- 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 September 30, 2009

[ ] 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, 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 o (Do not check if a smaller reporting company)	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 No X

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: 110,407,186 common shares, $.001 par value, as at November 6, 2009

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	39

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54

ITEM 4.	CONTROLS AND PROCEDURES	55


PART II.	OTHER INFORMATION	57

ITEM 1.	LEGAL PROCEEDINGS	57

ITEM 1A.	RISK FACTORS	57

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	62

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	62

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	62

ITEM 5.	OTHER INFORMATION	62

ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K	64

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK ENERGY, INC.
Consolidated Balance Sheets
(Exploration Stage Company Going Concern Uncertainty – Note 1)

	September			December
	30, 2009			31, 2008
	(Unaudited)			(Audited)
Assets

Current Assets:
Cash and Short Term Deposits	$	5,878		$	75,175
Accounts Receivable (Note 5)		408,856			64,325
Prepaid Expenses and Deposits		131,510			106,062
		546,244			245,562

Other Assets (Note 6)		290,197			290,903

Capital Assets (Note 7):
Oil and gas properties - Based on Full Cost Accounting		32,745,658			36,559,367
Property & Equipment		68,471			75,565
		32,814,129			36,634,932


Total Assets	$	33,650,570		$	37,171,397


Liabilities and Shareholders' Equity

Current Liabilities:
Accounts Payable	$	1,485,373			984,590
Accrued Liabilities		67,268			122,842
Loan Payable (Note 8)		1,260,857			-
Current Portion of Long-term Debt (Note 11)		803,213			-
Note Payable to Related Party (Note 9)		-			32,841
Advances (Note 10)		1,030,819			-
		4,647,530			1,140,273

Long-term Liabilities (Note 11)		3,911,293			39,262

Asset Retirement Obligations (Note 12)		1,020,772			199,574

		9,579,595			1,379,109
Commitments and Contingencies (Note 17)
Subsequent events (Note 22)

Shareholders' Equity
Share Capital (Note 14):
Preferred Shares - 10,000,000 authorized; nil issued and outstanding Common Shares - 300,000,000 authorized; 110,407,186 issued and outstanding at September 30,2009 and 110,023,998 at December 31, 2008		110,407			110,024
Additional Paid in Capital		49,939,374			49,296,114
Other Comprehensive Gain (Loss)		237,624			(4,903,762	)
Deficit Accumulated during the Exploration Stage		(26,585,756	)		(8,710,088	)
		23,701,649			35,792,288
Non Controlling Interest Equity (Note 14)		369,326			-
Total Shareholders’ Equity		24,070,975			35,792,288

Total Liabilities and Shareholders’ Equity	$	33,650,570			37,171,397

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Shareholders’ Equity

Nine Months Ended September 30, 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			Non Controlling 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		-		-		-		-			-			416,192			416,192
Net loss		-		-		-		(17,875,668	)		-			(46,866	)		(17,922,534	)
Foreign currency translation		-		-		-		-			5,141,386						5,141,386
Comprehensive gain (loss)		-		-		-		(17,875,668	)		5,141,386			(46,866	)		(12,781,148	)
Common shares issued		383,188		383		154,574		-			-						154,957
Stock-based Compensation		-		-		488,686		-			-			-			488,686
Balance at September 30, 2009		110,407,186	$	110,407	$	49,939,374	$	(26,585,756	)	$	237,624		$	369,326		$	24,070,975

(See accompanying notes to the consolidated financial statements )

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Operations

(Exploration Stage Company Going Concern Uncertainty – Note 1)

													Cumulative
	Three Months Ended			Three Months Ended			Nine Months Ended			Nine Months Ended			Since Inception
	September 30, 2009			September 30, 2008			September 30, 2009			September 30, 2008			Apr. 7, 2004 to
				(Restated – Note 2)						(Restated – Note 2)			September 30, 2009

INCOME DURING THE EVALUATION PERIOD	$	-		$	-		$	-		$	46		$	28,424

EXPENSES
Operating		4,621			3,590			6,793			8,863			50,554

General and Administrative		658,871			550,822			1,506,760			1,620,905			7,586,350
Stock-based Investor Relations		-			-			-			-			337,500
Depletion, Depreciation and Accretion Including Ceiling Test Impairment Write-downs		363,156			16,441			16,405,480			41,718			19,055,674
Interest		-			-			304			1,257			904,615
		1,026,648			570,853			17,921,337			1,672,743			27,934,693
Loss Before Other Expenses		(1,026,648	)		(570,853	)		(17,921,337	)		(1,672,697	)		(27,906,269	)
Other Expenses (Income)
Loss from valuation adjustment		-			-			-			-			(25,000	)
Loss on disposition of assets		-			-			(2,164	)		-			(6,309	)
Interest Income		44			12,239			967			73,739			179,121
		44			(12,239	)		(1,197	)		(73,749	)		147,812
Net Loss before taxes		(1,026,604	)		(558,614	)		(17,922,534	)		(1,598,958	)		(27,758,457	)
Deferred Income Taxes (Recovery)		-			(28,835	)		-			(978,835	)		(1,125,835	)
Net Loss before Non Controlling Interest		(1,026,604	)		(587,449	)		(17,922,534	)		(620,123	)		(26,632,622	)
Non Controlling Interest		31,024			-			46,866			-			46,866
NET LOSS	$	(995,580	)	$	(587,449	)	$	(17,875,668	)	$	(620,123	)	$	(26,585,756	)

(See accompanying notes to the consolidated financial statements)

Loss per share data (Note 16)

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Cash Flows

(Exploration Stage Company Going Concern Uncertainty – Note 1)

	Three Months Ended September 30, 2009			Three Months Ended September 30, 2008 (Restated – Note 2)			Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2008 (Restated – Note 2)			Cumulative Since Inception April 7, 2004 to September 30, 2009
Operating Activities:
Net Loss	$	(995,580	)	$	(587,449	)	$	(17,875,668	)		(620,123	)		(26,585,756	)
Adjustments to reconcile net loss to net cash used in operating activities:
Non Controlling Interest		(31,024	)		-			(46,866	)		-			(46,866	)
Depletion, Depreciation and Accretion Including Ceiling Test Impairment Write-downs		363,156			16,441			16,405,480			41,718			19,055,674
Non-cash Interest Expense		-			-			-			-			808,811
Stock-Based Investor Relations Expense		-			-			-			-			337,500
Stock-Based Compensation		193,967			152,185			488,686			507,790			1,876,015
Deferred Income Taxes (Recovery)		-			(28,835	)		-			(978,835	)		(1,125,835	)
Loss on disposition of fixed assets		-			-			2,164			-			2,164
Bad Debts Written Off		-			-			-			-			11,908
Contributions to Capital		-			-			-			-			900
Non-Cash Working Capital Changes (Note 21)		(7,060	)		219,897			196,015			836,234			438,729
Net Cash Used In Operating Activities		(476,541	)		(170,091	)		(830,189	)		(213,216	)		(5,226,756	)

Investment Activities:
Additions To Capital Assets		(1,190,292	)		(420,613	)		(1,584,478	)		(11,277,874	)		(22,476,169	)
Dispositions (Additions) Of Other Assets		14,999			13,878			706			26,928			(290,197	)
Net Cash Used In Investment Activities		(1,175,293	)		(406,735	)		(1,583,772	)		(11,250,946	)		(22,766,366	)

Financing Activities:
Shares Issued and Issuable		(90,109	)		(78,726	)		(188,757	)		2,695,396			23,658,555
Proceeds from Note Payable		-			-			-			-			3,300,000
Repayment of Note Payable		-			-			-			-			(732,500	)
Advances Received on Financing		557,929			-			1,030,819			-			1,030,819
Loan Payable		1,260,857			-			1,260,857			-			1,260,857
Non Controlling Interest Contribution		(147	)		-			416,192			-			416,192
Long term liabilities		3,528			(1,961	)		5,402			(66,018	)		44,664
Net Cash Provided By (Used in) Financing Activities		1,732,058			(80,687	)		2,524,513			2,629,378			28,978,587

Foreign Currency Translation		(137,604	)		25,229			(179,849	)		(94,041	)		(979,586	)

Net Cash Increase (Decrease)		446			(682,742	)		(69,297	)		(8,928,825	)		5,878

Cash beginning of period		5,432			737,599			75,175			8,983,682			-

Cash end of period	$	5,878		$	54,857		$	5,878		$	54,857		$	5,878

Interest Paid	$	-		$	-		$	304		$	1,257		$	95,340
Taxes Paid	$	-		$	-		$	-		$	-		$	-

Cash is comprised of:
Balances with banks	$	5,878		$	54,857		$	5,878		$	54,857		$	5,878

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

For the Nine Months Ended September 30, 2009 and 2008

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 September 30, 2009 and December 31, 2008 and for the three and nine month periods ended September 30, 2009 and 2008 and for the cumulative period from April 7, 2004 (inception) until September 30, 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, manufacture and distribution of medical instrumentation and became inactive after the bankruptcy outlined below. During 2006, the Company increased its authorized capital to 300,000,000 common shares and in December, 2008 increased its authorized capital to include 10,000,000 preferred shares.

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.

Since the Company emerged from bankruptcy, it has been an exploration stage company and its efforts have been principally devoted to the raising of capital, organizational infrastructure development, the acquisition of oil and gas properties and the initial stages of exploration to establish reserves for the purpose of future extraction of resources.

With the commencement of production from the properties acquired September 30, 2009 and October, 2009, the Company will no longer be an exploration stage company and will begin recognizing revenue and results of operations effective October, 2009.

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

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. From inception to September 30, 2009, the Company has incurred operating losses and has not generated any positive cash flow. The Company has a current working capital deficiency and will need additional working capital for future development and exploration and to enable it to repay its debt. The Company is currently in the process of arranging certain equity and longer term financing that will reduce its working capital deficiency and provide additional funding of near term development programs that are planned to significantly increase production, revenue and cash flow over the next nine months. It is contemplated that these transactions will completed before yearend. 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. If successful, management's plans, including additional equity and/or debt financing, will address this uncertainty; however, there are no assurances that any such financing can be obtained on favorable terms, if at all, or that the Company will generate positive cash flow. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.

2. 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 $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, 2007 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 $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		110,955			-			110,955

Asset Retirement Obligations		151,814			-			151,814

Deferred Income Taxes		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 and 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	$	41,517,560	$	(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			-			-
Non-Cash Working Capital Changes		(660,101	)		-			(660,101	)
Net Cash Used in Operating Activities		(2,504,081	)		-			(2,504,081	)

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 Cash Increase		8,535,336						8,535,336

Cash Beginning of Year		448,346						448,346

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

Following are the effects by line item that the 2007 restatement had on the September 30, 2008 Balance Sheet and results of operations and cash flow for the Three and Nine Months Ended September 30, 2008:

Consolidated September 30, 2008 Balance Sheet

	As Previously			Impact
	Reported			of Errors			Restated

Cash and Short Term Deposits	$	54,857			-		$	54,857
Accounts Receivable		1,010,428 -			1,010,428
Prepaid Expenses and Deposits		91,897			-			91,897
Total current assets		1,157,182			-			1,157,182

Other Assets		332,425			-			332,425

Unproved Oil and Gas Properties		38,267,882		$	3,500,000			41,767,882
Furniture and Fixtures		80,392			-			80,392
Total Property, Plant and Equipment		38,348,274			3,500,000			41,848,274

Total Assets	$	39,837,881		$	3,500,000		$	43,337,881

Accounts Payable	$	1,391,054			-		$	1,391,054
Accrued Liabilities		142,027			-			142,027
Total current liabilities		1,533,081			-			1,533,081

Long Term Liabilities		44,397			-			44,397

Asset Retirement Obligations		210,764			-			210,764

Deferred Income Taxes		52,000		$	(52,000	)		-
		1,840,782			(52,000	)		1,788,782

Share Capital		110,024			-			110,024
Additional Paid in Capital		46,756,714			2,374,165			49,130,879
Other Comprehensive Loss		(436,242	)		-			(436,242	)
Deficit Accumulated during the Exploration Stage		(8,433,397	)		1,177,835			(7,255,562	)
Total Shareholders’ Equity		37,997,099			3,552,000			41,549,099

Total Liabilities and Shareholders’ Equity	$	39,837,881		$	3,500,000		$	43,337,881

Consolidated Statement of Shareholders' Equity Period April 7, 2004 (Date of Inception) to September 30, 2008

	Par Value		Additional Paid in Capital		DeficitAccumulated during the Development Stage			Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance September 30, 2008 as Previously Reported		110,024	$	46,756,714	$	(8,433,397	)	$	(436,242	)	$	37,997,099

Impact of Errors		-		2,374,165		1,177,835			-			3,552,000

Balance June 30, 2008 as Restated		110,024	$	49,130,879	$	(7,255,562	)	$	(436,242	)	$	41,549,099

Consolidated Statement of Operations – Three Months Ended September 30, 2008

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

Expenses:
Operating	$	3,590			-		$	3,590
General and Administrative		550,822			-			550,822
Depletion, Depreciation and Accretion		16,441			-			16,441
Interest		-			-			-
		570,853			-			570,853
Loss Before Other Income		(570,853	)		-			(570,853	)
Interest Income		(12,239	)		-			(12,239	)
Loss before Taxes		(558,614	)		-			(558,614	)
Recovery of Deferred Taxes		-		$	(28,835	)		(28,835	)
Net Income (Loss)	$	(558,614	)	$	(28,835	)	$	(587,449	)

Basic & Diluted Loss per Share	$	(0.01	)	$	-		$	(0.01	)

Consolidated Statement of Cash Flow – Three Months Ended September 30, 2008

	As Previously Reported			Impact of Errors			As Restated
Operating Activities
Net Loss	$	(558,614	)	$	(28,835	)	$	(587,449	)
Depletion, Depreciation and Accretion including Ceiling Test Impairment Write-downs		16,441			-			16,441
Stock-Based Compensation		152,185			-			152,185
Deferred Income Tax Recovery		-			28,835			28,835
Non-Cash Working Capital Changes		219,897			-			219,897
Net Cash Used in Operating Activities		(170,091	)		-			(170,091	)

Investing Activities
Additions to Capital Assets		(420,613	)		-			(420,613	)
(Increase) Decrease in Other Assets		13,878			-			13,878
Cash Used in Investing Activities		(406,735	)		-			(406,735	)

Financing Activities
Shares Issued and Issuable		(78,726	)		-			(78,726	)
Long Term Liabilities		(1,961	)		-			(1,961	)
Cash Provided by Financing Activities		(80,687	)		-			(80,687	)

Foreign Currency Translation		25,229			-			25,229
Net Cash Increase		(682,742	)		-			(682,742	)

Cash Beginning of Period		737,599			-			737,599

Cash End of Period	$	54,857		$	-		$	54,857

Consolidated Statement of Operations – Nine Months Ended September 30, 2008

	As Previously Reported			Impact of Errors			As Restated
Income During the Evaluation Period	$	46			-		$	46

Expenses:
Operating		8,863			-			8,863
General and Administrative		1,620,905			-			1,620,905
Depletion, Depreciation and Accretion		41,718			-			41,718
Interest		1,257			-			1,257
		1,672,743			-			1,672,743
Loss Before Other Income		(1,672,697	)		-			(1,672,697	)
Interest Income		73,739			-			(73,739	)
Loss before Taxes		(1,598,958	)		-			(1,598,958	)
Recovery of Deferred Taxes		(5,000	)	$	(973,835	)		(978,835	)
Net Income (Loss)	$	(1,593,958	)	$	(973,835	)	$	(620,123	)

Basic & Diluted Loss per Share	$	(0.01	)	$	-		$	(0.00	)

Consolidated Statement of Cash Flow – Nine Months Ended September 30, 2008

	As Previously Reported			Impact of Errors			As Restated
Operating Activities
Net Loss	$	(1,593,958	)	$	973,835		$	(620,123	)
Depletion, Depreciation and Accretion including Ceiling Test Impairment Write-downs		41,718			-			41,718
Stock-Based Compensation		507,790			-			507,790
Deferred Income Tax Recovery		(5,000	)		(973,835	)		(978,835	)
Non-Cash Working Capital Changes		836,234			-			836,234
Net Cash Used in Operating Activities		(213,216	)		-			(213,216	)

Investing Activities
Additions to Capital Assets		(11,277,874	)		-			(11,277,874	)
Decrease in Other Assets		26,928			-			26,928
Cash Used in Investing Activities		(11,250,946	)		-			(11,250,946	)

Financing Activities
Shares Issued and Issuable		2,695,396			-			2,695,396
Long Term Liabilities		(66,018	)		-			(66,018	)
Cash Provided by Financing Activities		2,629,378			-			2,629,378

Foreign Currency Translation		(94,041	)					(94,041	)
Net Cash Increase		(8,928,825	)					(8,928,825	)

Cash Beginning of Period		8,983,682						8,983,682

Cash End of Period	$	54,857		$	-		$	54,857

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Kodiak Petroleum ULC, Kodiak Petroleum (Montana), Inc., Kodiak Petroleum (Utah), Inc. and its 93.6% 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 US 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, 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 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 Short Term Deposits

Cash and short term deposits 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. 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 using a separate test 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 Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 740 "Income Taxes". Under the asset and liability method, 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 FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”, under the asset and 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 September 30, 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 expense in the consolidated financial statements for share based payments using the fair value method pursuant to FASB ASC 718 "Stock Compensation". The fair value of share-based compensation to employees and other personnel will be 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 income. 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 deliverability occurs and title passes from the Company to its petroleum and/or natural gas purchaser under documented business arrangements at fixed or determinable prices and collectability is reasonably assured. The Company acquired proved reserves as of September 30, 2009 and will begin recognizing revenues from those properties as at October 1, 2009.

Loss Per Common Share

Basic loss per common share is computed by dividing net loss by the weighted average number of common shares outstanding for the period. Diluted 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 EPS 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 adopted the presentation and disclosure requirements as recommended.

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-life 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 did not have a material effect on our consolidated financial statements.

In May 2009, the FASB issued SFAS 165, Subsequent Events . This standard establishes general standards of accounting for and disclosure of events that occur after the balance sheet date, but before financial statements are issued or available to be issued. Specifically, this standard codifies in authoritative GAAP standards the subsequent event guidance that was previously located in auditing standards. SFAS 165 is effective for fiscal years and interim periods ended after June 15, 2009 and is applied prospectively. We have adopted SFAS 165 in the fiscal quarter ending June 30, 2009. The adoption of SFAS 165 did not have a material impact on our financial position, results of operation or cash flows.

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

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 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.

In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162” (“SFAS No. 168”), to establish the codification as the source of authoritative accounting principles in the preparation of financial statements in conformity with GAAP. All guidance contained in the codification carries an equal level of authority. SFAS No. 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009 and will not have an effect on the Company’s consolidated financial statements.

In June 2009, the FASB issued SFAS 167, Amendments to FASB Interpretation No. 46(R) . This standard changes the consolidation analysis for variable interest entities. SFAS 167 is effective for fiscal years ending after November 15, 2009. We are currently assessing the impact, if any, that the adoption of SFAS 167 will have on our financial position, results of operations or cash flows.

5. ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	September		December
	30, 2009		31, 2008

Non-operating partner joint venture accounts	$	4,113	$	1,193
Government of Canada Goods and Services Tax Claims		55,052		16,733
Administrative Recoveries Receivable		79,870		46,399
Amount due from Ionic Capital Corp. (Notes 8 and 22)		269,821		-
	$	408,856	$	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.

	September		December
		30, 2009		31, 2008

Alberta Energy and Utility Board Drilling Deposit	$	42,893	$	73,507
British Columbia Oil and Gas Commission Deposit		247,304		217,396

	$	290,197	$	290,903

7. CAPITAL ASSETS

	Cost		Accumulated Depreciation and Depletion		Net Book Value September 30, 2009

Oil and Gas Properties:

Canada	$	38,853,964	$	17,381,713	$	21,472,251
United States		11,772,274		498,867		11,273,407

Sub-total		50,626,238		17,880,580		32,745,658

Furniture and Fixtures		164,409		95,938		68,471

Total	$	50,790,647	$	17,976,518	$	32,814,129

	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 nine months ended September 30, 2009, the Company has capitalized $144,841 (September 30, 2008 - $ 267,030) of general and administrative personnel costs attributable to acquisition, exploration and development activities.

Property Acquisition

On September 30, 2009, Cougar acquired from an unrelated private company certain wells, facilities and producing operations in and adjacent to the CREEnergy Project in Alberta, Canada. The purchase price of the acquisition was $5,604,000 of which $934,000 was paid at closing. The non-interest bearing balance of $4,670,000 is payable in accordance with the terms set out in Note 11 Long-term Liabilities.

The cost of the acquisition is comprised of the following:

Land and producing properties	$	4,483,200
Geophysical seismic data		233,500
Tangible Facilities		887,300
		5,604,000
Asset retirement obligations acquired		798,077
	$	4,805,923

Full Cost Accounting Ceiling Test on Canadian Proved Oil and Gas Properties

At September 30, 2009, a ceiling test was performed on the company's newly acquired Canadian cost center properties subject to depletion in which the net present value of future cash flows from the properties discounted at 10% and using period end pricing was compared to the carrying cost of the properties. Costs of unproved properties aggregating $14,492,857 has been excluded from costs subject to depletion. This test disclosed that the carrying costs of the Company's depletable Canadian properties exceeded their net present value by $354,286 and consequently a ceiling test write-down of that amount has been recorded in the third quarter. This shortfall resulted from the inclusion in the recognized cost of the acquired properties of $711,290 attributable to a premium paid for the properties in consideration for the vendor carrying $4,669,842 as non-interest bearing debt repayable as set out in Note 11.

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.

	September		December
	30, 2009		31, 2008
Canada
Land acquisition and retention	$	1,351,563	$	16,046,580
Geological and geophysical costs		10,531,403		10,580,753
Exploratory drilling		2,292,111		2,906,031
Tangible equipment and facilities		53,970		219,914
Other		98,755		34,784
Currency revaluation		165,055		(4,479,284	)
	$	14,492,857	$	25,308,778

United States
Land acquisition and retention	$	8,168,134	$	8,158,899
Geological and geophysical costs		937,924		941,836
Exploratory drilling		1,991,841		1,974,346
Tangible equipment and facilities		95,699		95,699
Other		79,809		79,809
	$	11,273,407	$	11,250,589

	$	25,766,264	$	36,559,367

In Canada, a stimulation and horizontal drilling program is planned for our British Columbia property during the next year. In the United States, an initial seismic and drilling program has been conducted on our New Mexico property with additional drilling to follow. These planned activities, when completed, will enable the Company to evaluate the economic viability of these properties.

Unproved Properties Impairment Test

The Company has performed impairment tests for its unproved properties in its Canadian and United States geographical cost centers as at September 30, 2009. No impairment existed in its cost centers as at that date. In the second quarter of 2009, it was determined that, due to poor current economic factors regarding exploration and development in that part of Canada, an allowance for impairment was required for its Canadian cost center with respect to the Company's Little Chicago EL413 Exploration License in the N.W.T. of Canada. Consequently an allowance for impairment amounting to $16,035,774 was recorded in the second quarter of 2009 relating to the Company's cumulative capitalized land costs for the EL 413.

As at December 31, 2008, the carrying value of the Company’s unproved properties in its Canadian and United States cost centers were assessed by management and costs attributable to certain unproved properties were determined to be unsupportable. Consequently, impairment write-down as of December 31, 2008 of $284,391 and $498,867 for the Canadian and U.S cost centers, respectively, were recorded and included in depletion, depreciation and accretion for 2008.

8. LOAN PAYABLE

On September 30, 2009, the Company entered into a loan agreement with Ionic Capital Corp. ("Ionic"), under the terms of which Ionic loaned $1,260,857 to the Company to enable it to close the property acquisition described in Note 7. As at September 30, 2009, $991,036 had been received and the remaining $269,821 was recorded in accounts receivable (See Note 5). The Ionic indebtedness bears interest at the rate of 12% per annum payable monthly in arrears and is repayable at any time up to but no later than June 30, 2010. As additional financing consideration for the loan, the Company agreed to issue common shares of the Company based on the 10% discount to the closing trading price on September 27, 2009 that equated to 12% of the principal amount of the financing or $151,303. The 383,188 common shares of the Company that were issued to satisfy that obligation were recorded at a value of $187,762 based on the closing market price of the Company’s common shares on September 30, 2009. ((See Note 14 (b)).

9. NOTE PAYABLE TO RELATED PARTY

On November 24, 2008 the Company borrowed Cdn. $37,915 from Sicamous Oil & Gas Consultants Ltd., a company controlled by William S. Tighe, CEO, President and COO of the Company, under the terms of a demand note bearing interest at the Royal Bank of Canada prime rate plus 1% per annum. Following is a summary of transactions regarding this related party indebtedness:

Advance received November, 2008	$	37,915
Currency revaluation adjustment December 31, 2008		(5,074	)
Balance December 31, 2008		32,841
Repayment January, 2009		(15,857	)
Advance March, 2009		2,378
Repayment June, 2009		(19,362	)
Balance at September 30, 2009	$ Nil

10. ADVANCES

On June 17, 2009, the Company announced that Cougar had concluded strategic long term financing arrangements with a Swiss Private Equity Fund ("the Fund") focused on the Energy Sector to develop its CREEnergy Joint Venture and other properties located in Western Canada. Key components of the Cougar financing package include:

1. Cdn. $1,400,000 in equity financing via a private placement of Cougar common shares at a price of $1.21 per common share;

2. Arrangement by the fund of a non-dilutive $4,670,000 development debt financing;

3. A $700,000 payment by the fund to Cougar to acquire the heavy oil rights on an equal basis with Cougar plus a 10% working interest in the conventional oil and gas opportunities when Cougar completes the nomination and leasing of the CREEnergy properties. The Fund will be responsible for its share of all exploration and development costs following closing.

Negotiations are still being conducted to finalize these financing arrangements and it is anticipated that final agreement will be reached during the fourth quarter of 2009. If the proposed financing is fully drawn, Kodiak’s current 93.6% interest in Cougar will be reduced to approximately 81%.

During the nine months ended September 30, 2009, the Company received $1,030,819 from the Fund as advances toward their obligations under these arrangements. (See Note 22).

11. LONG TERM LIABILITIES

The Company has the following long-term liabilities:

	September		December
		30, 2009		31, 2008
Amount due to vendor of acquired properties (See Note 7)
Present Value of Total Amount Due	$	3,958,552		-
Amount of Discount to be accreted in the future (at 7.5% annually - .0625% per month)		711,290		-
Total Amount Due	$	4,669,842		-
Current portion		803,213		-
Long-term portion		3,866,629		-

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 6) as security for future well abandonment and site restoration activities		44,664		39,262

Total	$	3,911,293		39,262

The total amount due to the vendor of the acquired properties is payable in accordance with the following schedule:

Due January 1, 2010	$	280,200
Due in 2010 in 11 monthly instalments		719,180
Due in 2011 in 12 monthly instalments		952,680
Due in 2012 in 12 monthly instalments		1,120,800
Due in 2013 in 12 monthly instalments		1,288,920
Due in 2014 in 2 monthly instalments		242,840
Due March 1, 2014		65,222
	$	4,669,842

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

12. 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
Currency Translation Adjustment		15,527
Obligations acquired (Note 7)		798,077
Obligations settled		(2,372	)
Accretion		9,966
Asset retirement obligations, September 30, 2009	$	1,020,772

At September 30, 2009, the estimated total undiscounted amount required to settle the asset retirement obligations was $ 2,386,969 (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%.

13. DEFERRED INCOME TAXES

At September 30, 2009, the Company's deferred tax asset attributable to its net operating loss carry forward is approximately $3,357,000 (December 31, 2008 - $2,802,000) and 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 nine month periods ended September 30, 2009 and 2008 and for the cumulative period April 7, 2004 (Date of Inception) to September 30, 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 – Note 2)			Cumulative
Income tax benefit at statutory rate	$	(6,768,000	)	$	534,000		$	(2,861,000	)
Permanent Differences		-			-			(414,000	)
State tax benefit, net of federal taxes		-			217,000			60,000
Foreign taxes, net of federal benefit		-			-			(2,532,000	)
Revision to tax account estimates		-			-			(177,000	)
Other		(5,000	)		-			(7,000	)
Change in valuation allowance		6,773,000			(751,000	)		5,931,000
Deferred tax asset before the following		-			-			-
Deferred tax credit arising from flow-through share premiums		-			(973,835	)		(1,125,835	)
Deferred tax benefit at effective rate	$	-			(973,835	)	$	(1,125,835	)

Deferred tax assets (liabilities) at September 30, 2009 and December 31, 2008 are comprised of the following:

	2009			2008
Deferred tax assets
Capital assets	$	3,547,000		$	-
Net operating loss carryover		3,357,000			2,802,000
Other		386,000			75,000
Total deferred tax asset		7,290,000			2,877,000

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

Net deferred tax asset before valuation allowance		7,290,000			2,532,000
Less valuation allowance for net deferred tax asset		(7,290,000	)		(2,532,000	)

Net deferred tax asset	$	-		$	-

The change in the valuation allowance of $4,758,000 is net of $2,015,000 relating to currency revaluation adjustments that are included in the Comprehensive Loss in Shareholders' Equity.

14. SHARE CAPITAL AND ADDITIONAL PAID IN CAPITAL

Authorized:

September 30, 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)		-		-		(32,805	)
Shares Issued September 30, 2009 (b)		383,188		383		187,379
Stock-based compensation (Note 15)		-		-		488,686
Balance September 30, 2009		110,407,186	$	110,407	$	49,939,374

	(a)	During the nine months ended September 30, 2009, $32,805 in costs were incurred in connection with the issue of 575,317 common shares of Cougar pursuant to private placement subscriptions for shares.

	(b)	As additional financing consideration for the loan payable described in Note 8, the Company agreed to issue common shares of the Company based on the 10% discount to the closing trading price on September 27, 2009 that equated to 12% of the principal amount of the financing or $151,303. The 383,188 common shares of the Company that were issued to satisfy that obligation were recorded at a value of $187,762 based on the closing market price of the Company’s common shares on September 30, 2009.

The following common shares were reserved for issuance:

	Exercise Price ($)		Equivalent Shares Outstanding		Weighted Average Years to Expiry		Option Shares Vested
Stock Options (see below)		0.28-2.58		5,960,000		4.06		4,864,996
Warrants (see below)		3.50		2,430,000		1.19		-
Total Shares Reserved				8,390,000				-

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 and outstanding under the plan is as follows:

	Expiry Date	Number of Option Shares			Weighted Average Exercise Price		Total Value

Granted to five directors and one officer Oct. 23, 2006	Oct. 23/11		1,280,000		$	1.50	$	1,920,000
Cancellation of one 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 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
Granted to two consultants and two employees Oct. 16, 2008			100,000		$	0.69		69,000
Granted to three directors, two directors/officers, two officers, two employees and two consultants June 24, 2009	Mar 24/14		4,330,000		$	0.28		1,212,400
Balance September 30, 2009			5,960,000		$	0.61	$	3,607,100

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		3.50	Jun. 30/11		1,130,000		1.75
Issued June 18, 2008		3.50	Jun. 18/10		1,300,000		0.70

Balance September 30, 2009					2,430,000		1.19

During the nine months ended September 30, 2009, warrants exercisable into 3,693,014 common shares of the Company expired unexercised.

Non Controlling Interest

Following is a summary of the interest of the non controlling shareholders of Cougar:

Private placement investments made by non controlling shareholders of Cougar during the nine months ended September 30, 2009	$	416,192
Non controlling interest shareholders' share of loss for nine months ended September 30, 2009		(46,866	)

Due to non controlling interests as at September 30, 2009	$	369,326

Cougar Stock Option Plan

Cougar 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 and outstanding under the plan is as follows:

	Expiry Date	Number of Option Shares		Weighted Average Exercise Price ($Cdn.)		Total Value ($Cdn.)

Granted to three directors and two officers January 14, 2009	Jan. 14/14		675,000	$	0.65	$	438,750
Granted to two consultants	Jan. 14/14		50,000	$	0.65		32,500
Granted to one consultant	Jan. 14/12		25,000	$	0.65		16,250
Balance September 30, 2009			750,000	$	0.65	$	487,500

15. STOCK-BASED COMPENSATION

In accordance with FASB ASC 718, 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 earnings 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	1.89-2.57%	2.96-3.05%
Expected holding period	3 years	3 years
Share price volatility	100%	75%
Estimated annual common share dividend	-	-

A summary of the consolidated unvested value of options granted and outstanding under the plans is as follows:

	Nine Months Ended Sept. 30, 2009			Nine Months Ended Sep. 30 2008

Value of unvested options beginning of the period	$	574,203		$	1,536,957
Value of options granted	$	1,021,980		$	23,750
Value of options expensed	$	(488,686	)	$	(507,790	)
Value of options expired	$	(44,974	)	$	(359,534	)
Value of unvested options end of period	$	1,062,523		$	693,363

16. NET LOSS PER SHARE

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

	Three Months Ended September 30, 2009			Three Months Ended September 30, 2008 (Restated – Note 2)			Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2008 (Restated – Note 2)

Numerator:
Numerator for basic and diluted loss per share
Net Loss	$	(995,580	)	$	(587,449	)	$	(17,875,668	)	$	(620,123	)

Denominator:
Denominator for basic loss per share
Weighted average shares outstanding		110,028,163			109,632,694			110,025,402			107,734,253
In the money stock options		2,122,365			213,851			533,283			523,472
In the money warrants		-			368,953			-			1,018,356
Contingent Thunder shares		-			2,500,000			-			2,500,000

Denominator for diluted loss per share
Weighted average shares outstanding		112,150,528			112,715,498			110,558,684			111,776,081

Basic and diluted loss per share	$	(0.01	)	$	(0.01	)	$	(0.16	)	$	(0.01	)

The contingent shares issuable related to the 2007 property acquisition described in note 16 have been reduced to nil due to the unlikelihood that the Company will complete a drilling program on the property prior to the NWT EL 413 Exploration License expiry on September 17, 2010.

17. COMMITMENTS AND CONTINGENCIES

Thunder Acquisition Commitments

On September 28, 2007 the Company purchased from Thunder River Energy, Inc. (“Thunder”) certain properties in Canada (Exploration License 413 – “EL 413”) and the United States in consideration for cash and common shares of the Company. As part of the transaction, the Company committed to issue up to 11 million additional common shares of the Company upon the achievement of certain milestones in connection with the acquired properties, including 6 million shares to be issued as follows: 2 million shares upon completion of a 2007/08 seismic program for which such shares were issued in July, 2008; 1 million shares upon the spudding of a shallow depth well (1,500 meters TD) by March 31, 2009; 1.5 million shares upon the spudding of a medium depth well (2,500 meters TD) before license expiry in 2009 and 1.5 million shares upon conversion of any part of EL 413 to a Significant Discovery Lease. During the third quarter of 2009, a right to extend the license term one year from September 17, 2009 upon the payment of license rentals was obtained. Due to the decline in the economic prospects for the area due to ongoing pipeline delays, commodity prices being significantly below levels required to justify commercial development of proved reserves and the inability to carry out a drilling program prior to expiry of the current extended license on September 17, 2010, the obligation to issue any additional contingent shares has terminated.

Vehicle Lease Commitments

As of September 30, 2009 and December 31, 2008, the Company had the following vehicle lease commitments as follows:

	September 30,		December 31,
	2009		2008
Amounts payable in:
2009	$	7,423	$	26,099
2010		27,139		23,856
2011		3,608		3,172

18. 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, accounts receivable, accounts payable, accrued liabilities and long term debt are carried at values that approximate their fair values due to their relatively short maturity periods.

19. RELATED PARTY TRANSACTIONS

For the nine months ended September 30, 2009, the Company paid $45,014 (2008 - $Nil) to Sicamous Oil & Gas Consultants Ltd. (“Sicamous”), a company controlled by William S. Tighe, CEO, President and COO of the Company for consulting services rendered by him. Of this amount, $18,509 was payable as at September 30, 2009 (2008 - $ Nil). These amounts were charged to General and Administrative Expense.

During the nine months ended September 30, 2009, the Company received loans from Sicamous aggregating $36,066 for which repayments were made $17,831in March 2009 and the balance of $18,235 in June 2009. (See Note 8.)

For the nine months ended September 30, 2009, the Company paid $24,107 (2008 – $88,435), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services. Of this amount, $15,967 was payable as at September 30, 2009 (2008 – $ Nil) and of this amount, $6,910 (2008 - $ 39,394) was capitalized to Unproved Oil and Gas Properties and $17,197 (2008 - $49,041) was charged to General and Administrative Expense.

For the nine months ended September 30, 2009, the Company paid $92,106 (2008 - $143,426) to the Chief Financial Officer. Of this amount, $23,588 was payable as at September 30, 2009 (2008 - $6,043). These amounts were charged to General and Administrative Expense.

As at September 30, 2009 and December 31, 2008, included in accounts payable was an amount owing to Segment Engineering Inc., a company controlled by Greg Juneau, a director of the Company in the amount of $53,630 for rent and other administrative services provided in 2008.

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

As at September 30, 2009 and December 31, 2008, no other amounts were owing to any related parties.

20. SEGMENTED INFORMATION

The Company’s geographical segmented information is as follows:

	Three Months Ended September 30, 2009									Nine Months Ended September 30, 2009
	U. S.			Canada			Total			U. S.			Canada			Total
Income during the Evaluation Period		-			-			-			-			-			-
Net Loss	$	(10,015	)	$	(985,565	)	$	(995,580	)	$	(31,091	)	$	(17,844,577	)	$	(17,875,668	)
Capital Assets		11,273,407			21,472,251			32,814,129			11,273,407			21,472,251			32,814,129
Total Assets		11,275,783			22,374,787			33,650,570			11,275,783			22,374,787			33,650,570
Capital Expenditures		(3,912	)		6,520,148			6,516,236			22,818			7,235,959			7,258,777

	Three Months Ended September 30, 2008									Nine Months Ended September 30, 2008
	U. S.			Canada			Total			U. S.		Canada			Total
Income during the Evaluation Period		-			-			-			-	$	46		$	46
Net Income (Loss)	$	(6,300	)	$	(581,149	)	$	(587,449	)	$	14,540		(634,663	)		(620,123	)
Capital Assets		11,740,716			40,107,558			41,848,274			11,740,716		40,107,558			41,848,274
Total Assets		11,746,538			31,591,343			43,337,881			11,746,538		31,591,343			43,337,881
Capital Expenditures		1,494,722			6,752,371			8,247,093			4,661,471		13,122,796			17,784,267

21. CHANGES IN NON-CASH WORKING CAPITAL

	Three Months Ended September 30, 2009			Three Months Ended September 30, 2008 (Restated - Note 2)			Nine Months Ended September 30, 2009			Nine Months Ended September 30, 2008 (Restated - Note 2)			Cumulative Since Inception April 7, 2004 to September 30, 2009

Operating Activities:
Accounts Receivable	$	(12,536	)	$	(5,314	)	$	(19,542	)	$	623,448		$	(82,674	)
Prepaid Expenses and Deposits		(21,808	)		18,426			(15,912)			2,573			(130,671	)
Accounts Payable		1,722			209,446			310,392			263,807			583,154
Accrued Liabilities		25,562			(2,661	)		(78,923	)		(53,594	)		43,920
Other		-			-			-			-			25,000

Total	$	(7,060	)	$	219,897		$	196,015		$	836,234		$	438,729

Investing Activities:

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

Accounts Receivable	$	(48,874	)	174,504		(55,167	)	(419,623	)	(56,360	)
Prepaid Expenses and Deposits		(10,880	)	12,818		(9,536	)	(3,995	)	9,161
Accounts Payable		250,464		114,525		231,442		(306,558	)	902,220
Accrued Liabilities		23,349		(51,615	)	23,349		(339,661	)	23,349

Total	$	214,059		250,232		190,088		(1,069,837	)	878,370
Financing Activities:
The total changes in financing activities non-cash working capital accounts detailed below pertains to shares issued and issuable and has been included in that caption in the Statement of Cash Flow:

Accounts Receivable	$	(269,185	)	180,000		(269 ,822	)	-		(269,822	)
Due to Related Parties		(18,235	)	-		(32,841	)	-		-
Prepaid Expenses and Deposits		-		-		-		-		(10,000	)
Accounts Payable		(7,536	)	-		(41,051	)	(113,468	)	-
Flow Through Share Premium Liability		-		(28,835	)	-		28,835		-
Accrued Liabilities		(5,946	)	(250,000	)	-		(220,000	)	-

Total	$	(300,902	)	(98,835	)	(343,714	)	(304,633	)	(279,822

22. SUBSEQUENT EVENTS

Ionic Loan Payable

On October 1, 2009, the Company received the balance of $269,821 proceeds of the Ionic loan and paid additional closing costs due to the vendor of the acquired properties as described in Note 7.

Additional Property Acquisition

In October, 2009, Cougar completed the acquisition from an unrelated company of certain wells, facilities and producing properties in and adjacent to the CREEnergy project. This acquisition is in addition to the one described in Note 7. The acquisition costs was comprised as follows:

	$ U. S.		$ Cdn
Cash	$	93,400	$	100,000
Common shares of Cougar – 155,000 shares at $1.21 per share		186,800		200,000
Total cost	$	280,200	$	300,000

Lucy Farmout

In August, 2009, it was determined that Cougar’s working interest partner in the Lucy, B.C. project was unable to complete the financing as required in the farmout agreement and as a result, in October after due diligence and environmental reviews, Cougar has accepted the transfer of the partner’s Alexander and Crossfield, Alberta properties as a penalty payment. The properties received are valued at approximately $500,000 (NPV 10%). Cougar has assumed asset retirement obligations in connection with the properties estimated at $50,000.

Swiss Fund Financing

In connection with financing arrangements and advances described in Note 10, subsequent to September 30, 2009, Cougar received an additional $121,420 in advances.

Voluntary Delisting

On November 4, 2009, the Company voluntary requested the TSX Venture Exchange ("TSX-V") in Canada, to delist Kodiak's common shares from trading on the TSX-V.

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

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 third quarter of 2009, the Company completed an acquisition of properties that represents its first significant producing resource property. On September 30, 2009, Cougar Energy, Inc., the Company’s majority-controlled Canadian subsidiary, acquired from an unrelated private company certain wells, facilities and producing operations in and adjacent to the CREEnergy project in Alberta, Canada. The acquisition includes 11 producing wells, 21 suspended wells and associated production, water disposal and pipeline facilities in the Trout field. Gross current production is approximately 170 barrels of oil per day. Cougar will be actively working this fall and winter to maximize production and revenue and will also be assessing other opportunities in the area to supplement this initial asset base.

The Company expects to finance its future capital expenditure programs with combinations of debt, farm-outs, equity financings and some divestitures. 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.

The Company plans to aggressively develop and explore its newly acquired Cougar assets. An oil maintenance and development program is planned for the next nine months which is expected to result in increased production of approximately 300 barrels of oil per day (net). Drilling programs will be planned for the fourth quarter of 2010 where the seismic data supports the effort and expense and further drilling will be based on the results of the initial wells.

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

Core Properties

Canada

Trout - Alberta

Cougar has CREEnergy’s active cooperation and sponsorship to identify various operators working in the adjacent lands to the CREEnergy Project. Over the last six months, we negotiated commercial terms for area properties that have the greatest upside through normal maintenance and enhanced recovery programs as well as future potential with additional drilling.

These negotiations culminated at the end of September and beginning of October, 2009 with Cougar successfully acquiring producing the Trout Area properties from two private oil and gas companies. The Cougar operations, land and geological team have already high graded many of the properties within these acquisitions and foresee considerable potential to increase existing production in this first round of development. We anticipate operations to commence on these properties during the winter of 2009/10 consisting of a maintenance and work over program. Un updated independent reserves evaluation report is in process of being completed and will be filed and posted on the corporate website in the near future.

The following represents a summary of the producing and non-producing acquisitions completed over the previous six months:

Farmin (completed June 9, 2009)

28 sections of land in the area of the CREEnergy Project, northwest of Red Earth Creek, Alberta

Cougar has 100% working interest

The mineral rights within the farmin agreement are currently held under several Alberta Crown 4-year initial term P&NG licenses expiring in September 2010 – the rights can be grouped and validated with a drilling program and subsequently continued under a 5 year intermediate term license

Close to infrastructure – existing pipelines with capacity and all weather roads

The wells would have a maximum depth of approximately 1,700 meters (5,577 feet) and potentially target the Gilwood, Slave Point, Wabamun, Gething, and Bluesky formations

There is existing regional natural gas infrastructure and the target formations should contain sweet natural gas, which would reduce production and processing charges.

A drilling program has been prepared for one initial well and two subsequent wells. Contingent upon financing this program will be evaluated and funds allocated to the best net back between this gas project and the other oil developments. An 18 month payback criteria will be used prior to assigning capital to this project.

Private Company Production and Property Acquisition (completed October 1, 2009)

2560 gross acres of land within and adjacent to the CREEnergy Project area lands

65% working interest in six wells – 2 producing wells and 4 suspended wells

Approximately 12 barrels per day (bbl/d) net production (20 bbl/d gross) of light oil

Existing wells and reserves are located in the Kidney and Equisetum fields

Production facilities

Cougar negotiated a purchase agreement with the private company consisting of cash for the P1 reserves and Cougar shares for the P2 reserves. These properties are located within or adjacent to the CREEnergy Project lands. This acquisition was important for us to solidify our position with CREEnergy.

Private Company Production and Property Acquisition (completed September 30, 2009)

7,100 gross acres of mineral rights with an average 85% working interest (all continued through production, no expiries)

Approximately 125 barrels per day (bbl/d) net production (170 bbl/d gross)

11 pumping wellbores

8 single well batteries

3 water disposal wellbores with associated facilities

1 observation wellbore

21 suspended wellbores

2 multi well batteries with existing fluid handling capacity in excess of 2500bbl/day (oil, gas and water handling and treating capability)

Approximately 38.7 km of pipelines (oil and produced water)

10.

Approximately 13 km 2 of 3D seismic over the properties

11.

Approximately 84 km of 2D seismic over the properties and adjacent lands

The agreed purchase price was CAD$6,000,000 with an initial payment of CAD$1,000,000 at closing. The purchase price was negotiated at $52.50 per barrel (bbl) when oil is currently selling at $75+/bbl.

After operating costs, there is an average of CAD$50.00 net back per barrel at current commodity prices. The cash portion of the acquisition cost was provided by Kodiak.

This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs, lower development costs and giving our schedule an enormous leap forward to achieve our goals

Without this kind of infrastructure, the initial production would have lower net backs due to higher trucking costs and regular non-producing periods due to weather. In lieu of this acquisition, a large amount of capital would have to be spent to bring facilities to this baseline, which we now have.

At current costs, the infrastructure replacement value would be substantially in excess of CAD$6,000,000. This capital will now be able to be spent on the drill bit and development work – allowing for a more aggressive growth plan.

Additional details include:

The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in our control and not third party pipeline operator dependent.

There are 2 batteries for the handling and treating of oil and the disposal of the produced water. The batteries are capable of handling an estimated 2,500 bbl/d with nominal refit costs.

Many of the wells are piped into the batteries to lower the need for trucking which is especially important for the higher water cut wells – these pipelines can be expanded to further lower operating costs.

The produced water can be used for future water floods – which regularly have been shown in the area to add substantial incremental production.

There are 37 wells, which 11 are currently producing – the 22 suspended wells have potential upside, as discussed below.

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

This acquisition, combined with the smaller acquisition, provides a solid foundation for us to further enhance the Trout area properties, along with the existing operating and facilities to give substantial momentum to our plans. We believe this justifies the acquisition on that basis alone. There is great potential upside we see on these properties, with additional capital commitments this winter 2009/10 on maintenance programs discussed next.

Upside in Maintenance Programs

We conducted a detailed review of the of the acquired properties public domain petroleum records over last 5 to 7 years with a comparison to other operators in the area. Our operations and geological teams foresee a considerable potential to increase production through normal maintenance activities. Some of these normal maintenance activities include and are not limited to:

Acid wash of perforations

Setting of bridge plugs to seal off water

Waterflood programs

Cleanouts

Reperforating

Repairs to wells with separated rods

Pump optimization,

Plug off water sources

Horizontal drilling

Use of Low damage drilling fluids

Since these existing technologies have proven to be successful in other similar maintenance programs in the area, we see a high potential to enhance the current production levels within this property.

CREEnergy Lands, Alberta

History

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

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

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

To develop and strengthen the relationship with CREEnergy, Kodiak formed a subsidiary company, Cougar Energy, Inc. As a result, Cougar is the operating entity for Kodiak in Western Canada.

Joint Venture Information and Summary

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

Joint Venture Agreement

Key priorities were established from the discussions between CREEnergy and Kodiak:

Use the royalties from the oil and gas production and work programs to develop a revenue stream. The long term purpose of the revenue is to support education, employment and development opportunities for the First Nations communities that Cougar is working with.

Open communication at all stages of the oil and gas developments.

Staged and managed growth, with regard to the interests of the communities during each step.

Identify and source other development opportunities, using a similar model, either as a value add or on a joint venture basis.

Current Status

Cougar continues to actively work with CREEnergy as they assist their First Nations communities to achieve the goal of independence though the Treaty Land Entitlement (TLE) claim with the Federal Government of Canada and the Province of Alberta. This process is nearing completion. We engage with CREEnergy on a weekly basis through conference calls, monthly in person status meetings, and a continual dialogue to foster open communication.

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 projected similar volumetrics as many of the other majors in the area are projecting. In this analysis, the Corporation used all of the laboratory analysis findings and wellbore information obtained during the drilling operation. Further appraisal work is required before estimates can be finalized and commerciality assessed.

In April, 2009, Kodiak, through its private subsidiary, Cougar, entered into a standard farmout and participation agreement with one of its partners. The partner would 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 would be 50%.

Our partner did not complete its financing commitment and this farmout and participation agreement expired on August 15, 2009. After due diligence was completed in October, 2009, the partner transferred its interest in its Alexander and Crossfield, Alberta wells to the Company as a penalty for non-completion.

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 been 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 planned 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 Rock” ) is the 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 of 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 the 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 drilling 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 meters (1,148 feet). The Corporation has identified five drilling locations which could be evaluated during a planned future project drilling program.

In addition, Kodiak had made application with regulators to extend the EL 413 license and has received written notification from Indian and Northern Affairs Canada that a one year extension is available. The one year license extension, which is subject to certain terms and conditions, was provide just prior to expiry and provides for one additional year.

Upon review of the overall status of all projects in the area, current commodity prices being much below levels required to justify development on this and other projects, continued delay of the Mackenzie Valley Pipeline Project, the risk that any discovered gas reserves would be indefinitely stranded without such development, the Company continues to seek partnership in the development; however, the deteriorating economic facors make this difficult. We will still retain the confidential proprietary seismic data for future assessment of the "Little Chicago Prospect" and the Company will determine the best way to monetarize that asset through either divestiture and/or possibly renominating the prospect when conditions are more appropriate.

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 facilities 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 still ongoing with several firms regarding potential opportunities for the project, including integration of the CO2 production into Permian Basin enhanced oil recovery projects and the Company has also entered into farmout negotiations with several companies interested in exploring deeper oil and natural gas prospects on the properties.

Due to lower commodity prices for Permian Basin oil (the primary market for CO2) and CO2 contract prices (deliverable into the Denver City Hub), aggressive development is not financeable at this time. Aside from ongoing maintenance of leases and wells, the company is focusing its efforts on updating engineering models, and business opportunities so that when prices recover and investment markets improve, we will have the opportunity to move this project forward. The leases are 10 year leases and no expiries are imminent.

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 costs relative to this project and subsequently, in 2009, the Company has allowed the acreage to expire.

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 has been able, during these difficult times, to complete a property acquisition on favourable credit terms that will provide the basis for continuing exploration and development programs and ultimately lead the Company during the next few years to a promising future as a junior oil and gas producer. The Company is confident that it will be able to obtain financing that will enable it to carry out its planned programs for the balance of 2009 and for 2010.

The Company’s total assets of $33,650,570 as at September 30, 2009 represent a reduction of $3,520,827 from $37,171,397 as at December 31, 2008. This reduction is mainly comprised of a $16,036,000 impairment allowance recorded in the second quarter of 2009 in connection with the Company's Little Chicago Exploration License 413 in N.W.T, Canada offset by capital asset additions of $7,259,000 and a foreign currency translation gain of $5,141,000 related to its net Canadian assets. Our total assets consist of cash and other current assets of $546,244 (December 31, 2008 - $245,562); Oil and gas properties and equipment of $32,814,129 (December 31, 2008 - $36,634,932); and other assets of $290,197 (December 31, 2008 - $290,903). Our total current liabilities were $4,647,530 (December 31, 2008 - $1,140,273) and consisted of accounts payable and accrued liabilities of $1,552,641 (December 31, 2008 - $1,107,432); loan payable of $1,260,857 (December 31, 2008 - $ Nil); current portion of long-term debt of $803,213 (December 31, 2008 - $ Nil) and 1,030,819 (December 31, 2008 - $ Nil) in advances received from a European investment fund in anticipation of certain financing and asset disposition transactions. We had long-term liabilities of $3,911,293 (December 31, 2008 - $39,262) and asset retirement obligations of $1,020,772 (December 31, 2008 - $199,574). The new loan payable, long-term debt and asset retirement obligations resulted from the financing and acquisition that closed September 30, 2009. Shareholders’ equity amounted to $24,070,975 (December 31, 2008 - $35,792,288), net of an accumulated deficit of $26,585,756 (December 31, 2008 - $8,710,088) and other comprehensive gain consisting mainly of a net foreign currency translation gain of $237,624 (December 31, 2008 – $4,903,762 loss), and non controlling interest equity of $369,326 (December 31, 2008 - $ nil) relating to the 6.4% interest held by non controlling shareholders of Cougar.

Overall Operating Results

In the nine months ended September 30, 2009, the Company had no income (2008 - $46) and operating costs of $6,793 (2008 - $8,863) relating to its Granlea, Alberta property which well watered out in late 2006 and was deemed uneconomic. Except for that incidental production, the Company remained in the exploratory and development stage up to September 30, 2009. Effective October 1, 2009, the company will begin having production and receiving revenue from the producing properties it acquired September 30, 2009 as described elsewhere in this report.

Net Loss for the nine months ended September 30, 2009 totalled $17,875,668 (2008 - $620,123 as restated). In addition to the operating results noted above, these losses consist of general and administrative expenses of $1,506,760 (2008 - $1,620,905), including stock-based compensation expense amounting to $488,686 (2008 - $507,790); depletion, depreciation and accretion of $16,405,480 (2008 - $41,718) and interest of $304 (2008 $1,257).

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 are expected to increase in the future as the scope of the company’s activities increases.

Depletion, depreciation and accretion for 2009 includes a $16,035,774 provision for impairment in connection with the Company's Little Chicago Exploration License 413 in N.W.T, Canada and a $354,286 ceiling test write-down in connection with its Canadian depletable properties. Other unproved property costs as at September 30, 2009 of $25,766,264 (December 31, 2008 - $36,559,367) have been excluded from depletable cost pools for ceiling test purposes. See note 7 to the consolidated financial statements.

Interest income of $967 in the nine months ended September 30, 2009 (2008 - $73,739) was earned. The 2008 interest was derived from the investment of excess cash balances on a short-term basis. Deferred income tax recovery of $978,835 in the 2008 period represents a deferred tax credit arising from the expenditure of funds during that year relating to the premium received on the issue of Canadian flow-through shares in 2007. The non controlling interest credit of $46,866 represents the Cougar non controlling shareholders’ share of the net loss for the 2009 period during the portion of the year that the minority interests shareholdings were outstanding (6.4% as at September 30, 2009).

Capital Expenditures:

Capital Expenditures incurred by the Company during the nine months ended September 30, 2009 and 2008 are set out below.

	2009		2008
Land acquisition and carrying costs	$	6,075,685	$	8,932,404
Geological and geophysical		256,264		4,827,544
Intangible drilling and completion		33,412		3,862,901
Tangible completion and facilities		893,416		161,418

Total Capital Costs Incurred	$	7,258,777	$	17,784,267

Land acquisition and carrying costs for the 2009 period include the cost of the September 30, 2009 acquired properties and exclusivity rights payments in connection with our Cree Energy agreement and other land retention costs while the 2008 period costs include New Mexico land acquisitions and other land retention costs.

Geological and geophysical costs include the cost of the September 30, 2009 acquired seismic data and 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 September 30, 2009, the company’s operations have been financed from the sale of securities and loans from shareholders. The working capital deficiency at September 30, 2009 amounted to $4,101,286 (December 31, 2008 - $894,711). The increase in the deficiency results from the debt incurred related to the September 30, 2009 property acquisition. The Company is currently in the process of arranging certain equity and longer term financing that will reduce the working capital deficiency to a manageable amount and provide additional funding of near term development programs that are planned to significantly increase production, revenue and cash flow over the next nine months. It is contemplated that these transactions will completed before yearend.

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 and to enable it to repay its debt. Although the recent property acquisitions will provide production, revenue and cash flow, the Company's September 30, 2009 financial condition still raises 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 .

Voluntary Delisting of Company's Shares From TSX Venture Exchange in Canada

On November 4, 2009, The Company voluntarily requested the TSX Venture Exchange ("TSX-V") in Canada to delist its common shares from trading on the TSX-V. See "PART II Item 5. Other Information" in this Form 10-Q for further information on the delisting.

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 are designed , and are effective, to give reasonable assurance that the information required to be disclosed by the Company in reports that it files under the exchange act is recorded , processed, summarized and reported within the time periods specified in the rules and forms of the SEC and also effective to ensure that information required to be disclosed in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our chief executive officer and chief financial officer, to allow timely decisions regarding required disclosure. They also 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.

Our management believes that our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures are effective at that reasonable assurance level. As noted below, the Company continues to have a material weakness in internal control over financial reporting but believes that such weakness does not extend into our disclosure controls and procedures.

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. Since 2008, the Company has 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 yearend and quarterly Canadian and U.S. income tax provisions.

As at September 30, 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 will be justifiable in the near future now that the Company has acquired producing properties and commencing with the fourth quarter of 2009 will have production, revenue and cash from operations. The Company has also hired a Vice-President of Finance, effective November 2, 2009, which we believe will help to alleviate our segregation of duties weakness. 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. 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, or that the Company will generate positive cash flow. 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 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 substantial losses in worldwide equity markets led to a worldwide economic recession. The slowdown in economic activity caused by this recession reduced worldwide demand for energy and resulted 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. Although there are some signs that a slow economic recovery may be underway, the Company’s ability to raise capital to finance ongoing capital projects remains a very difficult challenge. Until the financial market conditions improve significantly, we will face challenges in meeting our ongoing financial obligations. The Company may be required to consider divestiture of some properties or working interests to raise funds. The continuing 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 our operating expenses will continue to increase 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 favorable 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.

Prior to the fourth quarter of 2009, we have been 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 nine months ended September 30, 2009 and the years ended December 31, 2008, 2007, 2006 and 2005, we reported losses of $17,543,936, $2,074,649, $2,571,663 (restated), $2,867,374 and $1,133,790 respectively. Commencing in October, 2009 and effective with the acquisition of our first producing properties as described under "Property Acquisition” in Note 7 to our consolidated financial statements, we will become a producing company and will no longer be an exploration stage company. Our consolidated financial statements for the nine months ended September 30, 2009 and the years ended December 31, 2008, 2007, 2006 and 2005 contained a going concern qualification and we cannot give any assurances that we can yet 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 And 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 such as changes in government regulation that could limit or expand 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 an automated quotation system sponsored by a national securities association (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.

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

Voluntary Delisting of Company's Shares From TSX Venture Exchange in Canada

On November 4, 2009, The Company voluntarily requested the TSX Venture Exchange ("TSX-V") in Canada to delist its common shares from trading on the TSX-V. The TSX-V’s policies allow for a period of ten days before delisting to facilitate settlement of trades and to allow shareholders to sell to willing purchasers. The TSX-V will issue an Exchange Bulletin ten days prior to the voluntary delisting. This voluntary delisting is not pursuant to any order or communication from the TSX-V.

Kodiak's common shares are currently quoted for trading on the OTC Bulletin Board (OTCBB) in the United States under the symbol KDKN and it will continue to maintain this quotation status and Canadian shareholders will be able to continue to trade through their brokers on that market.

The Corporation’s board of directors approved the voluntary delisting from the TSX Venture Exchange after weighing the required expenses and multi-jurisdictional filings to maintain a dual listing of the company's securities against the perceived shareholder benefit accrued from trading on different platforms. The Corporation does not expect the anticipated voluntary delisting from the TSX-V will have any impact on the day-to-day operations of the company.

The primary reasons for the voluntary delisting request are:

Since the Corporation’s TSX-V listing effective December 24, 2007 to market close on October 30, 2009, liquidity analysis revealed an average daily trading volume of 270,413 shares on the OTCBB and 14,022 on the TSX-V for the period – a difference in trading volume and liquidity of over 19 times.

Following the initial Canadian based financing associated with the TSX-V listing, the Corporation has repeatedly experienced little to no investment interest or support from the Canadian financial community consisting of investment banks, capital markets and retail brokerage firms, and private equity firms. The primary source of equity financing has been from Europe over the last 18 months, and we do not expect that to change in the foreseeable future. Our European investors have a stated preference for the OTCBB listing versus the TSX-V, of which the latter listing they do not follow.

The Corporation’s Board of Directors believes that voluntarily delisting from the TSX-V and focusing on U.S. and European markets is in the best interests of our shareholders. This will eliminate the substantial cross-border financing and reporting issues.

As of October 31, 2009, the Corporation’s transfer agent, Computershare, revealed the shareholder geographic position of all foreign based shareholders at 61.54% and Canadian based shareholders at 38.46%, of which the vast majority of the latter is founder shareholdings and only a nominal amount in the Canadian float. As a result, the OTCBB quotation system serves shareholders of the majority of Kodiak’s shares, where the Corporation’s stock has been trading since December 27, 2004.

The internal and external compliance costs to maintain the listing of the Corporation’s shares on the TSX-V are relatively significant to a company of this size, which has not resulted in an additional benefit for shareholders in view of the low trading volume on the TSX-V.

The Financial Industry Regulatory Authority (FINRA) is the largest independent regulator for securities firms in the United States and is responsible for establishing rules governing its broker/dealer members, including OTCBB subscribing members, on conduct, qualification standards, examinations, investigations, violations, and investor and member inquiries – thus there is a previous and demonstrated, current market for Kodiak shareholders.

Other factors:

To maintain quotation eligibility on the OTCBB, Kodiak Energy, Inc. is required to file periodic financial information with the U.S. Securities and Exchange Commission (SEC). All the Corporation’s filings are located under the “Kodiak Energy, Inc.” profile on the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system through the U.S. SEC website at http://www.sec.gov.

Kodiak intends on maintaining its “foreign reporting issuer status” with the Alberta Securities Commission.

Kodiak is Sarbanes Oxley (SOX) compliant, is a fully reporting accelerated filer, and adheres to the security laws, rules, regulations and filing requirements of the U.S. SEC.

ITEM 6. EXHIBITS

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.