- Quarterly Report (10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2010

[ ] 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 1120, 833 4th Avenue S.W. Calgary, AB T2P 3T5

(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 ___	Accelerated Filer ___
Non-Accelerated Filer X (Do not check if a smaller reporting company)	Smaller Reporting Company ___

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 May 14, 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	16

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26

ITEM 4.	CONTROLS AND PROCEDURES	27

ITEM 4T	CONTROLS AND PROCEDURES	29

PART II.	OTHER INFORMATION	30

ITEM 1.	LEGAL PROCEEDINGS	30

ITEM 1A.	RISK FACTORS	30

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	30

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	30

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	30

ITEM 5.	OTHER INFORMATION	30

ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K	30

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK ENERGY, INC.
Consolidated Balance Sheets
(Going Concern Uncertainty - Note 1)
	March 31			December 31,
	2010			2009
Assets	(Unaudited)			(Audited)
Current Assets:
Cash and Short Term Deposits	$	28,116		$	2,058
Accounts Receivable		657,287			403,907
Prepaid Expenses and Deposits		169,535			151,390
		854,938			557,355

Other Assets		306,458			296,153

Goodwill (Note 2)		1,593,742			-

Oil and natural gas properties, Full cost accounting (Note 4)
Devaluated properties		7,720,904			6,823,400
Less accumulated depreciation, depletion and ammortization		2,481,547			2,165,997
		5,239,357			4,657,403

Undeveloped properties excluded in amortization		22,548,800			26,081,786


Furniture and Fixtures, net		67,706			64,862
		27,855,863			30,804,051

Total Assets	$	30,611,001		$	31,657,559

Liabilities and Stockholders' Equity
Current Liabilities:
Accounts Payable	$	2,963,563		$	2,267,139
Accrued Liabilities		83,272			281,522
Operating line of credit (Note 5)		393,778			-
Note Payable (Note 2)		-			1,364,036
Current debt		1,305,055			538,831
		4,745,669			4,451,528

Long-term Liabilities (Note 6)		3,315,282			3,400,489

Asset Retirement Obligations (Note 7)		1,350,909			1,285,614


Total Liabilities		9,411,860			9,137,631

Share Capital: Authorized 300,000,000 Common Shares Par Value $.001 Each;10,000,000 (2008 -10,000,000l) Preferred Shares.Issued and Outstanding 110,407,186 (2009 -110,407,186) Common Shares.		110,407			110,407
Additional Paid in Capital		50,390,663			50,851,469
Accumulated Comprehensive Gain (Loss)		793,928			(416,905	)
Deficit		(32,895,455	)		(28,283,170	)
		18,399,543			22,261,801
Noncontrolling Interest		2,799,598			258,127
Total Shareholder Equity		21,199,141			22,519,928
Total Liabilities and Equity	$	30,611,001		$	31,657,559

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY INC. Consolidated Statements of Shareholders Equity (Deficiency) For the Periods ended March 31, 2010 and December 31,2009 ( Going Concern Uncertainty - Note 1)
	Number of Common Shares		Amount		Additional Paid in Capital			Deficit Accumulated			Accumulated other Comprehensive Income (Loss)			Non-contolling interest			Total Shareholders' Equity (Deficit)
Balance at December 31, 2009		110,407,186		110,407		50,851,469			(28,283,170	)		(416,905	)		258,127			22,519,928
Net Loss									(4,612,285	)					(104,605	)		(4,716,890	)
Foreign currency translation												1,210,833						1,210,833
Issuance of common stock																		-
Stock-based Compensation						166,143												166,143
Dispositon of Non-controlling interest in Cougar Energy Inc.						(626,949	)								(258,127	)		(885,076	)
Non-controlling interest in Cougar Oil and Gas															2,904,203			2,904,203
Balance at March 31, 2010		110,407,186		110,407		50,390,663			(32,895,455	)		793,928			2,799,598			21,199,141

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.
Consolidated Statements of Operations
( Going Concern Uncertainty - Note 1)	For the Three			For the Three
	Months ended			Months ended
	March 31, 2010			March 31, 2009

REVENUE
Oil Sales	$	725,393		$	-
Other		41			-
		725,434			-
EXPENSES
Operating		303,235			1,170
General and Administrative		652,520			493,462
Asset writedowns		4,410,309			7,788
Interest		76,260			211
		5,442,324			502,631

Loss Before Other Expenses (Income)		4,716,890			502,631

Gain on non-monetary transfer of properties		-			2,164
Interest Income		-			(198	)
		-			1,966
Loss before income taxes		4,716,890			504,597
Net Loss		4,716,890			504,597
Net Loss attributed to Non Controlling Interest		104,605			(4,062	)
Net Loss attributed to Kodiak		4,612,285			500,535

Basic and diluted loss per share (Note 10)	$	(0.04	)		(0.005	)

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.
Consolidated Statements of Cash Flows	For the Three			For the Three
(Going Concern Uncertainty - Note 1)	Months ended			Months ended
	March 31, 2010			March 31, 2009




Operating Activities:
Net Loss	$	(4,612,285	)	$	(500,535	)

Adjustments to reconcile net loss to net cash used in operating activities:

Depletion, Depreciation and Accretion including Ceiling Test Impairments and Write-downs		4,410,309			7,788
Stock-Based Compensation		309,475			152,047
(Gain) loss on non-monetary transfer of properties					(2,164	)
Non-Controlling Interst		(104,605	)		(4,062	)
Non-Cash Working Capital Changes (Note 15)		170,545			203,075
Net Cash Used In Operating Activities		173,439			(143,851	)

Investment Activities:

Additions to Capital Assets		(696,773	)		236,460
Decrease (Increase) in Other Assets		-			9,792
Net Cash Used In Investment Activities		(696,773	)		246,252

Financing Activities:

Shares Issued and Issuable		-			(79,190	)
Non-Controlling interest contribution					393,460
Increase(repayment) of revolving loan		393,778			-
(Decrease) Increase in Long Term Liabilities		155,316			(1,347	)
Cash Provided By Financing Activities		549,094			312,923

Foreign Currency Translation		-			(485,067	)
Net Cash (Decrease) Increase		25,760			(69,743	)
Cash beginning of year		2,058			75,175
Cash end of year	$	27,818		$	5,432

Cash is comprised of:
Balances with banks	$	28,116		$	5,432
Short term deposits
	$	28,116		$	5,432

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Three Months Ended March 31, 2010 and 2009

Stated in US dollars

1. ORGANIZATION, BASIS OF PRESENTATION AND GOING CONCERN UNCERTAINTY

The accompanying consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”) as at March 31, 2010 and March 31, 2009 , and are presented in accordance with accounting principles generally accepted in the United States of America (“U. S. GAAP”).

In the opinion of management, the accompanying unaudited consolidated financial statements reflect all adjustments (including normal recurring adjustments) necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the year ended December 31, 2010.

Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2009 Annual Report on Form 10-K.

Going Concern Uncertainty

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

2. PURCHASE OF SUBSIDARY

On January 25, 2010, the Company, through its subsidiary Cougar Energy Inc. (“Cougar”), completed its merger with Ore-More Resources with the issuance of of 36,786,972 (12,262,324 pre split) (b) share of Ore-more for 8,461,549 shares of Cougar. In accordance with U.S. GAAP, the transaction was accounted for as a reverse acquisition and Cougar was deemed the accounting acquirer. Cougar’s net assets were carried forward at their existing accounting basis and all of Ore-Mores’ assets and liabilities were revalued at fair value as of the acquisition date. The consolidated financial statements of the Company for March 31, 2010 include the operations of Ore-More from January 1, 2010. Ore-More contributed no revenue and immaterial earnings for the period January 1, 2010 to March 31, 2010.

The following table summarizes the calculation of the fair value of consideration transferred to acquire Ore-more:

Cougar shares to be issued		5,630,913	(a)
Multiplied by	$	0.61	(b)
	$	3,451,468

The following table summarizes the calculation of the fair value of consideration transferred by Kodiak to acquire Ore-More:

Assets acquired:
Current
Cash	$	7,611
Accounts receivable	$	1,326,786

Liabilities assumed:
Current
Accounts payable and accrued liabilities	$	(5,693	)
Operating Line	$	-
Current debt	$	(97,927	)
Inter- Company Payables
	$	1,230,777
NCI eliminated	$	626,949

Purchase price	$	3,451,468

Good will on acquisition	$	1,593,742

The allocation of the purchase price to the consolidated assets and liabilities of Ore-More resulted in goodwill of $1,593,742 which is the difference between the aggregate of the fair value of Ore-Mores’ net assets and the value of the eliminated non-controlling interest and the fair market value of the consideration effectively transferred. The goodwill is not expected to be deductible for tax purposes.

Prior to the merger, Ore-more had acquired from a third party the right to collect debt of $1,357,713 from the Company. Pursuant to the merger agreement, in addition to issuing common shares to the Company, Ore-more extinguished the $1,357,713 note receivable and cancelled 12,200,000 of its own common shares. Following the closing of the transaction, Ore-More changed its name to Cougar Oil and Gas Canada.

Upon the completion of the Merger, Kodiak directly hold approximately 64.58% of the outstanding shares of Cougar Oil and Gas. This remaining 35.48% is accounted for by the Company as a non-controlling interest

3. RECENTLY ISSUED ACCOUNTING STANDARDS

Accounting standards-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements affecting our financial statements have been issued since the filing of our 2009 Annual Report on Form 10-K.

_________

(a) In accordance with ASC 805-40 this represents the Number of Shares Cougar would have had to issue to give the owners of Ore-more the same percentage equity interest in the combined entity that results from the reverse acquisition.
(b) Represents the stock price of Cougar's private placement to unrelated parties on December 16, 2009, adjusted for the Ore-More 3- 1 reverse stock split effectuated on January 25, 2010.

4. CAPITAL ASSETS

	Cost		Accumulated Depreciation and Depletion		Net book Value March 31, 2010
Oil and Gas Properties:
Developed
Canada	$	7,720,904	$	2,481,547	$	5,239,357

Undeveloped
Canada		33,663,866		18,246,036		15,417,830
United States		11,773,837		4,642,867		7,130,970
		45,437,703		22,888,903		22,548,800

Furniture and Fixtures		178,750		111,044		67,706
Total	$	53,337,357	$	25,481,494	$	27,855,863

	Cost		Accumulated Depreciation and Depletion		Net book Value December 31, 2009
Oil and Gas Properties:
Developed
Canada	$	6,823,400	$	2,165,994	$	4,657,406

Undeveloped
Canada		32,441,500		17,634,527		14,806,973
United States		11,773,677		498,867		11,274,810
		44,215,177		18,133,394		26,081,783

Furniture and Fixtures		168,166		103,304		64,862
Total	$	51,206,743	$	20,402,692	$	30,804,051

During the three months ended March 31, 2010, the Company capitalized $7,266 (March 31, 2009 - $47,104) of general and administrative personnel costs attributable to acquisition, exploration and development activities. Future capital costs included in the depletion calculation for March 31, 2010 were $619,000 (March 31, 2009 - Nil)

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

At March 31, 2010, a ceiling test was performed on the Company's properties subject to depletion. Costs of unproved properties aggregating $22,548,799 and future abandonment costs of $306,375 have been excluded from this test. This test disclosed that the carrying costs of the Company's depletable Canadian properties did not exceeded their net present value b and consequently no ceiling write-down was required.

Unproved Properties

During the three months ended March 31, 2010 certain unproved properties in the United States were allowed to expire. These properties were removed from Undeveloped properties at their carrying value of $4,144,000 and have been included in Depletion, Depreciation and Accretion on the statement of operations.

5 . OPERATING LINE OF CREDIT

During the three months ended March 31,2010 the Company reached formal agreement with a Canadian bank for two credit facilities. The first credit facility is a revolving demand loan in the amount of Cdn$1,000,000 at a per annum rate of prime interest plus 3.5%. The second credit facility is a non-revolving acquisition/development demand loan bearing an annual per annum interest rate of prime plus 3.0%. Under the terms of the Agreement, the two credit facilities are committed for the development of existing proved non-producing /undeveloped petroleum and natural gas reserves. As at March 31, 2010 $393,778 of the revolving line was drawn (December 31, 2009 – Nil) . There was Nil drawn on the second facility.

6. LONG TERM AND SHORT TERM LIABILITIES

The Company has the following liabilities:

	March 31, 2010
Amount due to vendor of acquired properties present value of total amount due	$	4,599,155
Amount of Discount to be accreted in the future (at 7.5% annually - .0625% per month)		(601,745	)
Total Amount Due		3,997,410
Less: Current portion		682,127
Long-term portion	$	3,315,282


Current portion of Long-term debt	$	682,127
Other short-term debt		622,928
Total short-term debt	$	1,305,055

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

During the quarter, non cash interest of $71,219 was recorded as interest expense in relation to the discount on the vendor acquired indebtedness.

During the three months ended March 31, 2010 the total amounts owing on the note payable were extinguished as a result of the share exchange with Ore-More as noted in Note 2.

7. 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, 2009	$	1,285,614
Foreign exchange		39,503
Accretion		25,792
Asset retirement obligations, March 31, 2010	$	1,350,909

At March 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,132,778 (December 31, 2009 - $3,033,143). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 15 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%.

8. STOCK OPTION PLAN AND STOCK BASED COMPENSATION

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.

	March 31, 2010
	Weighted average Exercise
	Price		Shares
Outstanding at beginning of period	$	0.57		6,060,000
Options Granted		-		-
Options cancelled		1.50		(200,000	)
Outstanding at end of period		0.54		5,860,000
Exersicable at end of period	$	1.43		1,196,667

Significant option groups outstanding at March 31, 2010 and December 31, 2009 and related weighted average price and life information follow:

		Outstanding								Exerciseable
Range of exersise Price		Number outstanding at March 31, 2010		Weighted Average remaining Contracual life		Weighted average Exercsie Price		Aggregate intrensic value		Number outstanding at March 31, 2010		Weighted average Exercise price		Aggregate I ntrensic Value
	.28-1.28		4,855,000		4.08		0.32		-		225,000		1.02		-
	1.29-2.28		905,000		1.66		1.44		-		905,000		1.44		-
	2.29-3.28		100,000		2.67		2.58		-		66,667		2.58		-

A summary of options granted and outstanding under the plan is presented below.

		Nonvested Options			Weighted-Average Grant Date Fair Value
Nonvested at December 31, 2009			4,756,670			0.25
	Granted		-			-
	Vested		(93,334	)		0.72
	Forfeited		-			-
Nonvested at March 31, 2010			4,663,336			0.24

Warrants

During years ended December 31, 2006, 2007, 2008 and 2009, 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		1.25
Issued June 18, 2008		3.50	Jun. 18/10		1,300,000		0.22
Balance March 31, 2010					2,430,000		0.70

In accordance with FASB ASC 718, the Company uses the Black-Scholes option pricing method to determine the fair value of each warrant granted and the amount is recognized as additional expense in the statement of earnings over the vesting period of the warrants.

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

March 31, 2010
Weighted average Exercise
Price		Shares
$	0.81		850,000
	1.30		195,000
	-		-
	0.83		1,045,000
$	0.65		266,670

Outstanding								Exerciseable
Number outstanding at March 31, 2010		Weighted Average remaining Contracual life		Weighted average Exercsie Price		Aggregate intrensic value		Number outstanding at March 31, 2010		Weighted average Exercise price		Aggregate Intrensic Value
	750,000		3.73		0.65		-		266,670		0.65		-
	295,000		4.58		1.30		-		-		-		-
	1,045,000				0.83				266,670		0.65		-

9. NON CONTROLLING INTEREST

Net Income Attributable to Kodiak Petroeum and Transfers (to) from Noncontolling interst for the three months ended March 31, 2010

Net loss attributable to Kodiak	$	294,829
Transfer (to) from the non-controlling interest
Non-controlling interst percentage		35.48	%
Change from net income attributable to Kodiak Energy and transfer (to) from non-controlling interest		104,605

10. LOSS PER SHARE

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

	For the three months ended March 31, 2010		For the three months ended March 31, 2009
Numerator:
Numerator for basic and diluted loss per share.
Net loss		4,612,285		(500,353	)
Denominator:
Denominator for basic and diluted loss per share
Weighted average shares outstanding		110,407,186		110,023,998
Contingent Thunder shares		-		2,500,000

Denominator for diluted loss per share
Weighted average shares outstanding		110,407,186		112,523,998
Basic and diluted loss per share	$	0.04	$	0.005

Basic loss per share is based on the weighted average number of shares outstanding during the periods. Diluted loss is per share is based on the weighted average number of shares and all dilutive potential shares outstanding during the periods. The Company had outstanding stock options and warrants as at March 31, 2010 and 2009, as disclosed in note 11 that were antidilutive due to the net loss of those periods.

11. COMMITMENTS AND CONTINGENCIES

Lease Commitments

As of March 31, 2010 and 2009, the Company had lease commitments for vehicles, office rent and office equipment. The following lease commitments for the years shown:

	March 31, 2010		March 31, 2009
Amounts payable in:
2010	$	113,112	$	19,575
2011		166,642		23,856
2012		162,337		3,172
2013	$	39,797	$	-

12. FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

The Company adopted the provisions of SFAS No. 157 that relate to our financial assets and financial liabilities (“financial instruments”). SFAS No. 157 establishes a hierarchy that prioritizes fair value measurements based on the types of inputs used for the various valuation techniques (market approach, income approach and cost approach). The levels of the hierarchy are described below:

Level 1: consists of financial instruments whose value is based on quoted market prices for identical financial instruments in an active market

Level 2: consists of financial instruments that are valued using models or other valuation methodologies. These models use inputs that are observable either directly or indirectly; Level 2 inputs include (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in markets that are not active, (iii) pricing models whose inputs are observable for substantially the full term of the financial instrument and (iv) pricing models whose inputs are derived principally from or corroborated by observable market data through correlation or other means for substantially the full term of the financial instrument

Level 3: consists of financial instruments whose values are determined using pricing models that utilize significant inputs that are primarily unobservable, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair market requires significant management judgment or estimation

The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of financial instruments and their classification within the fair value hierarchy. As required by SFAS No. 157, financial instruments are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. There have been no changes in the classification of any financial instruments within the fair value hierarchy and did not result in any material changes.

13. RELATED PARTY TRANSACTIONS

For the three months ended March 31, 2010, the Company paid $Nil (March 31, 2009 – $24,107), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services. Of this amount, $nil (March 31, 2009 - $6,910) was capitalized to Unproved Oil and Gas Properties and $nil (March 31, 2009 -$17,197) was charged to General and Administrative Expense.

For the three months ended March 31, 2010 and 2009, the Company paid $9,681 (March 31, 2009 - $38,263) to Director and the former Chief Financial Officer. Of this amount, $10,214 was payable at March 31, 2010. The company paid $28,706 to a company owned and controlled by the chairman of the company. Of this amount, $10,337 was payable on March 31, 2010. The company paid the wife of the chairman of the company $6,565. Of this amount, $5,210 was outstanding on March 31, 2010. These amounts were charged to General and Administrative Expense.

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

14. SEGMENTED INFORMATION

The Company’s two geographical segments are the United States and Canada. Both segments use accounting policies that are identical to those used in the consolidated financial statements. The Company’s geographical segmented information is as follows:

	For the three months ended March 31, 2010
	U. S.		Canada			Total

Revenue, net of royalties		-		725,393			725,434
Net Loss		4,148,064		(464,221	)		3,683,843
Capital Assets		7,130,970		20,724,892			27,855,862
Total Assets		7,136,824		23,474,176			30,611,000
Capital Expenditures		160		2,130,374			2,130,534

	For the three months ended March 31, 2009
	U. S.		Canada			Total

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

15. CHANGES IN NON-CASH WORKING CAPITAL

	For the three Months Ended March 31, 2010			For the three Months Ended March 31, 2009			For the three Months Ended March 31, 2008
Operating Activities:
Accounts Receivable	$	(249,734	)	$	(7,006	)	$	648,919
Prepaid Expenses and Deposits		(16,427	)		5,896			(10,457	)
Accounts Payable		(15,969	)		308,670			21,131
Other Debt		(45,501	)		-			-
Accrued Liabilities		(198,250	)		(104,485	)		(56,129	)
Total	$	(525,881	)	$	203,075		$	603,464

Investing Activities
The total changes in investing activities non-cash working capital accounts, which is detailed below, pertains to capital asset additions and has been included in that caption in the Statement of Cash Flow:
Accounts Receivable		(13,902	)		(6,293	)	$	185,155
Prepaid Expenses and		(1,719	)		1,344			18,874
Deposits		-			-			155,976
Accounts Payable		712,393			(19,022	)		(19,253	)
Accrued Liabilities		-			-			2,252,012
Total	$	696,772		$	(23,971	)	$	2,592,764

Financing Activities
The total changes in financing activities non-cash working capital accounts, which is detailed below, pertains to shares issued and issuable and has been included in that caption in the Statement of Cash Flow:
Account Receivable					(637	)	$	-
Deposits and Prepaids		-			-
Accounts Payable					(33,515	)		(113,468	)
Accrued Liabilities		-			5,946			-
Note Payable to Related Party		0			(14,606	)		-
Total	$	0		$	(42,812	)	$	-113,468

Total Change in Non Cash	$	170,891		$	136,292		$	3,082,760

16. SUBSEQUENT EVENTS

Subsequent to March 31, 2010 Cougar Oil and Gas issued 2,625,584 shares to various third parties reducing Kodiak interest in their subsidiary from 64.52% at March 31, 2010 to 61.6% at the time of this filing.

Also following March 31, 2010, Kodiak purchased additional working interests in various producing wells in its core area of Trout. For $200,000 subject to normal industry adjustments is are due to close in the second quarter of 2010.

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 mentioned elsewhere 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 the consolidated financial statements of Kodiak Energy, Inc. included elsewhere herein.

PLAN OF OPERATION

Oil and Gas Leases and Development Rights

As of March 31, 2010, we had approximately 130 80 leases covering approximately 285 256,949 gross acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount typically ranges from 12% to 30% resulting in a 70% to 88% net revenue interest to us.

Because the acquisition of oil and gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other oil and gas operators. In order to gain the right to drill these leases, we may purchase leases from other oil and gas operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 5% to 15%, which further reduces the net revenue interest available to us to between 55% and 73%.

In Q1, 2010, the Corporation elected to allow approximately 29,000 acres of mineral rights to expire. These mineral rights were leased from the State of New Mexico and had more than a year left on their initial lease term. After reviewing the New Mexico project results to date the Corporation reviewed all of the New Mexico properties and determined this specific acreage was situated too far from the regional carbon dioxide pipeline and it would be unlikely to be developed prior to expiry resulting in additional rental fees and administration costs. The Corporation remains confident that the remaining mineral leases are the most strategically valuable to successfully develop the Sofia carbon dioxide resources.

As of December 31, 2009, approximately 4% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

In the Trout Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 7,680 gross acres, of which approximately 320 gross acres (4%) are not currently held by production. The approximate 320 acres had an expiry date in Q4 2009 and an application has been submitted to the regulatory agency to extend the expiry of these leases.

In the Alexander Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 160 gross acres, of which 0 gross acres (0%) are not currently held by production. There are no expiry issues for this lease.

In the Crossfield Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 160 gross acres, of which 0 gross acres (0%) are not currently held by production. There are no expiry issues for this lease.

In the Granlea Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 1,265 gross acres, of which approximately 1,265 gross acres (100%) are not currently held by production. The Granlea oil and gas leases will expire in Q3 2010.

In Lucy, British Columbia as of December 31, 2009, we held oil and gas leases on approximately 1,975 gross acres, of which approximately 1,975 gross acres (100%) are not currently held by production. The Lucy mineral lease was extended as part of an approved Experimental Scheme application to the regulatory agency. The Lucy lease is currently extended indefinitely.

In the Little Chicago Area, N.W.T. as of December 31, 2009, we held oil and gas leases on approximately 199,000 gross acres, of which approximately 199,000 gross acres (100%) are not currently held by production. The Little Chicago oil and gas leases will expire in Q3 2010.

In the Sofia and Speardraw Areas, northeast New Mexico as of December 31, 2009, we held CO2 and oil and gas leases on approximately 47,805 gross acres, of which approximately 47,805 gross acres (100%) are not currently held by production. There are no lease expiries in 2010.

In the Hill County Area, northwest Montana as of December 31, 2009, we held oil and gas leases on approximately 879 gross acres, of which approximately 879 gross acres (100%) are not currently held by production. The Montana leases will expire in Q3 2010.

In the Bison Lake area, northern Alberta as of December 31, 2009, we hold oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on approximately 17,712 gross acres that are still within their original lease or agreement term and are not earned or are not held by production. The farm-in agreement specifies that we are entitled to earn 100% of whatever leases we can extend as a result of drilling and completion operations. The farm-in leases expire in Q3 2010.

As our projects in Kodiak - EL 413 and Sofia New Mexico - were long term projects and subject to external influences such a commodity prices, pipeline status, overall investment climate and etc, it has been difficult to raise equity financing for such purposes in the last 18 to 24 months. During this time we reduced internal costs to a minimum and continue to hold Kodiak’s costs at that level.

Based on advice from the investment community on how to finance going forward and the stage of the projects that Kodiak was at, it was decided to place the CREEnergy project into a subsidiary and finance that project in conjunction with Lucy, as a Canadian conventional Oil and Gas operations based subsidiary. In that way specific financing could be raised with equity initially for this project and then as it matured into non conventional debt and finally into conventional debt instruments. Thus Cougar Energy was born.

To have arranged the private placements into Kodiak at the time of the world recession would have been at such a discount to the already depressed market as to have been very dilutive to the Kodiak shareholders. We tried very hard for many months to arrange financing during those difficult times – in Canada, Europe and various institutions in the USA.

Some of the term sheets offered by the various investment banks would have resulted in a material change of control of the company due to the discount to the share price and the size of the required placement, or the ownership of the actual projects would have changed or both and thus potentially lost opportunities to the existing shareholders. Ultimately we succeeded through hard work and persistence and are succeeding with the plan by making small steps toward the final goal.

We financed the CREEnergy project and Cougar operations, with small private placements with accredited small investors in Canada and Europe as per the regulations, for the first 10 months. Then as the acquisitions presented opportunities, we found a bridge loan and a vendor take back to close the acquisition. Please read the management discussion posted on the Cougar web site.

Subsequently we reached an agreement with OreMore ( Cougar Oil and Gas Canada, Inc) who had previously bought the bridge loan (which had been guaranteed by both Cougar and Kodiak) – to merge Cougar Energy into OreMore in exchange for issuing shares of Oremore to Kodiak and cancelling the bridge loan debt. Thus we retained the project through ownership of shares of and positions on the Board of Directors of Oremore.

The result was Cougar Oil and Gas Canada – who has a strong future and Kodiak retains a 64.52% of the outstanding shares at this time.

Kodiak in the agreements has the rights to retain a majority interest in Cougar Oil and Gas Canada going forward by participating in any financing and as Cougar shows success expected both short and long term, we believe that Kodiak will start to see that reflected in the Kodiak share price.

Canada

Through Kodiak’s majority interest in Cougar Oil and Gas Canada, the Company’s focus has developed into the definitive projects of:

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

CREEnergy Project, Alberta – mineral leases, exploration and development opportunities within the CREEnergy Agreement and several current and proposed Northern Alberta Treaty Land Entitlement Claims;

Lucy, British Columbia – Horn River Basin Muskwa shale gas project; and

Other Alberta properties.

The Company expects to finance its future capital expenditure programs and acquisitions with combinations of revenue from current operations, debt instruments, farm-outs, equity financings and divestitures, depending upon what vehicle is appropriate to the capital program/acquisition and the overall market economy. A 6 to 12 month payback will be used to benchmark all such capital programs for financing purposes. A brief description of the Company’s properties and activities is described below. For a more detail description of the properties to better understand the planned operations.

Cougar Trout Properties, Alberta (Core Area)

The following is a summary of the various properties plan of developments:

Farmin (June 2009) . A 100% working interest in 28 sections of land in the area of the CREEnergy Project, northwest of Red Earth Creek, Alberta – pay 100% to earn 100% with a 3% gross overriding royalty (GOR) upon earning to the vendor.

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. A minimum 18 month payback criteria will be used prior to assigning capital to this project.

Private Company Production and Property Acquisitions (2009) . The existing infrastructure and initial production on the acquired properties enables the Company to realize higher netbacks and focus on deploying capital to the drill bit and development work. Additional details include:

The existing area field personnel agreed to transfer to Cougar with their many years of hands-on field expertise thereby greatly reducing the risk of downtime due to lack of qualified field personnel.

The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in the Company’s 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 reduce the need for trucking, which is important for the higher water cut wells. These pipelines can be expanded to further lower operating costs.

There are 37 wells, which 13 were producing as of December 31, 2009. The 20 suspended wells are workover or recompletion candidates.

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

Metrics for review of progress

As of December 31, 2009, the average production was 125 bbl/d net of light sweet crude oil at an average operating cost of CAD$20.00 to CAD$25.00/bbl.

As of March 31, our average net production was approximately 150bbl/d. Our overall acquisition costs have dropped from $74K per flowing barrel to approximately $25K per flowing barrel as a result of the reactivation and maintenance work performed on the properties. Continued low risk development work is adding additional production at a cost of approximately $10K to $15K per flowing barrel. Production has increase 17% over previous quarter, Revenue has increased 27% over previous quarter, Operating costs have lowered 37% over previous quarter and operating net backs have increased 120% over previous quarter.

Subsequent Maintenance and Development Programs

Prior to the production and property acquisitions, the Company conducted a detailed review of the properties in public domain petroleum records over last 5 to 7 years and with a comparison to other operators in the area. The Company’s operations and geological teams have determined a strong potential to increase production through normal maintenance activities. These activities include utilizing existing technologies that have proven success in similar maintenance and optimization programs in the area. Some of these normal maintenance activities include and are not limited to:

Acid wash of perforations

Use of enhanced chemical treatment programs to improve inflow

Setting of bridge plugs to seal off water

Cleanouts

Re perforating

Drill out plugs and open up previously unproduced zones

Repairs to wells with separated rods

Plug off water sources with no resulting loss of production

Pump and well site equipment optimization

Waterflood programs – future

Horizontal drilling – future

Continued Development of the Trout Area Through Systematic Operational Controls

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

Consolidate the Trout Area

To further enhance our economies of scale, we intend to be aware of other acquisition opportunities in the area. Consistent with our strategy to improve our financial flexibility, we intend to make acquisitions utilizing either equity and/ or debt instruments. See subsequent notes re post March 31 developments

Develop Trout Area Assets

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

We also plan to acquire addition lands through the defined provincial posting process – as we do geological studies, additional targets within the overall seismic which we purchased covered areas is showing some opportunities – although higher risk, but higher rewards are possible and potentially to add production via the drill bit at an estimated find and development cost of $5 to $7 per barrel..

CREEnergy Project

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. Although delayed several times due to regulatory processes, this process is nearing completion.

We endeavor to engage with CREEnergy on a weekly basis through conference calls, status email and other written communication, monthly in person status meetings, and a continual dialogue to foster open communication.

At this time Cougar Energy is under negotiations to vend part of their mineral leases located within the TLE claim to CREEnergy for fair market value, to provide direct ownership and participation to the communities in the Oil and Gas mineral rights and associated operations. These discussions are reaching a mature level and legal is formalizing the documentation.

This proposed transaction will continue to provide positive growth for the relationship going forward and will provide cash flow opportunities for CREEnergy and thus the communities.

Due to delays in the land claim process, and in order to move Cougar Energy forward in the interim, Cougar looked to other opportunities in the Red Earth area. .

Lucy, Northern British Columbia

Cougar Energy, Inc is the operator and 80% working interest owner of a 1,920 acre lease located in Northeastern British Columbia. The Company 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 prospect is still in the early stages of delineation and no assurance can be given that its exploitation will be successful. Further appraisal work is required before these estimates can be finalized and commerciality assessed.

Depending upon commodity prices – the severe turn down in gas prices over the past year have made natural gas projects difficult to show returns on investment – especially high capital cost project such as the Horn River Basin – despite the very large reserves and recovery rates attributed to the Muskqua shales. The current $4-$5 gas prices limit the return this project in the short term and thus the financing availability.

The current intention is to perform the previously planned work programs for the license (as new information and financing becomes available, the plans may be revised). In lieu of obtaining our own financing, we are actively enlisting JV partners to move the project forward by way of divesting part of our interest.

Cougar Central Alberta Producing Properties

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

2 producing oil properties in the Crossfield and Alexander fields in Central Alberta.

100% working interest in the Crossfield property – 1 producing well with single well battery with approximately 5 barrels per day (bbl/d) net production – production continues to be stable with no capital commitment required.

55% working interest in the Alexander property – 1 shut in oil well with a single well battery, 1 suspended well. Expected production of approximately 10 bbl/d net production upon restarting shut in oil well after spring break up.

In Summary

The Company plans to aggressively develop and explore its newly acquired Cougar assets. A maintenance and development program was planned for the winter work season of 2009/2010 which was implemented and which attained the expected goals on a well by well basis, however we are now limited in some cases by pump sizes and after break up will start moving pumpjacks and downhole equipment to better take advantage of the workover programs performed in February and March. Addition maintenance programs will be initiated in post break up through into the following winter. 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.

Little Chicago – Northwest Territories

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

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 factors 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 monetize that asset through either divestiture and/or possibly renominating the prospect when conditions are more appropriate.

Province/Granlea – Southeast Alberta

No budget is assigned to this prospect.

UNITED STATES

New Mexico

Through its acquisition of Thunder, the Company acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Company’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.

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. A budget of $500,000 CAD has been assigned to this project in order to further define the reserves and the potential deliverability of those reserves in order to add definition to the engineering and economical prospect.

In Q1, 2010 the Company has made the strategic decision to allow some New Mexico properties to expire rather than continue to pay additional rental costs on lands which are not located in what has been identified as the most valuable project areas. These lands can be renominated for leases in the future if the Company determines they will be required.

FINANCIAL INFORMATION

Operating Results

Kodiak continues production on its developed assets which began in the fourth quarter of 2009. As there are no comparisons for this quarter year over year the information set forth is for this present quarter only, three months ending March 31, 2010.

Net Loss for the three months ended March 31, 2010 totaled $4,612,285 (March 31, 2009 - $500,535). The increase loss is mainly due to the one time asset write down of a un developed US property in the amount of $4,144,000.

General and administrative for the three months ended March 31, 2010 was $652,530 (March 31, 2009 - $493,462). The increase is due to the increased costs associated with being an operating entity.

Interest expense for the three months ended March 31, 2010 was $76,260 (March 31, 2009 - $211). The increased is as result of the company using banking debt to help finance daily operations. Prior to this period the Company did not have the any operating lines of credit.

Depletion, depreciation and accretion including ceiling test impairment write-downs includes the cost of depletion and depreciation relating to production from producing properties in the quater, ceiling test impairment write-downs and the cost of depreciation relating to office furniture and equipment. Costs attributable to certain US cost center properties were determined to be unsupportable and, as a result, asset write-downs of $4,144,000(March 31,2009 - Nil were recorded and included in this expense.

Financial Condition and Changes in Financial Condition:

The Company’s total assets have decreased to $29,017,258 as at March 31, 2010 from $31,943,001 as at December 31, 2009, and from $36,831,864 March 31, 2009. These decreases are sustainably due to write-downs of its unproved properties of $4,410,309. Total assets consist of cash and other current assets of $854,938 (December 31, 2009 - $296,153).

The Company has included in oil and gas properties evaluated and unevaluated properties. Evaluated properties net of accumulated depreciation, depletion and amortization was$5,239,357 (December 31, 2009 - $4,657,403l). Unevaluated properties decreased to $22,548,799 from $26,081,786 on December 31, 2009. The major difference write-down of undeveloped properties $4,410,309. There was requirement for a ceiling test write down for the period ending March 31, 2010.

Other assets increase marginally to $306,458 as of March 31, 2010 (December 31, 2009 - $296,153 3). The increase is due to the increase in deposit held by regulatory bodies for operational and environmental deposits.

Our total current liabilities increased $294,141 to $4,745,669 (December 31, 2008 - $4,451,528). The net increase is due to increases in accounts payable and current portions of long-term debt and a decrease in notes payable. Accounts payable and accrued liabilities increased to $3,046,835(December 31, 2009 - $2,548,661). The increase is due to increased work activity during the quarter and capital spending. Notes payable were paid out in the quarter and decreased to Nil at March 31, 2010(December 31, 2009 - $1,364,036) This was offset by an increase in the current portion of long term debt of $766,225.

We had long term liabilities of $3,315,282 (December 31, 2009 - $3,400,489). This decrease is due to the nature of payment term on the companys debt and the classification between current and long-term debt. Asset retirement obligations increased $65,295 for the quarter to $1,350,909 (December 31, 2009 - $1,285,614) The increase is a result of accretion expense of $ 24,032 (March 31, 2009 – nil) and actual costs incurred.

Liquidity and Capital Resources

The Company is in the process of raising additional financing in its Cougar Energy, Inc. subsidiary that will provide financing to carry out its business plan through 2010. See Subsequent Event Note 21 to the consolidated financial statements. Such additional financing will be required for the company’s 2009 planned activities. In the event that additional capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Company, or the Company’s interest in the subsidiary.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Company is exposed to market risk from changes 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’s revenues are derived from the sale of its crude oil and natural gas production. The prices for oil and gas remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company may enter into derivative financial instruments to manage oil and gas price risk.

The Company may utilize fixed price “swaps,” which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company might otherwise have received from any increases in commodity prices.

The Company may utilize price “collars” to reduce the risk of changes in oil and gas prices. Under these arrangements, no payments are due by either party as long as the market price is above the floor price and below the ceiling price set in the collar. If the price falls below the floor, the counter-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counter-party receives the difference from the Company.

Kodiak may purchase “puts” which reduce the Company’s exposure to decreases in oil and gas prices while allowing realization of the full benefit from any increases in oil and gas prices. If the price falls below the floor, the counter-party pays the difference to the Company.

The Company may enter into various agreements from time to time to reduce the effects of volatile oil and gas prices and does not enter into derivative transactions for speculative purposes. However, under certain circumstances some of the Company’s derivative positions may not be designated as hedges for accounting purposes The Company’s oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices. Declines in oil and gas prices reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). Declines in oil and gas prices can reduce the value of our oil and gas properties and increase impairment expense, as occurred in 2009.

We expect oil and gas price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.

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

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this report. They concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not 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.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)). Under the supervision and with the participation of our management, including our principal executive officer (CEO) and principal financial officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements will not be prevented or detected. Management identified the following material weaknesses during its assessment of our internal control over financial reporting as at December 31, 2008 and December 31, 2007.

SEGREGATION OF DUTIES AND ACCESS TO CRITICAL ACCOUNTING SYSTEMS

As at December 31, 2009, December 31, 2008 and December 31, 2007, management believes the Company’s Internal Control over Financial Reporting did not meet the definition of adequate control, based on criteria established by Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management identified a material weakness relating the segregation of duties among certain personnel who had incompatible responsibilities within all significant processes affecting financial reporting. We also had a material weakness resulting from our failure to implement controls to restrict access to financially significant systems or to monitor access to those systems, which resulted in conflicting access and/or inappropriate segregation of duties. These material weaknesses affect all significant accounts. In addition, the 2007 restatement issues discussed below demonstrated a need to engage additional personnel or outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP, to assist in income tax planning and compliance and a review of our Canadian and U. S. income tax provisions. As a result of these material weaknesses, management has concluded that internal control over financial reporting was not effective as at December 31, 2009.

REMEDIATION OF MATERIAL WEAKNESS IN INTERNAL CONTROL

During December, 2006 and the first half of 2007, the Company hired a Controller, a new CFO, a Vice-President, Operations and additional qualified personnel. The new staff and existing management have implemented new procedures and controls for many areas of the Company’s activities. During 2007, the Company initiated a review of its corporate

policies and procedures with the assistance of an outside consulting firm, with a goal of having the Company become fully SOX compliant by year end 2007. Additional policies and procedures have been implemented and others strengthened. Testing of such policies and procedures was completed in late 2007 and early 2008. In addition, the Company will endeavor to engage outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP. Beginning in 2008, the Company engaged an outside consulting firm to assist in income tax planning and compliance and beginning with our fiscal year ended December 31, 2008, to review our Canadian and U.S. income tax provisions.

As at December 31, 2009, the Company continues to have a material weakness relating to the segregation of duties among certain personnel and, as of that date, management believes that without engaging additional personnel estimated to cost a minimum of approximately $150,000 per annum, we cannot remedy such material weakness. Management believes such expenditures cannot be justified at this time when the Company is still in the early stage of operations and has just acquired proved reserves, production and cash flow. When sufficient cash flow is being generated, management will review its position. Management believes its controls and procedures related to its financial and corporate information systems are appropriate for a company of its size and mandate and, due to its internal expertise, is not dependent upon the inherent risks in external third party management of such systems. Our CFO retired on December 31, 2009, has joined the Board of Directors and continues to consult to the Company in a financial capacity and alleviate some of the segregation of duties and related weaknesses. The VP of Finance assumed the role of CFO ensuring a smooth transition.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal control over financial reporting during the fourth quarter ended December 31, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 4T. CONTROLS AND PROCEDURES

Not applicable

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is not presently a party to any litigation.

ITEM 1A. RISK FACTORS

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

Item 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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.