation. For reference, this internally calculated volume is between the “best” and “high” calculations listed in the Chapman report that only had the TOC analysis and industry available data. Further appraisal work is required before these estimates can be finalized and commerciality assessed.

The current intention is to perform the following work commitments for the license (target dates are subject to change as new information becomes available):

·	Second Quarter 2009 and Third Quarter 2009 - Perforate the Muskwa intervals, perform a vertical shale gas fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to an existing pipeline approximately 1 Km from the wellhead.

·	First Quarter 2010 and Second Quarter 2010 – Drill and case a 1000 meter horizontal leg from an existing cased vertical well on the lease, perform a horizontal staged fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to pipeline.

In April, 2009, Kodiak, through its private subsidiary, Cougar, entered into a standard farmout and participation agreement with one of its partners. The partner will provide 90% of the funding for the first phase of the “Lucy” Horn River work program. Upon completion of the funding, the partner will have earned an additional 30% working interest in the wells and property. Cougar will maintain operator status and majority ownership of the project with the management of Kodiak/Cougar overseeing the execution of the work program. Upon fulfillment of the funding provisions of the farmout and participation agreement, Cougar’s working interest in the “Lucy” Horn River Basin project will be 50% with the other two partners holding 40% and 10%.

CREEnergy Lands, Alberta

On November 28, 2008, Kodiak entered into a binding letter agreement with CREEnergy Oil and Gas Inc., a company which is the authorized agent of Peerless/Trout Lake First Nation and Alberta Cree Nation, which are new First Nations in various stages of ratification from the federal Government of Canada to satisfy outstanding Treaty Land Entitlement claims. As part of the Treaty Land Entitlement settlements it is expected these new First Nations will receive approximately 15 townships or 540 sections of mineral rights for development in Alberta.

In exchange for Kodiak advancing certain contracted funds and making work program commitments, the Corporation will have an exclusive opportunity to develop certain identified oil and gas properties within the Peerless/Trout Lake First Nation and the Alberta Cree Nation. The joint venture is based on a confidential letter of intent with a term sheet and a head agreement for developing the relationship going forward. This arrangement is designed to be the stepping stone for a larger scale oil and gas development project.

Kodiak will initially have the opportunity to select up to approximately two townships (72 sections or 46,000 acres) of mineral rights from the combined Peerless/Trout Lake First Nations identified lands and Alberta Cree Nation identified lands. The leases will be for ten years, paid up with all rights. Kodiak will submit to CREEnergy a development plan for the two selected townships with a goal to begin exploration and development operations on or before November 1, 2009. CREEnergy and Kodiak will discuss terms and conditions for the development of other townships of land on or before May 1, 2010.

Little Chicago – Northwest Territories

The Company is the operator and largest working interest owner of the 201,160 acre Exploration Licen s e 413 (“EL 413”) in the Mackenzie River Valley centered along the planned Mackenzie Valley Pipeline.

In 2006, the Company signed an exploration farm-in agreement with the two 50% working interest owners of EL 413. The company reprocessed 50 km of existing seismic data in Q4 of 2006 and during the 2006-07 winter work season, the Company shot and acquired 84 km of high resolution proprietary 2D seismic and gravity survey data on the farm-out lands, thus earning a 12.5% working interest in the property. In September, 2007, the Company acquired Thunder River Energy, Inc.’s (“Thunder”) remaining 43.75% in the property giving the Company a 56.25% interest in EL 413. A letter of intent signed earlier in 2008 with the Company’s remaining partner in the project, which would have allowed Kodiak to acquire the balance of the working interest in EL 413 and become a 100% working interest owner, recently expired.

A 2007-08 43 km 2D high resolution proprietary seismic program and gravity survey was completed on the property and the results were processed and interpreted and used to support the Corporations planned drilling program. This project was completed on budget and schedule. The seismic and gravity data from the two projects show substantial structural closure and formation character and support the planning for a future multiple well drilling program. That data was included in an updated Chapman Prospective Resource report published in May, 2008.

The decision to acquire additional seismic and gravity data in the winter of 2007-08 was made to improve the potential to drill both the Devonian Bear Rock and the Basal Cambrian Sand targets f rom a common drilling site. This would substantially lower drilling costs on a per well basis and reduce the overall project risk.

Kodiak has analyzed the 2007-08 seismic data and the various reservoir indicators/lands and identified 11 drill locations . These drill locations have been selected to evaluate three primary target formations on EL 413 including the Devonian Bear Rock Oil Prospect, the Basal Cambrian Sand /Top Precambrian Oil and Gas Prospect and the Canol Oil Prospect . These locations have b een further high graded into a two phase drilling program consisting of two wells with a planned total depth of 2400 meters each targeting both the Basal Cambrian/Precambrian and the Bear Rock prospects and a m ulti-well shallow drilling program with a plan ned total depth of 400m each targeting the Canol prospect. A scouting trip was completed in the third quarter of 2008 which allowed the Corporation to review potential access routes, well sites and camp locations.

The Devonian Bear Rock Prospect (“ Bear Ro ck” ) is t he first described target and is located at a shallow depth of approximately 700 meters (2,300 ft.). This reservoir was previously identified and preliminarily evaluated in the initial Chapman Report prepared in 2005. The expected product from the reservoir is light and medium oil, with no consideration to solution gas.

The combined seismic obtained during 2007 and 2008 acknowledged a series of pools distributed throughout the project. The Chapman Report identified fifteen Bear Rock leads located along the seismic lines with five of them being selected as well defined high grade Bear Rock leads. This is an increase of 5 additional leads from the initial 2007 work program. Indicators of these potentially prolific reservoirs are present along several seismic lines that may imply these Bear Rock occurrences to be present throughout EL 413.

The additional 2008 seismic further defined a hydrocarbon trap in the Basal Cambrian Sand sitting on the top of the Precambrian. This interval, found at a depth o f approximately 2,300 meters (7,545 feet), has never been regionally penetrated and tested; however, it has been proven as a productive reservoir in the Colville Hills area approximately 125 kilometers (77 miles) east of EL 413. With this additional data , the Chapman Report identified five drilling locations that will allow the Basal Cambrian Sand and the top of the Precambrian to be drilled and tested.

Physical evidence of hydrocarbons is present with a natural surface oil seep on the northern edge of th e license area on the banks of the Mackenzie River . This natural occurrence is suggestive of a shallow oil pool, possibly in the Canol formation, and warrants further investigation. While reviewing core samples and well logs from previous regional drillin g activity. Kodiak was able to map out the Canol/Imperial formation and determine that it is the likely source of the natural surface seeps. This prospect will be found on the Northwest quarter of EL 413 and is at a very shallow depth of approximately 350 m eters (1,148 feet). The Corporation has identified 5 drilling locations which will be evaluated during a planned future project drilling program.

Kodiak is preparing for the previously mentioned drilling program and has commenced work on the necessary per mits and applications. The Corporation is working with the Sahtu and the Gwich ’ in, which are the beneficiaries of the land claims containing the EL 413 licen s e. The Corporation does not believe there will be any difficulty finishing the Access and Benefits Agreement prior to submitting the final applications to the regulators for approval. The Corporation is currently in discussions with other industry partners to share in the costs of the drilling programs, thus reducing risk and capital commitments. Fina n cing plans will be finalized when overall partnerships are established. Kodiak intends on retaining operatorship.

In addition, Kodiak has made application with regulators to extend the EL 413 license and has recently received written notification from In dian and Northern Affairs Canada that a 1 year extension is available . The licen s e extension is subject to certain terms and conditions, which Kodiak is presently reviewing for consideration.

Province/Granlea – Southeast Alberta

The Corporation purchased a 50% working interest in two sections (1280 acres gross - 640 net) of P&NG rights at a provincial land sale on September 22, 2005. In 2005, a 2D seismic program was completed on the property and in 2006, a well was drilled and completed; surface facilit i es were installed and a pipeline tie-in was completed. Production commenced in September, 2006. The well produced for a short period until excess water rates occurred and in October, 2006 the well was shut in. After the well bore was evaluated as having n o current economic production potential, the well was abandoned. An internal geological review of the prospect will be done to determine if any further drilling is warranted.

United States

New Mexico

Through its acquisition of Thunder, the Corporation acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Corporation’s land position to approximately 79 ,000 acres. These lands have potential for natural gas and CO2 and oil and helium resources at shallow depths. In 2008, the Corporation purchased 19,000 stations of gravity data and 37 miles of trade seismic data, completed a 35 mile 2D high resolution proprietary seismic program and a three well drilling program.

The three wells were drilled with air to reduce formation damage and they were cased to the base of the Yeso formation. Based on gas detector results, drill cutting samples and open hole logs, all wells showed three potential shallow porous sandstone formations capable of CO2 production with up to 200 feet of identified net pay thickness. The Yeso, Glorieta and Santa Rosa formations were perforated and flow tested to determine deliverability and pressure. There were multiple gas samples analyzed at specialized independent laboratories from two separate extended flow tests that identified CO2 concentration quality from 98.4% to 99.5%. Two of the wells were stimulated with a nitrified acid squeeze and were able to sustain an extended flow rate of approximately 375mcf/d. The shallow sands have been mapped using offset well control and the newly acquired seismic data and the Corporation has determined there is a very high likelihood of encountering the target formations throughout the leased project area; provided, however, that no assurance can be given that this will be the case.

The 35 mile 2D high resolution seismic program was completed on schedule and on budget and after reviewing the seismic data, the Company was able to effectively map out a probable long term development area which would result in CO2 production from the previously identified formations. The seismic is currently being evaluated to identify possible conventional oil and gas prospects on the leased project area.

A preliminary project feasibility study was commissioned to identify capital development costs and timelines as well as projected operating costs in order to provide information to support a large scale long-term plan of development. This information will enable the definitions for pipeline access planning and negotiation, transportation agreements, sales contracts for the CO2, additional land acquisition terms and conditions, facility engineering and construction and ultimately the parameters for financing the project development.

Several companies have expressed interest in participating in the New Mexico properties at several levels of involvement. Discussions are currently ongoing with several firms regarding potential opportunities for the project, including integration of the CO2 production into Permian Basin enhanced oil recovery projects.

Montana

During 2006, the Company, under a joint venture farmout agreement, participated in a seismic acquisition program and a two well drilling program to earn a 50% non-operating working interest in the wells and well spacing. This joint venture project provides the company with the right to participate on a 50% basis going forward on this prospect in the Hill County area of Montana. The Operator of the project had 60,000 contiguous undeveloped acres of P&NG rights in the area, as well as some excess capacity in facilities and pipelines. Two wells were drilled in the third quarter of 2006; one is cased for subsequent evaluation of the multiple zones found and one was abandoned. In order to facilitate the efficient exploration of this prospect area, the company has acquired from the original operator a 100% working interest of 12,000 acres of P&NG rights while retaining the right to participate and initiate operations on the remaining approximate 48,000 acres of prospect leases. After an internal geological review of this prospect, and in light of current commodity prices, the Company, in the fourth quarter of 2008, wrote off its drilling costs relative to this project and consideration is being given to the divestiture of the property.

Financial Condition and Changes in Financial Condition

(All dollar values are expressed in United States dollars unless otherwise stated)

The Company’s ability to raise funds has been severely impacted by the global collapse of credit and equity markets. However, the Company is confident that it will be able to obtain financing that will enable it to regain momentum in furthering its exploration and development plans for the second half of 2009.

The Company’s total assets of $36,831,864 as at March 31, 2009 are relatively unchanged from $36,634,932 as at December 31, 2008 and $38,190,768 as at December 31, 2007. Total assets consist of cash and other current assets of $182,515 (December 31, 2008 - $245,562); unproved oil and gas properties and equipment of $36,368,238 (December 31, 2008 - $36,634,932); and other assets of $281,111 (December 31, 2008 - $290,903). Our total current liabilities were $1,283,261 (December 31, 2008 - $1,140,273) and consisted of accounts payable and accrued liabilities relating to general and administrative costs and some capital expenditures incurred. We had long term liabilities of $37,915 (December 31, 2008 - $39,262), and asset retirement obligations of $198,935 (December 31, 2008 - $199,574). Shareholders’ equity amounted to $34,922,355 (December 31, 2008 - $35,792,288), net of an accumulated deficit of $9,210,623 (December 31, 2008 - $8,710,088) and other comprehensive loss consisting mainly of foreign currency translation losses of $5,388,829 (December 31, 2008 - $4,903,762), and minority interest equity of $389,398 (December 31, 2008 - $ nil) relating to the 6.2% interest held by minority shareholders in Cougar.

Overall Operating Results

In the three months ended March 31, 2009 and March 31, 2008, the Company had no income and operating costs of $1,170 (2008 - $274) relating to its Granlea, Alberta property which well watered out in late 2006 and was deemed uneconomic. Except for that small amount of production, the Company remains in the exploratory and development stage.

Net Loss for the three months ended March 31, 2009 totalled $500,535 (2008 - $458,843 as restated) In addition to the operating results noted above, these losses consist of general and administrative expenses of $493,462 (2008 - $512,165), including stock-based compensation expense amounting to $152,047 (2008 - $190,136); depletion, depreciation and accretion of $ 7,788 (2008 - $11,704) and interest of $211 (2008 $ nil).

General and administrative expenses include the cost of employed and consulting personnel and others who provided investor relations services, public company costs for SEC reporting compliance, accounting, audit and legal fees and other general and administrative office expenses. General and administrative expense also includes stock-based compensation relating to the cost of stock options granted to directors, officers, employees and other personnel. General and administrative costs are being minimized during periods of low activity but will be expected to increase in the future as the scope of the company’s activities increase.

Depletion, depreciation and accretion includes the cost of depreciation relating to office furniture and equipment in the three months ended March 31, 2009 and 2008. All of the remaining capitalized costs relate to Canadian and United States unproven properties and have been excluded from depletable cost pools for ceiling test purposes.

Interest income of $56,898 in the three months ended March 31, 2008 was derived from the investment of excess cash balances on a short-term basis. Deferred income tax recovery of $926,000 in the 2008 period represents a deferred tax credit arising from the expenditure of funds during the quarter relating to the premium received on the issue of Canadian flow-through shares in 2007. The Minority interest credit of $4,062 represents the Cougar minority shareholders’ 6.2% share of the net loss for the 2009 first quarter during the portion of the quarter that the minority interests were issued and outstanding.

Capital Expenditures:

Capital Expenditures incurred by the Company during the three months ended March 31, 2009 and 2008 are set out below.

	2009		2008
Land acquisition and carrying costs	$	238,877	$	605,931
Geological and geophysical		83		4,112,993
Intangible drilling and completion		6,454		2,934,748
Tangible completion and facilities		1,036		56,914

Total Capital Costs Incurred	$	246,450	$	7,710,586

Land acquisition and carrying costs for the 2009 quarter include exclusivity rights payments in connection with our Cree Energy agreement and other land retention costs while the 2008 quarter costs include New Mexico land acquisitions and other land retention costs.

Geological and geophysical costs include the costs of the seismic programs carried out on the EL 413 Little Chicago, North West Territory and New Mexico projects in 2008.

Intangible drilling and completion costs for 2008 include the Company’s 57% share of the drilling of the second Lucy well in British Columbia and 100% of the three well New Mexico program.

Liquidity and Capital Resources:

Since inception to March 31, 2009, the company’s operations have been financed from the sale of securities and loans from shareholders. The working capital deficiency at March 31, 2009 amounted to $1,100,746 (December 31, 2008 - $894,711). The Company is currently in the final negotiation stages with European financing sources that will, when closed, provide sufficient funds to enable the Company to cover this working capital deficiency and fund additional 2009 activities.

The Corporation currently has no long term debt obligations.

The Company is seeking and is confident it will obtain additional financing, either through debt, equity or a combination thereof to cover the estimated cost of its planned programs for the balance of 2009 and into 2010. In addition, we may require funds for additional acquisitions. In the event that additional capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Corporation.

There is uncertainty that 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 generated positive cash flow from operations since inception and has incurred operating losses and will need additional working capital for its future planned activities. 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 additional equity and debt financing; however, there are no assurances that any such financings can be obtained on favorable terms, if at all. These consolidated 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Company is exposed to market risk from changes in petroleum and natural gas and related hydrocarbon prices, foreign currency exchange rates and interest rates.

Petroleum and Natural gas and Related Hydrocarbon Prices

The Company currently has no petroleum and natural gas and related hydrocarbon reserves or production so the Company therefore has no current exposure related to the instability of prices of such commodities. However; the prices of these commodities are unstable and are subject to fluctuation, due to factors outside of the Company’s control, including war, weather, the availability of alternate fuel and transportation interruption and any material decline in these commodity prices could have an adverse impact on the economic viability of the Company’s exploration projects.

Foreign Currency Exchange Rates

The Company, operating in both the United States and Canada, faces exposure to adverse movements in foreign currency exchange rates. These exposures may change over time as business practices evolve and could materially impact the Company’s financial results in the future. To the extent revenues and expenditures denominated in other currencies vary from their U. S. dollar equivalents, the Company is exposed to exchange rate risk. The Company can also be exposed to the extent revenues in one currency do not equal expenditures in the same currency. The Company is not currently using exchange rate derivatives to manage exchange rate risks.

Interest Rates

The Company’s interest income and interest expense, in part, is sensitive to the general level of interest rates in North America. The Company is not currently using interest rate derivatives to manage interest rate risks.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this report. They concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were adequate and effective in ensuring that material information relating to the Company would be made known to them by others within those entities, particularly during the period in which this report was being prepared. Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and in reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

Internal Control over Financial Reporting

2007 Restatement

During the process of preparing the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2008, it was determined that it may be necessary to restate our consolidated financial statements for the Fiscal Quarter Ended September 30, 2007 and the Fiscal Year Ended December 31, 2007. The restatements would be required to correct for an error in measurement and an error in the application of U.S. generally accepted accounting principles (“US GAAP”) in recording two September, 2007 transactions as described in Note 2 to our unaudited consolidated financial statements.

After discussing these matters with other management, the CFO recommended to the Audit Committee that previously reported financial results be restated to reflect correction of these errors. The Audit Committee agreed with this recommendation. Pursuant to the recommendation of the Audit Committee, the Board of Directors determined at its meeting on March 13, 2009, that previously reported results for the Company be restated. On March 27, 2009, amended consolidated financial statements for the above noted periods were filed.

Both of these errors resulted from the Company not seeking appropriate external advice regarding the accounting of certain transactions that were complex and not subject to routine accounting principles. One error was in measuring the appropriate date at which common shares of the Company were issued in consideration for the acquisition of unproved oil and gas properties, an arm’s length transaction that was negotiated over a period of several months during 2007 but not finally closed until September 28, 2007, at which date the common shares were issued. The second error was in the application of US GAAP in the accounting for the complexities involved relating to premium proceeds received on the issue of Canadian flow-through shares, a Canadian income tax concept not in practice in the United States. These errors demonstrated a material weakness relating to the segregation of duties among financial and accounting personnel and a need to engage additional personnel or seek outside advice where appropriate to strengthen internal control over financial reporting.

Remediation of Weakness in Internal Control Over Financial Reporting

The Company will endeavor to engage outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and compliance with US GAAP. Beginning in 2008, the Company engaged an outside consulting firm to assist in income tax planning and compliance and beginning with our fiscal year ended December 31, 2008, to review our Canadian and U.S. income tax provisions.

As at March 31, 2009 and December 31, 2008, the Company continues to have a material weakness in internal control over financial reporting, relating to the segregation of duties among certain personnel. Management believes that without engaging additional personnel, estimated to cost a minimum of approximately $150,000 per annum, we cannot remedy such material weakness. Management believes such expenditures cannot be justified at this time when the Company is still in the exploratory stage of operations and has no proved reserves, production or cash flow. When sufficient cash flow is being generated, management will review its position. Management believes its controls and procedures related to its financial and corporate information systems are appropriate for a company of its size and mandate and due to its internal expertise, it is not dependent upon the inherent risks in external third party management of such systems.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is not presently a party to any litigation.

ITEM 1A. RISK FACTORS

Going Concern Uncertainty

There is uncertainty that 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 generated positive cash flow since inception and has incurred operating losses and will need additional working capital for its future planned activities. Additional financing will be required by mid 2009. 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 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.

Financial Markets Instability and Uncertainty

The 2008-09 worldwide financial and credit crisis has reduced the availability of capital and credit to fund the continuation and expansion of industrial business operations worldwide. The shortage of capital and credit combined with recent substantial losses in worldwide equity markets has led to an extended worldwide economic recession. The slowdown in economic activity caused by this recession is reducing worldwide demand for energy and resulting in lower oil and natural gas and other commodity prices. A prolonged reduction in oil and natural gas prices will depress the immediate levels of exploration, development and production activity. That is impacting negatively on our Company’s ability to raise capital to finance our ongoing capital projects. The Company may be required to consider divestiture of some properties or working interests to raise funds. Until the financial market conditions improve, we will face significant challenges in meeting our ongoing financial obligations. This global financial crisis may have impacts on our business and financial condition that we currently cannot predict.

The Oil and Gas Industry Is Highly Competitive

The oil & gas industry is highly competitive. We compete with oil and natural gas companies and other individual producers and operators, many of which have longer operating histories and substantially greater financial and other resources than we do. We compete with companies in other industries supplying energy, fuel and other needs to consumers. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices of gas and oil more easily than we can. Our competitors may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.

Government and Environmental Regulation

Our business is governed by numerous laws and regulations at various levels of government. These laws and regulations govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. The laws and regulations may, among other potential consequences, require that we acquire permits before commencing drilling, restrict the substances that can be released into the environment with drilling and production activities, limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas, require that reclamation measures be taken to prevent pollution from former operations, require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediation of contaminated soil and groundwater, and require remedial measures to be taken with respect to property designated as a contaminated site.

Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages as well as environmental damage that occurs over time. However, we do not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost. Accordingly, we could be liable, or could be required to cease production on properties, if environmental damage occurs.

The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur that may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.

The Successful Implementation Of Our Business Plan Is Subject To Risks Inherent In The Oil & Gas Business.

Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs will be charged against earnings as impairments.

We Expect Our Operating Expenses To Increase Substantially In The Future And May Need To Raise Additional Funds.

We have a history of net losses and expect that we expect to incur additional our operating expenses over the next 12 months as we continue to implement our business plan. In addition, we may experience a material decrease in liquidity due to unforeseen expenses or other events and uncertainties. As a result, we may need to raise additional funds, and such funds may not be available on favourable terms, if at all. If we cannot raise funds on acceptable terms, we may not be able to execute on our business plan, take advantage of future opportunities or respond to competitive pressures or unanticipated requirements. This may seriously harm our business, financial condition and results of operations.

We Are An Exploration Stage Company Implementing A New Business Plan.

We are an exploration stage company with only a limited operating history upon which to base an evaluation of our current business and future prospects, and we have just begun to implement our business plan. Since our inception, we have suffered recurring losses from operations and have been dependent on new investment to sustain our operations. During the three months ended March 31, 2009 and the years ended December 31, 2008, 2007, 2006 and 2005, we reported losses of $500,535, $2,074,649, $2,571,663 (Restated), 2,867,374 and 1,133,790 respectively. In addition, our consolidated financial statements for the years ended December 31, 2008, 2007, 2006 and 2005 contained a going concern qualification and we cannot give any assurances that we can achieve profits from operations.

Our Ability To Produce Sufficient Quantities Of Oil & Gas From Our Properties May Be Adversely Affected By A Number Of Factors Outside Of Our Control.

The business of exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil wells involves the risk that the wells may be unproductive or that, although productive, that the wells may not produce oil or gas in economic quantities. Other hazards, such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic due to pressure depletion, water encroachment, mechanical difficulties, etc, which impair or prevent the production of oil and/or gas from the well.

There can be no assurance that oil and gas will be produced from the properties in which we have interests. In addition, the marketability of any oil and gas that we acquire or discover may be influenced by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. We cannot predict how these factors may affect our business.

In addition, the success of our business is dependent upon the efforts of various third parties that we do not control. We rely upon various companies to assist us in identifying desirable oil and gas prospects to acquire and to provide us with technical assistance and services. We also rely upon the services of geologists, geophysicists, chemists, engineers and other scientists to explore and analyze oil prospects to determine a method in which the oil prospects may be developed in a cost-effective manner. In addition, we rely upon the owners and operators of oil drilling equipment to drill and develop our prospects to production. Although we have developed relationships with a number of third-party service providers, we cannot assure that we will be able to continue to rely on such persons. If any of these relationships with third-party service providers are terminated or are unavailable on commercially acceptable terms, we may not be able to execute our business plan.

Market Fluctuations In The Prices Of Oil & Gas Could Adversely Affect Our Business.

Prices for oil and natural gas tend to fluctuate significantly in response to factors beyond our control. These factors include, but are not limited to actions of the Organization of Petroleum Exporting Countries and its maintenance of production constraints, the U.S. economic environment, weather conditions, the availability of alternate fuel sources, transportation interruption, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that could limit future drilling activities for the industry.

Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in charges to earnings due to impairment.

Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation of projects. We expect that commodity prices will continue to fluctuate significantly in the future.

Risks Of Penny Stock Investing

The Company's common stock is considered to be a "penny stock" because it meets one or more of the definitions in the Exchange Act Rule 3a51-1, a Rule made effective on July 15, 1992. These include but are not limited to the following:(i) the stock trades at a price less than five dollars ($5.00) per share; (ii) it is NOT traded on a "recognized" national exchange; (iii) it is NOT quoted on the NASD's automated quotation system (NASDAQ), or even if so, has a price less than five dollars ($5.00) per share; OR (iv) is issued by a company with net tangible assets less than $2,000,000, if in business more than three years continuously, or $5,000,000, if in business less than a continuous three years, or with average revenues of less than $6,000,000 for the past three years. The principal result or effect of being designated a "penny stock" is that securities broker-dealers cannot recommend the stock but must trade in it on an unsolicited basis.

Risks Related To Broker-Dealer Requirements Involving Penny Stocks / Risks Affecting Trading And Liquidity

Section 15(g) of the Securities Exchange Act of 1934, as amended, and Rule 15g-2 promulgated there under by the Commission require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor's account. These rules may have the effect of reducing the level of trading activity in the secondary market, if and when one develops.

Potential investors in the Company's common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be "penny stock." Moreover, Commission Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor's financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in the Company's stock to resell their shares to third parties or to otherwise dispose of them in the market or otherwise.

Our controls and procedures have not been effective and we have restated our financial statements.

In the fiscal years 2007 and 2008, management has identified issues concerning the effectiveness of our controls and procedures. As a result, it has been determined that they have not been effective. One of the results has been the need to restate the unaudited and audited financial statements for certain periods in 2005 through 2008. The financial statements as originally filed for those periods should not be relied upon.

The company will take measures to remediate the failures in effectiveness of the controls and procedures. Currently, the company has plans for certain actions, but they will take time to implement because of their cost. There can be no assurance when remediation will be complete, if at all. Therefore, future reports may have statements indicating that the Company’s controls and procedures are not effective. Additionally, future financial statements may have to be restated if as a result of the ineffectiveness of controls and procedures the statements are inaccurate.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Item 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

EXHIBITS

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

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

32.1 - Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

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