- 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, 2011

[ ] 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 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: 129,683,294 common shares, $.001 par value, as at May 11, 2011.

KODIAK ENERGY, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3

ITEM 1.	FINANCIAL STATEMENTS	3

	Condensed Consolidated Balance Sheets as of March 31, 2011 (unaudited) and December 31, 2010	3

	Condensed Consolidated Statements of Operations for the three months ended March 31, 2011 and 2010 (unaudited)	4

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2011 and 2010 (unaudited)	5

	Notes to Condensed Consolidated Financial Statements (unaudited)	6

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	26

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35

ITEM 4.	CONTROLS AND PROCEDURES	36

PART II.	OTHER INFORMATION	37

ITEM 1.	LEGAL PROCEEDINGS	37

ITEM 1A.	RISK FACTORS	37

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	37

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	37

ITEM 4.	REMOVED AND RESERVED	37

ITEM 5.	OTHER INFORMATION	38

ITEM 6.	EXHIBITS	38

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2011			2010
	(unaudited)
Assets
Current Assets:
Cash and short term deposits	$	75,871		$	18,735
Accounts receivable		872,686			585,637
Prepaid expenses and deposits		121,391			145,873
Total current assets		1,069,948			750,245

Other assets (Note 5)		321,456			313,247

Oil and natural gas properties, Full cost accounting (Note 3)
Developed properties		12,663,691			9,266,193
Less accumulated depreciation, depletion and amortization		(4,838,337	)		(3,493,865	)
Net		7,825,354			5,772,328
Undeveloped properties excluded from amortization		24,766,612			22,622,246
Furniture and fixtures, net		54,780			57,220
		32,646,746			28,451,794

Total assets	$	34,038,150		$	29,515,286

Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	4,039,441		$	2,054,919
Accrued liabilities		673,009			677,335
Operating line of credit (Note 6)		2,191,625			2,035,994
Current debt		913,492			839,060
Total current liabilities		7,817,567			5,607,308

Long-term liabilities (Note 7)		3,097,708			2,769,965

Asset retirement obligations (Note 8)		1,549,979			1,471,808

Total liabilities		12,465,254			9,849,081

Commitments and contingencies (Note 12)

Stockholders' equity
Preferred stock, par value: $0.001 per share; 10,000,000 shares authorized, -0- issued and outstanding		-			-
Common stock, par value $0.001 per share; 300,000,000 shares authorized; 129,683,294 and 119,683,294 shares issued and outstanding as of March 31, 2011 and December 31, 2010, respectively		129,683			119,683
Additional paid in capital		57,186,624			54,628,900
Accumulated comprehensive gain (loss)		96,120			(256,401	)
Deficit		(36,383,253	)		(35,237,407	)
Stockholders' equity attributable to Kodiak Energy, Inc.		21,029,174			19,254,775
Non controlling interest		543,722			411,430
Total stockholders' equity		21,572,896			19,666,205

Total liabilities and stockholders' equity	$	34,038,150		$	29,515,286

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements

KODIAK ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)

	Three months ended March 31,
	2011			2010
REVENUE:
Oil sales	$	719,793		$	725,393
Other		135			41
Total revenue		719,928			725,434

EXPENSES:
Operating		557,961			303,235
General and administrative		723,338			652,520
Depletion and depreciation		1,279,045			4,410,309
Total expenses		2,560,344			5,366,064

Net loss from operations		(1,840,416	)		(4,640,630	)

OTHER INCOME (EXPENSE):
Interest expense		(130,966	)		(76,260	)

Net loss before income taxes		(1,971,382	)		(4,716,890	)

Income taxes		-			-

Net loss		(1,971,382	)		(4,716,890	)

Non controlling interest		825,536			104,605

NET LOSS ATTRIBUTABLE TO KODIAK ENERGY, INC.	$	(1,145,846	)	$	(4,612,285	)

Loss per common share (basic and fully diluted)	$	(0.01	)	$	(0.04	)

Weighted average number of shares outstanding (basic and fully diluted)		127,618,077			110,407,186

Comprehensive loss:
Net loss	$	(1,971,382	)	$	(4,716,890	)
Foreign currency translation gain (loss)		352,521			1,210,833

Comprehensive loss:		(1,618,861	)		(3,506,057	)
Comprehensive loss attributable to non controlling interest		573,363			104,605

Comprehensive loss attributable to Kodiak Energy, Inc.	$	(1,045,498	)	$	(3,401,452	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements

KODIAK ENERGY, INC.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

	Three months ended March 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,145,846	)	$	(4,612,285	)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss from non controlling interest, net of tax		(825,536	)		(104,605	)
Depreciation and depletion		1,279,045			4,410,309
Amortization of debt discount		35,390			-
Stock based compensation		320,960			309,475
Interest expense charged to Notes payable		49,862
Working capital changes (Note 16)		1,717,629			170,545
Net cash provided by operating activities		1,431,504			173,439

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of oil and gas properties		(4,874,813	)		(696,773	)
Net cash used in investing activities		(4,874,813	)		(696,773	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Sale of common stock		1,380,000			-
Advances on the revolving line of credit		155,631			393,778
Proceeds from majority owned warrants exercised		1,265,627			-
Net proceeds from (repayments of) long term debt		706,840			155,316
Net cash provided by financing activities		3,508,098			549,094

Effect of foreign currency rate change on cash		(7,653	)		-

Net decrease in cash and cash equivalents		57,136			25,760

Cash and cash equivalents, beginning of period		18,735			2,058
Cash and cash equivalents, end of period	$	75,871		$	27,818

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	41,274		$	4,965
Taxes	$	-		$	-

The accompanying notes are an integral part of these unaudited condensed financial statements

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES

The accompanying condensed consolidated financial statements as of March 31, 2011 and for the three months ended March 31, 2011 and 2010 are unaudited. These financial statements have been prepared in accordance with the instructions to Form 10-Q, and therefore, do not include all the information necessary for a fair presentation of financial position, results of operations and cash flows in conformity with generally accepted accounting principles.

In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three months period ended March 31, 2011 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2011. The unaudited condensed consolidated financial statements should be read in conjunction with the consolidated December 31, 2010 financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “SEC”).

Basis and Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”). The Company was incorporated under the laws of the state of Delaware on December 15, 1999 under the name “Island Critical Care, Corp.” On December 30, 2004 the name was changed to “Kodiak Energy, Inc”. During the year ended December 31, 2009, the Company transitioned from a development stage enterprise to an operating company. The Company’s principal activity is in the exploration, development, production and sale of oil and natural gas.

The unaudited condensed consolidated financial statements include the accounts of the Company, three wholly-owned subsidiaries: Kodiak Petroleum ULC (“KULC”), an inactive Alberta company; Kodiak Petroleum (Montana), Inc. (“KPMI”), a Delaware company that operates Kodiak’s projects in New Mexico and Montana; and Kodiak Petroleum (Utah), Inc. (“KPUI”), an inactive Delaware company; and one majority- owned subsidiary, Cougar Oil and Gas Canada Inc. In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All significant inter-company transactions have been eliminated in consolidation.

Reverse Acquisition

In January 2010, Cougar Oil and Gas Canada ("COG"), formerly Ore-More Resources, Inc. entered into a stock purchase Agreement (the “Agreement”) with Cougar Energy, Inc, a majority-owned subsidiary of the Company (which we refer to as CEI) and CEI’s then shareholders whereby COG agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

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

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

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

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

b) On January 25, 2010, COG finalized a share purchase agreement between COG and the Company whereby COG purchased from the Company a total of 8,461,549 shares of the common shares of CEI held by the Company. The share purchase agreement called for COG to issue a total of 1.5 shares of its common stock for each share of CEI tendered by the Company, resulting in COG issuing a total of 12,692,324 shares of common stock. As further consideration for the acquisition of the CEI common shares, COG forgave all current indebtedness owed to COG by the Company and guaranteed by CEI, which was in the amount of $1,296,888. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of Ore-More Resources, Inc were cancelled.

Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of COG. Subsequently, on February 4, 2010, Ore-More Resources, Inc filed a Certificate of Amendment to its Certificate of Incorporation with the Registrar of Corporations in Alberta, Canada, changing the Company’s name to “Cougar Oil and Gas Canada, Inc.”.

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

Functional currency

The reporting currency of the Company is the United States dollar, while the functional currency is the Canadian dollar. When a transaction is executed in a foreign currency, it is re-measured into Canadian dollars based on appropriate rates of exchange in effect at the time of the transaction. At each balance sheet date, all recorded balances are adjusted to the reporting currency of the Company to reflect the current exchange rate. The resulting foreign currency transactions gains (losses) are included in general and administrative expenses in the accompanying consolidated statements of operations.

The cumulative translation adjustments are included in accumulated other comprehensive loss in the equity section of the consolidated balance sheet.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of unproved properties, future taxable income and related assets/liabilities, the collectability of outstanding accounts receivable, stock-based compensation expense, contingencies and the results of current and future litigation.

Oil and natural gas reserve estimates which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are 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.

The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, the creditworthiness of counterparties, interest rates, the market value of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income. Future changes in these assumptions may affect these significant estimates materially in the near term. The Company has also evaluated subsequent events for recording and disclosures, including assumptions used in its estimates.

Reclassification

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

Revenue Recognition

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

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

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

Cash and Cash Equivalents, and Concentrations of Credit Risk

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

Furniture and Fixtures

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

Segment Information

The Company applies Accounting Standards Codification subtopic Segment Reporting 280-10 (“ASC 280-10”). ASC 280-10 establishes standards for reporting information regarding operating segments in annual consolidated financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. ASC 280-10 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision making group, regarding how to allocate resources and assess performance. The information disclosed herein, materially represents all of the financial information related to the Company's principal operating segments.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of properties within a relatively large geopolitical cost center, in our case by country, are capitalized when incurred and are amortized as mineral reserves in the cost center as they are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs designated as unproven properties are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at March 31, 2011 and 2010. Unevaluated and undeveloped costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable country cost center. The Company has assessed for impairment of oil and natural gas properties for the full cost pool at March 31, 2011 and 2010 and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes is compared to (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues is based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test takes into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price is consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation has been disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities since inception through March 31, 2011. Application of the ceiling test is required for reporting purposes, and any write-downs are not reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

Impairment of long lived assets

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

Reserves

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

Fair Values

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

Comprehensive Income (Loss)

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

Net Loss per Share

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

Stock based compensation

The Company follows Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”) which requires that all share-based payments to both employees and non-employees be recognized in the income statement based on their fair values. The fair value of share-based compensation to employees 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.

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

Income Taxes

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SIGNIFICANT ACCOUNTING POLICIES (continued)

Flow-through Shares

From time to time 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.

Non-controlling Interests

We adopted the accounting standard for non-controlling interests in the consolidated financial statements as of January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the non-controlling owner.

Accounting for Changes in Ownership Interests in Subsidiaries

The Company’s ownership interest in a consolidated subsidiary may change if it sells a portion of its interest, or if the subsidiary issues or re-purchases its own shares. If the transaction does not result in a change in control over the subsidiary and it is not deemed to be a sale of real estate, the transaction is accounted for as an equity transaction. If the transaction results in a change in control it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the statement of operations. During the three months ended March 31, 2011, the Company’s ownership interest in Cougar Energy Inc. changed and such changes were accounted for as equity transactions. See Note 11 Non-Controlling Interest for a description of the transactions and the impact to the financial statements.

Accounting for Sales of Stock by a Subsidiary

The Company's majority owned subsidiary issued common shares in various transactions, which resulted in a dilution of the Corporation's percentage ownership in the Subsidiary. The Company accounted for the sale of the Subsidiary common shares in accordance with guidance related to equity transactions. The guidance allows for the election of an accounting policy of recording such increase or decreases in a parent's investment either in income or in equity. The Corporation adopted a policy of recording such gains or losses directly to additional paid in capital.

Recent Accounting Pronouncements

There were various updates recently issued by the Financial Accounting Standards Board, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's consolidated financial position, results of operations or cash flows.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 2 - GOING CONCERN MATTERS

These unaudited condensed 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. The Company is subject to a financial covenant regarding its working capital ratio that is adjusted to meet requirements within its credit facility. Continuation of the Company as a going concern is dependent upon obtaining sufficient working capital to finance ongoing operations and to provide for an adequate working capital ratio as determined by the credit facility. 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.

NOTE 3 - OIL AND GAS PROPERTIES

Major classes of oil and gas properties under the full cost method of accounting at March 31, 2011 and December 31, 2010 consist of the following:

	March 31, 2011			December 31, 2010
Proved properties, net of cumulative impairment charges	$	12,663,691		$	9,266,193
Unevaluated and Unproved properties		24,766,612			22,622,246
Gross oil and gas properties		37,430,303			31,888,439
Less: accumulated depletion, accretion and impairments		(4,838,337	)		(3,493,865	)
Net oil and gas properties	$	32,591,966		$	28,394,574

Unevaluated and Unproved Properties

The Company has certain unevaluated and unproved properties, valued at cost, that have been excluded from costs subject to depletion. These costs amounting to $24,766,612 and $22,622,246 as at March 31, 2011 and December 31, 2010, respectively, are subject to a test for impairment which is separate from the test applied to proved properties.

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

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

At March 31, 2011, a ceiling test was performed on the Company's properties subject to depletion. Costs of unproved properties aggregating $24,766,612 and future abandonment costs of $307,000 have been excluded from this test. This test disclosed that the carrying costs of the Company's depletable Canadian properties exceeded their net present value and consequently the Company recorded a $963,729 ceiling write-down during the three months ended March 31, 2011.

Included in the Company’s oil and gas properties are asset retirement obligations of $1,353,304 and $1,306,481, comprising both current and long term items as of March 31, 2011 and December 31, 2010, respectively.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 4 - ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	March 31, 2011		December 31, 2010
Non-operating Partner joint venture accounts	$	533,948	$	487,265
Government of Canada Goods and Services Tax Claims		242,352		17,778
Other		96,386		80,594
	$	872,686	$	585,637

During the period, the Company incurred costs relating to a significant development program which generated a large Goods and Services Tax receivable.

NOTE 5 - OTHER ASSETS

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

	March 31, 2011		December 31, 2010
Alberta Energy and Utility Board Drilling Deposit	$	47,850	$	46,519
Department of Energy Reclamation Deposit		516		503
British Columbia Oil and Gas Commission Deposit		273,090		266,225
	$	321,456	$	313,247

NOTE 6 - OPERATING LINE OF CREDIT

During the year ended December 31, 2010, the Company reached formal agreement with a Canadian bank for credit facilities. The credit facility is a revolving demand loan facility in the amount of Cdn$2,500,000 bearing an interest at prime plus 3.5% per annum. Under the terms of the Agreement, the credit facility is committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves. As at March 31, 2011, U.S $2,191,625 of the revolving line was drawn.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 7- LONG TERM AND SHORT TERM LIABILITIES

The Company has the following liabilities:

	March 31, 2011			December 31, 2010
Amount due to vendor of acquired properties present value of total amount due	$	3,790,222		$	3,951,337
Amount of Discount to be accreted in the future (at 7.5% annually - .0625% per month)		(366,293	)		(416,155	)
Present value of amount due		3,423,929			3,535,182
Convertible debenture, net of unamortized debt discount of $523,575		522,057			-
Other short term debt		15,893			25,762
Total indebtedness from the purchase of properties		3,961,879			3,560,944

Less current portion		(913,492	)		(839,060	)
Long-term portion		3,048,387			2,721,884

Funds advanced by partners for their share of a drilling deposit required to be lodged by the Company with the British Columbia Oil and Gas Commission (See Note 5) as security for future well abandonment and site restoration activities		49,321			48,081
Total	$	3,097,708		$	2,769,965

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

Due in 2011 in 12 monthly installments	$	864,423
Due in 2012 in 12 monthly installments		1,206,515
Due in 2013 in 12 monthly installments		1,387,492
Due in 2014 in 2 monthly installments		331,792
	$	3,790,222

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 three months ended March 31, 2011, non cash interest of $49,862 was recorded as interest expense in relation to the discount on the vendor acquired indebtedness.

Convertible Debenture

On February 25, 2011, the Company's majority owned subsidiary, Cougar Oil and Gas Canada, Inc ("Cougar") issued a $1,023,530 unsecured convertible debenture due eighteen months from issuance with interest at Bank of Canada Prime plus 3% per annum due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 7- LONG TERM AND SHORT TERM LIABILITIES (continued)

In accordance with ASC 470-20, the Company recognized an embedded beneficial conversion feature present in the debenture. The Company allocated a portion of the proceeds equal to the intrinsic value of that feature to additional paid-in capital. The Company recognized and measured an aggregate of $558,966 of the proceeds, which is equal to the allocated intrinsic value of the embedded beneficial conversion feature, to additional paid-in capital and a discount against the debenture. The debt discount attributed to the beneficial conversion feature is amortized over the debenture’s maturity period (eighteen months) as interest expense.

In connection with the placement of the debenture, the Company is contingently obligated to issue detachable warrants granting the holder the right to acquire shares of the Company’s common stock at $3.90 per share upon debenture conversion. The warrants, if issued, expire four years from the issuance. In accordance with ASC 470-20, the Company determined the allocated value attributable to the warrants in the amount of $464,565 and will recognize as a charge to interest expense upon issuance. The Company valued the warrants in accordance with ASC 470-20 using the Black-Scholes pricing model and the following assumptions: contractual terms of 4 years, an average risk free interest rate of 1.22%, a dividend yield of 0%, and volatility of 136.60%.

Amortization of $35,391 was recorded for three months ended March 31, 2011.

NOTE 8- ASSET RETIREMENT OBLIGATIONS

The Company’s financial statements reflect the provisions of Accounting Standards Codification Subtopic 410-20, Asset Retirement Obligations (“ASC 410-20”). ASC 410-20 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by ASC 410-20, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the Consolidated Balance Sheet. Periodic accretion of discount of the estimated liability is recorded, as appropriate, as an expense in the Consolidated Statement of Operations and is included in depletion, depreciation and accretion. The Company’s asset retirement obligations relate to all wells. The Company has recognized an asset retirement liability of $1,549,979 and $1,471,808 at March 31, 2011 and December 31, 2010, respectively.

At March 31, 2011, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,352,101 (December 31, 2010 - $3,227,980). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 14 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and an inflation rate of 2.5%.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 8- ASSET RETIREMENT OBLIGATIONS (continued)

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
Additions		36,666
Accretion		100,436
Retirements		(20,966	)
Foreign exchange gain (loss)		70,058
Asset retirement obligations, December 31, 2010		1,471,808
Additions		15,195
Accretion		27,657
Retirements		-
Foreign exchange gain (loss)		35,319
Asset retirement obligations, March 31, 2011	$	1,549,979

NOTE 9- 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 8,000,000 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, 2011
	Weighted average Exercise
	Price		Shares
Outstanding at beginning of period	$	0.50		5,405,000
Options granted		-
Options forfeited		0.45		(200,000	)
Outstanding at end of period		0.50		5,205,000
Exercisable at end of period	$	0.75		2,505,000

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

Significant option groups outstanding at March 31, 2011 and related weighted average price and life information as follow:

Range of Exercise Price		Number outstanding at March 31, 2011	Weighted Average remaining Contractual life		Weighted average Exercise Price		Exercisable Number outstanding at March 31, 2011		Exercisable Weighted average Exercise price
$	0.19-1.28	4,425,000		3.23	$	0.32		1,725,000	$	0.38
	1.29-2.28	680,000		0.64		1.41		680,000		1.41
	2.29-3.28	100,000		1.67		2.58		100,000		2.58
		5,205,000		2.86		0.50		2,505,000		0.75

Transactions involving options issued to employees are summarized as follows:

	Number of Shares			Weighted Average Price Per Share

Outstanding at December 31, 2009		6,060,000		$	0.57
Granted		300,000			0.19
Exercised		-
Canceled or expired		(955,000	)		0.85
Outstanding at December 31, 2010		5,405,000		$	0.50
Granted		-
Exercised		-
Canceled or expired		(200.000	)		0.45
Outstanding at March 31, 2011		5,205,000		$	0.50

Cougar Oil and Gas Canada Stock Option Plan

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

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

Outstanding						Exercisable
Number outstanding at March 31, 2011		Weighted Average remaining Contractual life		Weighted average Exercises Price (Cdn$)		Number outstanding at March 31 , 2011	Weighted average Exercise price
	3,262,500		2.79	$	0.144	2,175,000	$	0.144
	892,500		3.50	$	0.289	555,000		0.289
	35,000		4.00	$	2.02	-		-
	600,000		4.17	$	2.38	-		-
	50,000		4.54	$	1.40	-		-
	50,000		4.58	$	1.52	-		-
	45,000		4.67	$	1.83	-		-
	30,000		4.69	$	2.36	-		-
	450,000		4.71	$	2.92	-		-
	400,000		5.00	$	3.07
	5,815,000		3.42	$	0.87	2,730,000	$	0.174

Transactions involving options issued to employees are summarized as follows:

	Number of Shares			Weighted Average Price Per Share
Outstanding at December 31, 2009		-		$	-
Granted		1,260,000			2.47
Exercised		-			-
Canceled or expired		-
Outstanding at December 31, 2010		1,260,000			2.47
Granted		400,000			3.07
Transfers (see below)		4,455,000			0.18
Canceled or expired		(300,000	)		-
Outstanding at March 31, 2011		5,815,000		$	0.87

During the three months ended March 31, 2011, the Company granted 400,000 stock options with an exercise price of Cdn $3.07 per share expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:	-0-	%
Volatility	81	%
Risk free rate:	2.71	%

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

On January 1, 2011, Cougar Energy, Inc. merged with its parent, Cougar Oil and Gas Canada Inc. Both of the companies are Alberta corporations and were merged in a statutory amalgamation under Alberta corporate law. Upon that merger, and after giving effect to the Cougar Oil and Gas Canada/Cougar Energy Inc. share exchange at 1:1.5 and the subsequent 3:1 split of Cougar Canada Oil and Gas Canada Inc. shares, the 725,000 and 265,000 outstanding Cougar Energy, Inc stock options exercisable at $0.65 and $1.30 per share respectively shown above became 3,262,500 and 1,192,500 outstanding Cougar Oil and Gas Canada stock options exercisable at Cdn $0.144 and Cdn $.289 per share, respectively.

Kodiak Energy Inc. Warrants

During each of the years ended December 31, 2006 and 2010, 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		0.25
Issued Nov 4, 2010	$	0.50	Aug 15/12		4,776,108		1.38
Issued Dec 9, 2010	$	0.50	Aug 15/12		4,500,000		1.38
Issued Jan 17, 2011	$	0.34	Jan 16/12		10,000,000		4.80
	$	0.59			20,406,108		2.99

Transactions involving Kodiak Energy Inc. are summarized as follows:

	Number of Shares		Weighted Average Price Per Share (Cdn$)
Outstanding at December 31, 2009		1,130,000	$	3.50
Issued		9,276,108		0.50
Exercised		-		-
Canceled or expired		-
Outstanding at December 31, 2010		10,406,108	$	0.83
Issued		10,000,000		0.34
Exercised		-		-
Canceled or expired		-		-
Outstanding at March 31, 2011		20,406,108	$	0.59

During the three months ended March 31, 2011, in connection with the sale of the Company's common stock, the Company issued 10,000,000 warrants to purchase the Company's common stock at $0.34 per share expiring five years from the date of issuance.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 9- STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

Cougar Oil and Gas Canada Warrants

Warrants

The following table summarizes warrants outstanding and related prices for the shares of the Company’s common stock issued to shareholders at March 31, 2011:

Warrants Outstanding

Weighted Average

Warrants Exercisable

Remaining

Weighted

Number

Contractual

Average

Number

Average

Exercise Price (Cdn$)

Outstanding

Life (years)

Exercise price (Cdn$)

Exercisable

Exercise Price (Cdn$)

0.577

41,207

0.22

0.577

41,207

0.577

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

	Number of Shares			Weighted Average Price Per Share

Outstanding at December 31, 2009		-		$	-
Issued		6,223,506			0.33
Exercised		(2,014,848	)		0.29
Canceled or expired		-			-
Outstanding at December 31, 2010		4,208,658		$	0.35
Issued		-			-
Exercised		(3,823,170	)		(0.33	)
Canceled or expired		(344,281	)		(0.56 )
Outstanding at March 31, 2011		41,207		$	0.577

NOTE 10 - STOCKHOLDER’S EQUITY

The Company is authorized to issue 10,000,000 and 300,000,000 shares of $0.001 par value preferred and common stock, respectively. As of March 31, 2011 and December 31, 2010, the Company had nil preferred shares issued and outstanding and 129,683,294 and 119,683,294 shares of common stock, respectively.

NOTE 11- NON CONTROLLING INTEREST

A reconciliation of the non controlling loss attributable to the Company:

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 11- NON CONTROLLING INTEREST (continued)

Net loss Attributable to the Company and transfers (to) from non-controlling interest for the three months ended March 31, 2011 and 2010:

		2011			2010
Net loss	$	1,887,151		$	294,829
Average Non-controlling interest percentage		43.62	%		35.48	%
Net loss attributable to the non-controlling interest	$	825,536		$	104,605

The following table summarizes the changes in Non Controlling Interest from December 31, 2009 to March 31, 2011:

Balance, December 31, 2009	$	258,127
Transfer (to) from the non-controlling interest as a result of change in ownership		881,533
Foreign currency translation		21,874
Net loss attributable to the non-controlling interest		(750,104	)
Balance, December 31, 2010		411,430
Transfer (to) from the non-controlling interest as a result of change in ownership		705,655
Foreign currency translation		252,173
Net loss attributable to the non-controlling interest		(825,536	)
Balance, March 31, 2011	$	543,722

NOTE 12- COMMITMENTS AND CONTINGENCIES

Lease Commitments

As of March 31, 2011 and 2010, the Company had lease commitments for vehicles, office rent and office equipment. The following lease commitments for the years shown:

Amounts payable in:	March 31, 2011		March 31, 2010
2011	$	164,175	$	166,642
2012	$	218,217	$	162,337
2013	$	77,758	$	39,797

Cougar Oil and Gas Canada, Inc..

The Company relocated its offices in December 2009 and pays rent of approximately $14,000 per month until the lease expires in February 2013. The remaining lease commitments pertain to two trucks and a number of office computers. Rent expense for the three months ended March 31, 2011 and 2010 is $43,652 and $13,164, respectively.

Litigation

The Company is subject to other legal proceedings and claims, which arise in the ordinary course of its business. Although occasional adverse decisions or settlements may occur, the Company believes that the final disposition of such matters should not have a material adverse effect on its financial position, results of operations or liquidity. There was no outstanding litigation as of March 31, 2011.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

(UNAUDITED)

NOTE 13- FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

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

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

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

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

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

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

NOTE 14- RELATED PARTY TRANSACTIONS

For the three months ended March 31, 2011 and 2010, the Company incurred fees of $13,465 (March 31, 2010 - $9,681) charged by a Director and the former Chief Financial Officer. An amount of $10,079 was payable at March 31, 2011. The Company incurred charges of $30,771 by a Company owned and controlled by the chairman of the Company for management consulting services. An amount of $33,165 was payable on March 31, 2011. The Company incurred expenses of the wife of the chairman of the Company of $Nil for administration consulting services. A total of $1,559 was outstanding on March 31, 2011. 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.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2011

NOTE 15- 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:

	Three months March 31, 2011									Three months ended March 31, 2010
	U. S.			Canada			Total			U. S.			Canada		Total
Revenue, net of royalties	$	-		$	719,793		$	719,793		$	-		$	725,393	$	725,393
Net Loss attributable to Kodiak	$	(4,852	)	$	(1,138,119	)	$	(1,142,971	)	$	(4,148,064	)	$	(464,221)	$	(4,612,285	)
Capital Assets	$	7,132,102		$	25,514,644		$	32,646,746		$	7,130,970		$	20,724,892	$	27,855,862
Total Assets	$	7,147,494		$	26,890,656		$	34,038,150		$	7,136,824		$	23,474,176	$	30,611,000
Capital Expenditures	$	(524)		$	6,001,826		$	6,001,302		$	160		$	2,130,374	$	2,130,534

NOTE 16- CHANGES IN WORKING CAPITAL

	Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
Operating Activities:
Accounts Receivable	$	(287,049	)	$	(263,636	)
Prepaid Expenses and Deposits		24,482			(63,993	)
Accounts Payable		1,984,522			696,424
Accrued Liabilities		(4,326	)		(198,250	)
Total	$	1,717,629		$	170,545

NOTE 17- SUBSEQUENT EVENTS

On April 13, 2011, the Company's majority owned subsidiary, Cougar Oil and Gas Canada, Inc. ("Cougar") issued to an investor a $1,000,000 unsecured convertible debenture due eighteen months from issuance with interest at Bank of Canada Prime plus 3% per annum due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90.

On May 3, 2011, the Company's majority owned subsidiary, Cougar Oil and Gas Canada, Inc. ("Cougar") issued to an investor a $217,000 unsecured convertible debenture due eighteen months from issuance with interest at Bank of Canada Prime plus 3% per annum due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90.

In April, 2011, Cougar Oil and Gas Canada, Inc. closed an acquisition from a private company for certain properties, for consideration which mainly included Cougar assuming the abandonment liability for the properties (for which the vendor had approximately $631,500 on deposit with the ERCB) and forgiving an outstanding accounts receivable of approximately $2,500 from the private company. The properties include four producing non-operated CBM gas wells and associated gathering and production facilities located in Central Alberta with a net production of approximately 25 BOEPD, and three suspended cardium oil wells located in central Alberta with the potential to reactivate two of the wells during the summer of 2011for an estimated net production of 25bbl per day. The wells are also located in an area that has recently proven successful for horizontal cardium oil development. Also included in the purchase were five standing natural gas wells in central and southern Alberta and three thousand two hundred net acres of mineral rights adjacent to Cougar's oil producing Alexander property. The wells require additional work over and/or tie-in work and will be evaluated for development, farm-out or divestiture. The mineral rights include all P&NG rights and will be evaluated for oil production potential.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

Investors should 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

Canada

Through Kodiak’s majority owned subsidiary, Cougar Oil and Gas Canada, Inc., the Company’s focus is:

PLANS FOR GROWTH

Trout Operations Growth Plans

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

Field Optimization

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

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

During the last six months Cougar has been working on additional well reactivations in the Trout production field.

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

The 13-25 reactivation involved repairing a wellbore and pumpjack that had been shut in for over three years. The downhole work was successfully repaired but the pumpjack repair took longer due to time required to get the gear box repaired. A maintenance crew recently finished all of the repair work and the well is was put on production at approximately 25 bbls/day. A casing leak occurred 3 weeks after production was restored and the well has been shut in until a service rig can be mobilized after the spring breakup. Therefore the work required is expected to be completed during Q2.

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

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

Infill Drilling

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

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

In December of 2010, the company initiated licensing of 2 wells for an infill drilling program for Q1 2011. The Company drilled and completed a horizontal well on one of the locations during the first quarter and the well is currently pumping to clean up fluids that were pumped down hole during the drilling process.

The Company completed an extensive 3D program over the lands acquired in July 2010. The size of this 3D program coupled with the drill results will support additional drilling programs described below. See subsequent event notes

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

Cougar Trout HZ 102/10-21-089-03W5

Cougar finished drilling the horizontal Keg River oil well on March 20, 2011. The horizontal leg was successfully drilled in the top two (2) meters of a ten (10) meter thick Keg River zone and has approximately 400 meters of horizontal productive formation. Upon entering the Keg River formation there was an immediate loss of circulation and increase of wellbore gas indicating a substantial reservoir was encountered. Using electro-magnetic directional tools the Corporation was able to successfully steer the horizontal wellpath to the required endpoint.

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

During the horizontal leg, there was extensive loss of circulation and 50,000 bbls of water were lost to the formation. The well was completed and put on test with a portable hydraulic pump jack. As of filing, the well continues to recover drilling fluids, although fluid levels had climbed recently. Until a larger downhole pump is installed and larger volumes are pumped, it is not expected that the hydrocarbon rates of production will increase. This is typical of wells in this area and this formation.

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

Current Status:

The 102/10-21-89-3W5 horizontal well is currently pumping using a hydraulic pump jack installed onto the well head and the production is being stored in tanks and trucked to the main 12-22 battery. The hydraulic jack is limited to a maximum production rate of 30m3 per day with production currently made up of a mix of lost drilling fluids and new reservoir water with a measured salinity of 20.5% . (The expected field salinity is 24 to 28%). There has been an increase of gas with the production indicating some improved reservoir inflow. The pumping system currently installed on the well does not have the capability to produce enough fluid to draw down the fluid level and allow the oil to enter the wellbore. The high hydrostatic pressure reduces oil inflow, however this was the only equipment available in the area at the time of completion that could be installed prior to break up. The drill cuttings have been analyzed and as expected there is a strong dolomite composition in the horizontal leg. Historically we have found in this formation, that since a water molecule is much smaller than an oil molecule, water has the ability to enter the wellbore preferentially ahead of the oil resulting in reduced production rates.

History and Planning Summary:

The 3D seismic that was purchased in September 2010 was used to identify the structurally highest part of the targeted Keg River reservoirs in sections 21 and 22-89-3W5.

The Keg River formation does not appear to have a basic oil water contact but rather has oil and water in transition with the highest percentage of oil at the top of the formation and the highest percentage of water at the bottom of the formation.

Three vertical wells and one horizontal well were identified using the purchased 3D seismic.

There were two cored vertical wells at 16-21-89-3w5 and 10-21-89-3w5 that had good porosity but relatively poor permeability and production. The cores showed excellent oil concentration in the Keg River formation.

A horizontal well was planned to target the oil reserves which could not be effectively drained using the two original vertical wells.

The well target would be the Keg River formation and the horizontal leg was planned to run along the top of the structural trap.

It was anticipated that a horizontal well would be able to effectively produce the Keg River oil and would not require any well stimulation other than an acid wash to stimulate inflow.

After presenting our planning information to the engineering firm GLJ, they granted a reserves value of 218,000 barrels of recoverable oil with a discounted net present value of almost $5MM (NPV-10%).

Anticline (Structural) Trap:

An anticline is an example of rocks which were previously flat, but have been bent into an arch. Oil that finds its way into a reservoir rock that has been bent into an arch will flow to the crest of the arch, and get trapped (provided, of course, that there is a trap or cap rock above the arch to seal the oil in place).

Drilling Summary:

The 102/10-21-89-3W5 well was licensed in early February and the location was built as a padded dirt lease. A drilling rig was moved to location on February 19 and the well was spudded on February 21. Drilling continued until March 20 when the well was cased and the drilling rig was released from site. The total measured depth of the well is 2105m including a 410m horizontal leg. The horizontal leg was shortened due to the structure rapidly dropping off as we drilled SW off the 3D seismic data grid since the lower the structure the less chance of producing oil.

The drilling ran into several significant problems resulting in the total cost exceeding the budgeted amount by approximately 30%. The lease construction had to be built as a dirt pad rather than a planned winter lease due to the drilling being pushed back to very end of the winter season, which also meant delays in licensing and difficulty in obtaining a rig during the busy season. Therefore there was little choice in the selection of the drilling rig and we had to accept an undersized rig that had difficulty in drilling the larger surface hole required. The drilling company and some of the service providers used some inexperienced crews, due again to the busy winter drilling season, that resulted in delays in performing the drilling operations. This affected most companies in the area and they also experienced delays and cost overruns as a result. More problems occurred during drilling into the Muskeg salt formation building an angle towards the planned 90 degree horizontal leg. Drilling rates were slow which was compounded by an unexpected complete loss of drilling fluids in the horizontal leg. An estimated 50,000bbls of water was lost drilling the horizontal leg. The directional equipment used included a gamma signal which verified formation tops. Drill cuttings and the gamma ray data confirmed the horizontal leg was drilled in the Keg River formation and the leg was always within 1.5m of the formation top (structurally highest part of the reservoir). The anticipated severe lost circulation in the Wabamun formation was effectively isolated with the planned bypass casing string.

Completion Summary:

Tubing was run into the horizontal leg and swabs were pulled from various spots in the horizontal leg to clean up any near wellbore damage. The tubing was landed at approximately 1000m and the pump and rods were run in the hole and the well was put on production. Produced fluids are stored in two 400bbl tanks and trucked to the main 12-22 battery.

Anticipated Operations:

The key element to increasing production rate is increasing the pressure drawdown of the reservoir by reducing the back pressure imposed by the production system. Currently the pumping system installed on the horizontal well cannot produce enough fluid and the fluid level/hydrostatic pressure in the wellbore is too high reducing oil production. Once the lease conditions improve (dry up) an electric submersible pump (ESP) will be installed in the well to produce a higher volume of fluid. A temporary surface flow line will be used to transport the produced fluid to the main 12-22 battery, to better evaluate the potential of the well. To reduce operating costs the well will be shut in to monitor pressures until the ESP can be installed. Regular pump offs will be continued to test inflow using the hydraulic pump jack. During the drilling operations the water which was lost to the formation effectively swept all the hydrocarbons away from the wellbore and it will take time to migrate back to the horizontal wellbore. However, there has been an increase in produced gas seen in early May indicating the wellbore continues to clean up. Coupled with the increase in fluid level, we believe that hydrocarbon is migrating into the well bore, however with the low volume pump we cannot fully test that concept.

Future Horizontal wells:

The 102/10-21-89-3W5 well was planned to efficiently produce a reservoir that had good porosity and oil content and poorer permeability. The better than expected reservoir quality resulted in the lost circulation in the Keg River. Horizontal drilling is still an effective way to produce this reservoir but future wells should be done using underbalanced drilling techniques

3D Seismic Program

Cougar has completed the initial review of the processed 3D seismic data that was acquired in January/February 2011. The seismic data confirms the multi-well vertical and horizontal development potential of the existing Keg River and Granite Wash oil pools but the 3D seismic also identified several new undeveloped oil reservoirs. The development drilling locations are key to increasing production and cash flow and the new undeveloped reservoirs can add significant reserves for the company to pursue. The Corporation is finalizing the locations for the next drilling program and expects to begin the permitting process by the end of May 2011.

The announced first stage five (5) well drilling program was selected after an extensive review of the 3D seismic data, the regional and local geological mapping, the core data and the well performance of the existing regional wells. All of the current targets are vertical locations with new potential reservoirs identified with the seismic. Of the 15 locations, 7 are targeting new reservoirs and the balance are development wells of existing reservoirs.

Additional Development

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

(a)

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

(b)

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

(c)

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

Continued Development of the Trout Area through Systematic Operational Controls

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

Consolidate the Trout Area

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

Develop Trout Area Assets

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

The First Nation Joint Ventures

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

Current Status

In June of 2010, CREEnergy defaulted on its agreements with Cougar Oil and Gas Canada, Inc. and Cougar terminated any funding at that time. Cougar had met all the commitments and terms required by the agreements and that was acknowledged by CREEnergy but CREEnergy could not deliver the leases as promised. Cougar continued to work to find a solution with CREEnergy, but as of yearend, discussions had broken down. Once Cougar became aware of the default of CREEnergy, Cougar opened negotiations directly with the Peerless Trout First Nation and has continued on with that process since. We have established a good working dialogue and created employment. In the 2011 Q1 Trout 3D seismic program Cougar became a major employer of local Peerless Trout Lake First Nation contractors and laborers for the duration of that project. We continue to work with the Chief and Council toward formalizing a Joint Venture. Cougar has commenced recourse against CREEnergy to recover funds advanced for the agreements.

We have tendered several business models to the communities. We intend on developing the relationship and the opportunities to the joint benefit of both Cougar and the communities of Peerless/Trout Lake in a way that respects their heritage, the land and the environment.

Northern Alberta – First Nations Joint Ventures:

	•	Approximately 75,000 gross acres for access and development inside the land claim
	•	Approximately 90,000 gross acres for development outside the land claim in an identified 2 mile perimeter currently tendered as Joint Venture – Cougar 85% and operator

–

Light crude and natural gas prospects

Project Status:

	•	Negotiations are underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.
	•	In Parallel - Develop Joint Venture agreement to acquire, explore, develop and operate adjacent lands to the benefit of both Cougar and the Peerless Trout First Nation – Native Joint Ventures have priority with the province over other industry and thus reduced competition for a Cougar/Peerless Trout First Nation JV.

Operating Plan – 2011/2012:

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

	•	Execute similar maintenance programs on existing wells as Trout properties
	•	Acquire additional lands adjacent to the land claim in a Joint Venture structure (anticipated model is 85/15 shared ownership).

Lucy, British Columbia

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

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

Manning Heavy Oil Project

On February 14, 2011, Cougar completed negotiations on a two section heavy oil farm-in with a private company in the Manning area of north western Alberta. The farm-in includes a commitment for Cougar to drill one well to a minimum contract depth of 500m by the end of Q3, 2011 in order to earn a 100% working interest. Upon successful completion of the farm-in, the private company retains a 3% royalty interest on the two sections. Cougar has completed the initial review of this farm-in acreage and selected two possible drilling locations for the commitment well.

The permitting process has started and we are targeting a Q3, 2011 drilling program for this project. Cougar will earn 100% working interest in 1280 acres of land prospective for Heavy Oil after drilling this well.

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

for the prospect.

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

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

Cougar has also continued the preparation for the Manning area heavy oil farm-ins. The geological review has included core and log analysis and detailed geological mapping.

We are evaluating trade seismic for the second Manning farm-in announced on March 17, 2011. This will be the first step in the earning process for this project. Cougar has entered into a two phase farm-in agreement with TAMM which will ultimately result in Cougar earning a 50% working interest in approximately 47 sections or 30,000 acres of heavy oil prospective lands in the Manning area. This is in the same area as the 1280 acre farm in which the planned well is expected to be drilled in Q3, 2011

The activity level is rapidly changing in this area, with increased recent interest demonstrated by the land sales in April that resulted in over 148,000 acres in the immediate or adjacent area and an additional 130,000 acres close by being leased on 15 year leases for over $6 million.

Summary

The Company plans to develop and optimize its assets in Alberta and British Columbia as the primary focus. Due to the strength of the crude oil commodity prices Cougar, the Company’s subsidiary, will focus on the development of the crude oil properties over natural gas. A maintenance and development program focusing on low risk work has been prepared and is being implemented, as capital is available. The Company will also continue preparing for a planned five well drilling program on the Trout Properties and the one well drill and test for the Manning Farm in for Q3/Q4 2011. This will be followed up with subsequent drilling programs on the Trout Properties, and coring programs on the Manning Properties for winter of 2011/2012.

Cougar Oil and Gas Canada, Inc.

At this time, due to various financing activities of Cougar Oil and Gas Canada, Inc., Kodiak owns about 60% of the outstanding stock of Cougar. Kodiak also provided a $900K note for drilling purposes to Cougar for the 2011 winter drilling program. Kodiak expects to have the debt repaid plus interest and will retain a 1% Gross Overriding Royalty on the production which will produce some cash flow for G&A purposes.

Little Chicago – Northwest Territories

The Mackenzie Valley Pipeline project has been approved by various levels of Government in Canada – with a large amount of qualifications as to social and environmental commitments by the construction and operating companies. However, the license holders of the pipeline continue to delay any commitment for the construction of the pipeline until sometime in the future.Without a firm date, the governmental deadline for the commitment seemingly is being ignored.

The recent disaster in the Gulf of Mexico with the uncontrolled release of oil for extended periods into the ocean and the delays in drilling a relief well, has caused the Canadian regulatory bodies to review drilling programs in sensitive areas of the Canadian North and we believe that the Little Chicago project will face new substantial environmental regulations, insurance requirements and a dramatic increase in costs for the drilling and production of oil in any area close to the Mackenzie River. The potential for barging oil has probably been eliminated due to the environmental risks.

Thus, even with oil pricing approaching 2007/2008 levels, the projected costs for drilling an oil well and the probable stranding of the production until there is a pipeline make it difficult to project an economic return on investment for the Little Chicago project.

All of the majors have ceased exploration activity in the area during the past two winters, however there are some indications of renewed activity with new land postings for the July 2011 land sale. We continue to project that we will be able to monetize the seismic acquired in 2006 and 2007.

We 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 re-nominating the prospect when conditions are more appropriate.

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 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.

As the price of oil approaches $100/bbl on a sustained basis, we believe there will be renewed activity in the Permian Basin of SW Texas – with the resultant increase in enhanced recovery projects with a need for CO2 for that stimulation. However there have been several large projects that were in process of construction at the time of the recession which have come on line and the overall CO2 prices are still depressed due to lack of overall demand and uncertainty due to no clear plan from the governments as to greenhouse gas policies as they would relate to these type of projects.

Without the ability to obtain a long term contract for our product for at least 50% of the minimal facility capacity – it is currently unfeasible to finance the $25 million estimated facility. However as oil prices stabilize, and as the excess CO2 capacity is used up, and if the regulators finalizes a greenhouse gas policy that reflects regional economics – we believe that there is still an opportunity to profitably exploit these technologies. The leases have 5 years without any further development before expiry. We are assessing releasing of the lands that are located the farthest from the Sheep Mountain Pipeline. Thus reducing rentals for these lands in which development would have the longest timeline.

Kodiak has entered into a Farmout Agreement with a private company to develop the deeper rights of Kodiak’s approximate 30,000 gross acres of oil and gas rights in NE New Mexico. Kodiak retains the rights to the CO2 and Helium. The transaction anticipates additional seismic work and/or drilling of a number of wells on the Farmout acreage on or before June 1, 2011. The Farmee will earn 100% of pre-selected, semi-contiguous 6-section blocks for each 2000’ well drilled until their continuous option or right to earn ceases. Farmor will retain a convertible overriding royalty of 7.5% on Helium and 5% on balance of rights (no deductions) on the test well blocks and a 25% potential working interest in an Area of Mutual Interest opportunity. There is a provision for a drop fee in the event of default on the part of the Farmee. We retain the CO2 rights on the lands.

OTHER PROJECTS

Kodiak management continues to keep costs at a minimum by controlling G&A where ever possible and thus reducing requirements for financing. We have been working to find new projects, both domestic and international, that fit our current situation where we can add value with minimal capital commitments, with specific project deliverables and timelines.

FINANCIAL INFORMATION

Financial Condition and Changes in Financial Condition:

The Company has a working capital deficit of $6,747,619 at March 31, 2011, which has increased by $1,890,556 from $4,857,063 at December 31, 2010. Approximately $3.6 million of the working capital deficit at March 31, 2011 relates to supplier debt (December 31, 2010 – approximately $2.0 million), while the remainder relates to debts that are secured by the oil and gas assets, and related party amounts. The Company is working to reduce the working capital deficiency through equity and convertible debt financing and asset acquisitions.

The Company’s total assets have increased to $34,038,150 as at March 31, 2011 from $29,515,286 as at December 31, 2010. This increase is primarily due to the costs associated with the drilling of a horizontal well and a 3D seismic program during the quarter ended March 31, 2011. Total current assets consist of cash and other current assets of $1,069,948 (December 31, 2010 - $750,245).

The Company has included in oil and gas properties both developed and undeveloped properties. Developed properties net of accumulated depreciation, depletion and amortization was $7,825,354 (December 31, 2010 - $5,772,328). Undeveloped properties increased to $24,766,612 from $22,622,246 on December 31, 2010. The increase in capitalized cost of developed properties was mainly due to drilling of a horizontal well during the quarter. Increases in undeveloped properties in the quarter were primarily the result of a 3D seismic program that was completed in the Trout area. There was a requirement for a ceiling test write down for the period ending March 31, 2011 of $963,729.

Other assets increased marginally to $321,456 as of March 31, 2011 (December 31, 2010 - $313,247). The increase is due to currency translations from Canadian to United States dollars.

Our total current liabilities increased $2,210,259 to $7,817,567 (December 31, 2010 - $5,607,308). The net increase is due primarily to increases in our trade accounts payable. Accounts payable and accrued liabilities increased to $4,712,450 (December 31, 2010 - $2,732,254). The increase is due to increased work activity during the quarter and capital spending. Our current debt increased to $3,105,117 (December 31, 2010 - $2,875,054).The increase is caused by an increase in our operating line and current portions of long term debt.

We had long term liabilities of $3,097,708 (December 31, 2010 - $2,769,965). This increase is due to added borrowing of $1,023,530 of unsecured convertible debenture net with reductions in existing debt. Asset retirement obligations increased by $78,171 for the three months ended March 31, 2011 to $1,549,979 (December 31, 2010 - $1,471,808). The increase is a result of accretion expense of $27,657 (March 31, 2010 – $25,792), asset retirement obligation additions of $15,195 (March 31, 2010 – nil), and foreign exchange amounts of $35,319 (March 31, 2010 - $39,503).

Liquidity and Capital Resources

On February 25, 2011, the Company's majority owned subsidiary, Cougar Oil and Gas Canada, Inc ("Cougar") issued a $1,023,530 unsecured convertible debenture to investors due eighteen months from issuance with interest at Bank of Canada Prime, plus3% per annum, due upon maturity. The debenture is convertible at any time prior to maturity, at the holder’s option, into shares of Cougar common stock at $3.00 per share. In the event of a conversion election by the holder, the holder will receive one warrant for each share received, exercisable four years from issuance with an exercise price of $3.90

Our registered independent certified public accountants have stated in their report dated April 13, 2011, that we are dependent upon management's ability to develop profitable operations and raise additional capital. These factors among others may raise substantial doubt about our ability to continue as a going concern.

The Corporation has used in the past and expects to use a variety of sources of funding to finance its acquisitions and capital development and exploration programs for 2011, including financing based on cash flow, specific debt instruments for discrete projects, vendor financing, and equity and debt financing.

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’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 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, 2009.

SEGREGATION OF DUTIES AND ACCESS TO CRITICAL ACCOUNTING SYSTEMS

As at December 31, 2009, management believed 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 affected 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 concluded that internal control over financial reporting was not effective as at December 31, 2009. Management feels that these material weaknesses have been remedied during 2010 and were fully remedied by December 31, 2010 as set out in the following section “Remediation of Material Weakness in Internal Control”.

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.

During 2010, the Company engaged the services of additional personnel on a consulting basis who together are providing an additional level of review and governance with respect to the preparation and review of the Company’s quarterly and annual consolidated financial statements. Management believes that this additional level of control procedures was in place by December 31, 2010 and was operating effectively to remedy the material weakness relating to the segregation of duties among certain personnel that was previously reported. 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 from January, 2007 to December, 2009 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 at that time and was CFO until March 4, 2011 at which date, due to health reasons, he resigned as CFO and was retained as Business Development Manager on a consulting basis. A new CFO was hired effective March 4, 2011.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal control over financial reporting during the first quarter ended March 31, 2011 other than the finalization of the remediation of the weakness in internal control referred to above, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. Litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. Except as described below, we are currently not aware of any such legal proceedings that we believe will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.

ITEM 1A. RISK FACTORS

Not applicable.

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

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. Removed and reserved

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

32.2 - 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.