- Quarterly Report (10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2010

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

For the transition period from ____________ to_____________

Commission file number 333 - 38558

KODIAK ENERGY, INC .

(Exact name of registrant as specified in its charter)

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

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

(Address of principal executive offices - Zip code)

(403) 262-8044

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___

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

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

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

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

Check whether the registrant filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes X No

APPLICABLE ONLY TO CORPORATE ISSUERS

State the number of shares outstanding of each of the registrant's classes of common equity, as of the latest practicable date: 110,407,186 common shares, $.001 par value, as at November 22, 2010.

KODIAK ENERGY, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3

ITEM 1.	FINANCIAL STATEMENTS	3

	Condensed Consolidated Balance Sheets as of September 30, 2010 (unaudited) and December 31, 2009	3

	Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009 (unaudited)	4

	Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009 (unaudited)	5

	Notes to Condensed Consolidated Financial Statements (unaudited)	6

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION	22

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	31

ITEM 4.	CONTROLS AND PROCEDURES	32



PART II.	OTHER INFORMATION	33

ITEM 1.	LEGAL PROCEEDINGS	33

ITEM 1A.	RISK FACTORS	33

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	33

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	34

ITEM 4.	REMOVED AND RESERVED	34

ITEM 5.	OTHER INFORMATION	34

ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K	34

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK ENERGY, INC.
CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2010			2009
	(Unaudited)			(Audited)
Assets
Current Assets:
Cash and short term deposits	$	56,222		$	2,058
Accounts receivable		600,181			403,907
Prepaid expenses and deposits		150,137			151,390
Total current assets		806,540			557,355

Other assets		302,652			296,153

Oil and natural gas properties, Full cost accounting (Note 3)
Evaluated properties		8,700,860			6,823,400
Less accumulated depreciation, depletion and amortization		(3,156,520	)		(2,165,997	)
Net		5,544,340			4,657,403
Undeveloped properties excluded from amortization		22,188,364			26,081,786
Furniture and fixtures, net		60,173			64,862
		27,792,877			30,804,051

Total assets	$	28,902,069		$	31,657,559

Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	3,145,634		$	2,267,139
Accrued liabilities		275,464			281,522
Operating line of credit (Note 4)		1,443,149			-
Note payable (Note 5)		-			1,364,036
Current debt (Note 5)		1,254,143			538,831
Total current liabilities		6,118,390			4,451,528

Long-term liabilities (Note 5)		2,879,699			3,400,489

Asset retirement obligations (Note 6)		1,402,540			1,285,614

Total liabilities		10,400,629			9,137,631

Commitments and Contingencies (Note 11)

Equity (Note 7 & 8)
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; 110,407,186 shares issued and outstanding as of September 30, 2010 and December 31, 2009		110,407			110,407
Additional paid in capital		51,535,567			50,851,469
Accumulated comprehensive gain (loss)		642,596			(416,905	)
Accumulated deficit		(34,009,668	)		(28,283,170	)
Stockholders' equity attributable to Kodiak Energy, Inc.		18,278,901			22,261,801
Non controlling interest (Note 9)		222,539			258,127
Total equity		18,501,440			22,519,928

Total liabilities and equity	$	28,902,069		$	31,657,559

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

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

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009
REVENUE:
Oil sales	$	770,674		$	-		$	2,435,939		$	-
Other		501			-			4,078			-
Total revenue		771,175			-			2,440,017			-

EXPENSES:
Operating		353,785			4,621			1,128,551			6,793
General and administrative		648,014			658,871			1,928,735			1,506,760
Depletion and depreciation		489,713			363,156			5,270,976			16,407,480
Interest		84,913			-			247,266			304
Total expenses		1,576,425			1,026,648			8,575,528			17,921,337

Net loss from operations		(805,250	)		(1,026,648	)		(6,135,511	)		(17,921,337	)

OTHER INCOME (EXPENSE):
Gain on settlement of debt		-						72,657
Gain (loss) on disposal of assets		897			-			897			(2,164	)
Interest income		311			44			1,103			967

Net loss before income taxes		(804,042	)		(1,026,604	)		(6,060,854	)		(17,922,534	)

Income taxes		-			-			-			-

Net loss		(804,042	)		(1,026,604	)		(6,060,854	)		(17,922,534	)

Non controlling interest		87,916			31,024			334,355			46,866

NET LOSS ATTRIBUTABLE TO KODIAK ENERGY, INC.	$	(716,126	)	$	(995,580	)	$	(5,726,498	)	$	(17,875,668	)

Loss per common share (basic and fully diluted) (Note 10)	$	(0.01	)	$	(0.01	)	$	(0.05	)	$	(0.16	)

Weighted average number of shares outstanding (basic and fully diluted)		110,407,186			110,023,998			110,407,186			110,023,998

Comprehensive loss:
Net loss	$	(804,042	)	$	(1,026,604	)	$	(6,060,854	)	$	(17,922,534	)
Foreign currency translation gain (loss)		430,303			1,207,958			1,059,501			5,141,416

Comprehensive loss:		(373,739	)		181,354			(5,001,353	)		(12,781,118	)
Comprehensive loss attributable to non controlling interest		87,916			31,024			334,355			46,866

Comprehensive loss attributable to Kodiak Energy, Inc.	$	(285,823	)	$	212,378		$	(4,666,998	)	$	(12,734,252	)

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

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

	Nine months ended September 30,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,060,854	)	$	(17,922,534	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and depletion		5,270,976			16,405,480
Amortization and accretion		236,254			-
Stock based compensation		566,190			488,686
Gain on settlement of debt		(72,657	)		-
Loss on disposal of fixed assets		-			2,164
Working capital changes (Note 15)		625,415			196,015
Net cash provided by (used in) operating activities		565,325			(830,189	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of fixed assets		(2,213,925	)		(1,584,478	)
Disposal of other assets		-			706
Net cash used in investing activities		(2,213,925	)		(1,583,772	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Shares issued		-			(188,757	)
Advances on the revolving line of credit		1,443,149			1,030,819
Non controlling interest contribution		-			416,192
Net proceeds from long term debt		173,473			1,266,259
Net cash provided by financing activities		1,616,622			2,524,513

Effect of foreign currency rate change on cash		86,142			(179,849	)

Net increase (decrease) in cash and cash equivalents		54,164			(69,297	)

Cash and cash equivalents, beginning of period		2,058			75,175
Cash and cash equivalents, end of period	$	56,222		$	5,878

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	-		$	304
Taxes	$	-		$	-

Supplemental disclosures of non-cash investing and financing activities:

Cougar stock issued of Cougar Oil and Gas Canada, Inc. to acquire non controlling interest in Cougar Energy, Inc.	$	366,475		$	-
Effect change in ownership interest in majority owned subsidiary	$	129,956
Disposition of non-controlling interest in Cougar Energy, Inc.	$	50,200

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIE S

General

The accompanying condensed consolidated financial statements as of September 30, 2010 and for the three and nine months ended September 30, 2010 and 2009 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 and nine month periods ended September 30, 2010 are not necessarily indicative of the results that may be expected for the fiscal year ending December 31, 2010. The unaudited condensed consolidated financial statements should be read in conjunction with the consolidated December 31, 2009 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”), a Delaware company and holding company holding the shares of Kodiak Petroleum (Montana), Inc.; and one majority- owned subsidiary, Cougar Oil and Gas Canada 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 CEI 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 the 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 shall be the 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, the COG issued a total of 3,980,775 shares of the common stock of its common stock to the Vendors and an equal number of warrants, entitling the holders to exercise a total of 5,348,085 warrants. The warrants have the following exercise prices and expiry dates:

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIE S (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 the 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 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 $1,296,889. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Ore-More Resources, Inc were cancelled.

Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of the COG. Subsequently, on February 4, 2010, the 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 the 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 the Ore-More Resources, Inc is the legal acquirer rather than a business combination. The 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 are those of CEI from its date of inception on November 21, 2008.

Functional currency

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

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

Estimates

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

Reclassification

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIE S (continued)

Revenue Recognition

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

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

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

Cash and Cash Equivalents, and Concentrations of Credit Risk

Cash and cash equivalents represent cash in banks. The Company considers any highly liquid debt instruments purchased with a maturity date of three months or less to be cash equivalents. The Company’s accounts receivable are concentrated among entities engaged in the energy industry, within Canada 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 a straight-line basis over estimated useful lives of five years. Repair and maintenance costs are charged to expense as incurred while acquisitions are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of property, plant and equipment are recorded in the period incurred. The net book value of the property, plant and equipment that is retired or sold is charged to accumulated depreciation and amortization, and the difference is recognized as a gain or loss in the results of operations in the period the retirement or sale transpires.

Segment Information

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

SEPTEMBER 30, 2010

(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIE S (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, and are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs designated as unproven properties are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at September 30, 2010 and 2009. Unevaluated and undeveloped costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable country cost center. The Company has assessed the impairment for oil and natural gas properties for the full cost pool at September 30, 2010 and 2009 and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes is compared to (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues is based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test takes into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price is consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities since inception through September 30, 2010. Application of the ceiling test is required for reporting purposes, and any write-downs are not reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.

Reserves

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

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIE S (continued)

Impairment of long lived assets

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

Fair Values

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

Comprehensive Income (Loss)

The Company adopted Statement of Accounting Standards Codification subtopic 220-10, Comprehensive Income (“ASC 220-10”) ”. ASC 220-10 establishes standards for the reporting and displaying of comprehensive income and its components. Comprehensive income 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 has adopted Accounting Standards Codification subtopic 260-10, Earnings Per Share (“ASC 260-10”) specifying the computation, presentation and disclosure requirements of earnings per share information. Basic loss per share has been calculated based upon the weighted average number of common shares outstanding. Stock options and warrants have been excluded as common stock equivalents in the diluted loss per share because their effect is anti-dilutive on the computation.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIE S (continued)

Stock based compensation

Effective for the year beginning January 1, 2006, the Company has adopted Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”). The Company made no employee stock-based compensation grants before December 31, 2005 and therefore has no unrecognized stock compensation related liabilities or expense unvested or vested prior to 2006.

As more fully described in Note 7 below, the Company granted equity based compensation over the years to employees of the Company under its equity plans. The Company granted non-qualified stock options to purchase 5,505,000 shares of common stock of the Company and 1,555,000 (net of cancellations of 125,000) of the Company’s majority-owned subsidiary, Cougar Oil and Gas Canada since inception through September 30, 2010, respectively, to employees and directors of the Company under the Employee Retention Plan.

As of September 30, 2010, there were outstanding employee stock options to purchase 7,060,000 shares of common stock, 2,580,003 shares of which were vested.

Stock-based compensation expense in connection with stock options granted in the aggregate amount of $566,190 and $488,686 was charged to operations for the nine-month period ended September 30, 2010 and 2009, respectively. There was no grant of stock based compensations during the quarter ended September 30, 2010.

Recent accounting pronouncements

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

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

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

There were various other updates recently issued, 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.

The Company has evaluated and included subsequent events through the filing date of this form 10-Q.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

2. GOING CONCERN MATTERS

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

3. OIL AND GAS PROPERTIES

Major classes of oil and gas properties under the full cost method of accounting at September 30, 2010 and December 31, 2009 consist of the following:

	September 30, 2010		December 31, 2009
Proved properties, net of cumulative impairment charges	$	8,700,860	$	6,823,400
Unevaluated and Unproved properties		22,188,364		26,081,786
Gross oil and gas properties		30,889,224		32,905,186
Less: accumulated depletion, accretion and impairments		3,156,520		2,165,997
Net oil and gas properties	$	27,732,704	$	30,739,189

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 $22,188,364 and $26,081,786 as at September 30, 2010 and December 31, 2009, respectively are subject to a test for impairment which is separate from the test applied to proved properties.

Included in the Company’s oil and gas properties are asset retirement obligations of $1,265,473 and $1,285,614, comprising both current and long term items as of September 30, 2010 and December 31, 2009, respectively.

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

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

At September 30, 2010, a ceiling test was performed on the Company's properties subject to depletion. Costs of unproved properties aggregating $22,188,364 and future abandonment costs of $310,010 have been excluded from this test. This test disclosed that the carrying costs of the Company's depletable Canadian properties did not exceeded their net present value and consequently no ceiling write-down was required.

Unproved Properties

During the nine months ended September 30, 2010 certain unproved properties in the United States were allowed to expire. These properties were removed from undeveloped properties at their carrying value of $4,144,344 and have been included in depletion and depreciation the statement of operations.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

4 . OPERATING LINE OF CREDIT

During the nine month period ended September 30, 2010 the Company reached formal agreement with a Canadian bank for two credit facilities. The first credit facility is a revolving demand loan facility in the amount of Cdn$1,500,000 bearing an interest at prime plus 3.5%. The second credit facility is $1,000,000 non-revolving acquisition/development demand loan bearing an annum interest rate of prime plus 3.0%. Under the terms of the Agreement, the two credit facilities are committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves. As at September 30, 2010, $1,443,149 of the revolving line was drawn. There was Nil drawn on the second facility. See subsequent event note 16.

5. LONG TERM AND SHORT TERM LIABILITIES

The Company has the following liabilities:

	September 30, 2010
Amount due to vendor of acquired properties present value of total amount due	$	4,023,324
Deposit obligation relating to undeveloped properties		46,474
Amount of discount to be accreted in the future (at 7.5% annually - .0625% per month)		(462,982	)
Total Amount due		3,606,816
Less: Current portion		727,117
Long-term portion	$	2,879,699


Current portion of long-term debt	$	727,117
Other short-term debt		527,026
Total short-term debt	$	1,254,143

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 nine months ended September 30, 2010, non cash interest of $185,515 was recorded as interest expense in relation to the discount on the vendor acquired indebtedness.

During the nine months ended September 30, 2010 the total amounts owing on the note payable were extinguished as a result of the share exchange with Ore-More Resources, Inc as noted in Note 1.

6. 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 the all wells. The Company has recognized an asset retirement liability of $1,402,540 and $1,285,614 at September 30, 2010 and December 31, 2009, respectively.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

6. ASSET RETIREMENT OBLIGATIONS (continued)

At September 30, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,125,344 (December 31, 2009 - $3,033,143). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 15 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and a rate of inflation of 2.5%.

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		61,972
Accretion		72,145
Retirements		(17,191	)
Asset retirement obligations, September 30, 2010	$	1,402,540

7 . STOCK OPTION PLAN AND STOCK BASED COMPENSATION

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

	September 30, 2010
	Weighted average Exercise
	Price		Shares
Outstanding at beginning of period	$	0.57		6,060,000
Options granted		-		-
Options forfeited		1.25		(555,000	)
Outstanding at end of period		0.54		5,505,000
Exercisable at end of period	$	0.73		2,371,667

Significant option groups outstanding at September 30, 2010 and December 31, 2009 and related weighted average price and life information follow:

		Outstanding							Exercisable
Range of Exercise Price		Number outstanding at September 30, 2010	Weighted Average remaining Contractual life		Weighted average Exercise Price		Aggregate intrinsic value		Number outstanding at September 30, 2010		Weighted average Exercise price		Aggregate Intrinsic Value
$	.28-1.28	4,725,000		3.64	$	0.32	$	-		1,625,000	$	1.02	$	-
	1.29-2.28	680,000		1.15		1.41		-		680,000		1.41		-
	2.29-3.28	100,000		2.17		2.58		-		66,667		2.58		-

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

7 . STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

A summary of options granted and outstanding under the Kodiak’s stock option plan is presented below.

		Non vested Options			Weighted-Average Grant Date Fair Value
Non vested at December 31, 2009			4,756,667		$	0.25
	Granted		-			-
	Vested		(1,523,334	)		0.26
	Forfeited		(100,000	)		0.19
Non vested at September 30, 2010			3,133,333		$	0.25

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.

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

September 30, 2010
Weighted Average
Exercise Price		Shares
$	1.96	35,000
	2.31	600,000
$	2.29	635,000

Outstanding								Exercisable
Number outstanding at September 30, 2010		Weighted Average remaining Contractual life		Weighted average Exercises Price			Aggregate intrinsic value	Number outstanding at September 30, 2010		Weighted average Exercise price		Aggregate Intrinsic Value
	35,000		4.50	$	1.96	$	-		-	$	-	$	-
	600,000		4.67		2.31		-		-		-		-
	635,000			$	2.29	$			-	$	-	$	-

Cougar Energy, Inc. Stock Option Plan

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

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

September 30, 2010
Weighted Average
Exercise Price		Shares
$	0.63	625,000
	1.26	295,000
$	0.83	920,000

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

7 . STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

Outstanding								Exercisable
Number outstanding at September 30, 2010		Weighted Average remaining Contractual life		Weighted average Exercises Price		Aggregate intrinsic value		Number outstanding at September 30, 2010		Weighted average Exercise price		Aggregate Intrinsic Value
	625,000		3.29	$	0.63	$	-		208,336	$	0.63	$	-
	295,000		4.09		1.26		-		-		-		-
	920,000			$	0.83	$	-		208,336	$	0.63	$	-

It is the intention of company management to merge Cougar Energy, Inc. with its parent, Cougar Oil and Gas Canada Inc. in the near future. Both of the companies are Alberta corporations and could be merged in a statutory amalgamation under Alberta corporate law. Upon that merger, and after giving effect to the Cougar Oil and Gas Canada/Cougar Energy Inc. share exchange at 1:1.5 and the subsequent 3:1 split of Cougar Canada Oil and Gas Canada Inc. shares, the 625,000 and 295,000 outstanding Cougar Energy, Inc stock options exercisable at $.65 and $1.30 respectively shown above will become 2,812,500 and 1,327,500 outstanding Cougar Oil and Gas Canada stock options exercisable at $0.144 and $0.289 respectively.

Warrants

During years ended December 31, 2006, 2007, 2008 and 2009, the Company, as part of certain private placement financings, issued warrants that are exercisable in common shares of the Company. A summary of such outstanding warrants follows:

		Exercise Price ($)		Expiry Date		Equivalent Shares Outstanding			Weighted Average Years to Expiry
Issued June 30, 2006		3.50		Jun. 30/11		1,130,000			1.00

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

Cougar Oil and Gas Canada Warrants

Warrants

The following table summarizes in warrants outstanding and related prices for the shares of the Company’s common stock issued to shareholders at September 30, 2010:

				Warrants Outstanding Weighted Average						Warrants Exercisable
				Remaining		Weighted				Weighted
		Number		Contractual		Average		Number		Average
Exercise Price		Outstanding		Life (years)		Exercise price		Exercisable		Exercise Price
$	0.28		3,873,810		0.77	$	0.28		3,873,810	$	0.28
	0.56		2,342,766		0.86		0.56		2,342,766		0.56
Total			6,216,576		0.81				6,216,576

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

7 . STOCK OPTION PLAN AND STOCK BASED COMPENSATION (continued)

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

	Number of Shares			Weighted Average Price Per Share

Outstanding at October 1, 2008 (date of inception)		-		$	-
Issued		-			-
Exercised		-			-
Canceled or expired		-			-
Outstanding at December 31, 2009		-			-
Issued		6,223,506			0.95
Exercised		(6,930	)		0.56
Canceled or expired		-			-
Outstanding at September 30, 2010		6,216,576		$	0.39

8. STOCKHOLDERS 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 September 30, 2010 and December 31, 2009, the Company had nil preferred shares issued and outstanding and 110,407,186 shares of common stock.

9. NON CONTROLLING INTEREST

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

Net loss Attributable to the Company and transfers (to) from non-controlling interest for the nine months ended September 30, 2010

Net loss	$	1,154,027
Non-controlling interest percentage		38.46	%
Net loss attributable to the non-controlling interest		443,806
Gain from change in non-controlling interest ownership		(109,451	)
Net loss of non controlling interest of Cougar Oil and Gas Canada		334,355

The following table summarizes the changes in Non Controlling Interest from December 31, 2009 to September 30, 2010:

Balance, January 1, 2010	$	258,127
Transfer (to) from the non-controlling interest as a result of change in ownership		298,767
Net loss attributable to the non-controlling interest		(334,355	)
Balance, September 30, 2010	$	222,539

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

10. LOSS PER SHARE

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

	For the three months ended September 30, 2010			For the three months ended September 30, 2009
Numerator:
Numerator for basic and diluted loss per share:
Net loss attributable to the Company	$	(716,126	)	$	(995,580	)

Denominator:
Denominator for basic and diluted loss per share:
Weighted average shares outstanding		110,407,186			110,023,998
Denominator for diluted loss per share:
Weighted average shares outstanding		110,407,186			110,023,998

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

	For the nine months ended September 30, 2010			For the nine months ended September 30, 2009
Numerator:
Numerator for basic and diluted loss per share.
Net loss attributable to the Company	$	(5,726,498	)	$	(17,875,668	)

Denominator:
Denominator for basic and diluted loss per share:
Weighted average shares outstanding		110,407,186			110,023,998
Denominator for diluted loss per share:
Weighted average shares outstanding		110,407,186			110,023,998

Basic and diluted loss per share	$	(0.05	)	$	(0.16	)

Basic loss per share is based on the weighted average number of shares outstanding during the periods. Diluted loss is per share is based on the weighted average number of shares and all dilutive potential shares outstanding during the periods. The Company had outstanding stock options and warrants as at September 30, 2010 and 2009, as disclosed in note 7 that were anti dilutive due to the net loss of those periods.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

11. COMMITMENTS AND CONTINGENCIES

Lease Commitments

As of September 30, 2010 and 2009, the Company had lease commitments for vehicles, office rent and office equipment. The following lease commitments for the years shown:

	September 30, 2010		September 30, 2009
Amounts payable in:
2010	$	48,626	$	27,139
2011		177,954		3,608
2012		173,556		-
2013	$	43,876	$	-

12. FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

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

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

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

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

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

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

13. RELATED PARTY TRANSACTIONS

For the nine months ended September 30, 2010, the Company paid $Nil (September 30, 2009 – $24,107), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services. Of this amount, $nil (September 30, 2009 - $6,910) was capitalized to Unproved Oil and Gas Properties and $nil (September 30, 2009 -$17,197) was charged to General and Administrative Expense.

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

13. RELATED PARTY TRANSACTIONS (continued)

For the nine months ended September 30, 2010 and 2009, the Company incurred $31,333 (September 30, 2009 - $92,106) to Director and the former Chief Financial Officer. $4,374 was payable at September 30, 2010. The Company incurred $86,637 to a Company owned and controlled by the chairman of the Company for management consulting services. $10,104 was payable on September 30, 2010. The Company incurred expenses of the wife of the chairman of the Company of $18,442 for administration consulting services. $6,122 was outstanding on September 30, 2010. These amounts were charged to General and Administrative Expense.

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

14. SEGMENTED INFORMATION

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

	Three Months Ended September 30, 2010									Nine Months Ended September 30, 2010
	U. S.			Canada			Total			U. S.			Canada			Total
Revenue, net of royalties	$	-		$	771,177		$	771,177		$	-		$	2,440,017		$	2,440,017
Income during the Evaluation Period:		-			-			-			-			-			-
Net Loss attributable to Kodiak		(5,583	)		(710,540	)		(716,123	)		(4,157,856	)		(1,568,642	)		(5,726,498	)
Capital Assets		7,132,466			20,660,411			27,792,877			7,132,466			20,660,411			27,792,877
Total Assets		7,133,989			21,768,080			28,902,069			7,133,989			21,768,080			28,902,069
Capital Expenditures		-			1,921,284			1,921,284			1,656			2,623,846			2,625,502

	Three Months Ended September 30, 2009									Nine Months Ended September 30, 2009
	U. S.			Canada			Total			U. S.			Canada			Total
Revenue, net of royalties	$	-		$	-		$	-		$	-		$	-		$	-
Income during the Evaluation Period:		-			-			-			-			-			-
Net Loss attributable to Kodiak		(10,015	)		(985,565	)		(995,580	)		(31,091	)		(17,844,577	)		(17,875,668	)
Capital Assets		11,273,407			21,540,722			32,814,129			11,273,407			21,540,722			32,814,129
Total Assets		11,275,783			22,374,787			33,650,570			11,275,783			22,374,787			33,650,570
Capital Expenditures		(3,912	)		6,520,148			6,516,236			22,818			7,235,959			7,258,777

15. CHANGES IN NON-CASH WORKING CAPITAL

	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
Operating Activities:
Accounts Receivable	$	(196,274	)		(19,542	)
Prepaid Expenses and Deposits		1,253			(15,912	)
Accounts Payable		878,495			310,392
Accrued Liabilities		(6,058	)		(78,923	)
Other		(52,001	)		-

Total	$	625,415			196,015

KODIAK ENERGY, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

(UNAUDITED)

16. SUBSEQUENT EVENTS

In accordance with FASB ASC 855, “Subsequent Events,” the Company has evaluated subsequent events through the date of filing.

Cougar Oil and Gas Canada, Inc.:

On October 14, 2010, the operating line at the Canadian Western Bank was increased from 1.5 mill Cdn. to 2.5 mill Cdn. The second loan vehicle of 1.5 mill Cdn. previously negotiated was then cancelled.

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

On October 29, 2010, Michael J. Hamilton was appointed as an additional director of Cougar Oil and Gas Canada, Inc and Chairman of the Audit Committee. Previously, he has served as Chairman and Chief Executive Officer of MMC Energy, Inc., a publicly traded merchant electricity generator that owned several generating units in California, until September 2009. Previously, Mr. Hamilton was the partner in charge of utility audit and tax at PricewaterhouseCoopers until he retired in 2003. He then served as a senior managing director at FTI Consulting where he specialized in bankruptcy and restructuring work, primarily in the merchant power industry. Mr. Hamilton is a certified public accountant with additional certifications in business valuation and financial forensics and is a certified turnaround professional. Mr. Hamilton is also a director of MMC Energy, Inc., the non-executive Chairman of the Board and a director for MXenergy Holdings, Inc. the non-executive Chairman of the Board and a director of Coda Octopus Group. and Gradient Resources, Inc. Mr. Hamilton also is an experienced senior financial independent director and as an financial expert per the SEC and US Stock Exchange regulations.

Kodiak Energy, Inc.:

On October 29, 2010, the Company notified Meyers Norris Penny LLP (“Meyers Norris Penny”) that it was dismissed as the Company's independent registered public accounting firm. The decision to dismiss the Meyers Norris Penny as the Company’s independent registered public accounting firm was approved by the Company’s Board of Directors on October 28, 2010. Except as noted in the paragraph immediately below, the reports of Meyers Norris Penny on the Company’s consolidated financial statements for the years ended December 31, 2009 and 2008 did not contain an adverse opinion or disclaimer of opinion, and such reports were not qualified or modified as to uncertainty, audit scope, or accounting principle.

The reports of Meyers Norris Penny on the Company’s consolidated financial statements as of and for the years ended December 31, 2009 and 2008 contained an explanatory paragraph which noted that there was substantial doubt as to the Company’s ability to continue as a going concern due to uncertainty with respect to Company’s ability to fund future operations.

During the years ended December 31, 2009 and 2008 through October 29, 2010, the Company has not had any disagreements with Meyers Norris Penny on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to Meyers Norris Penny’s satisfaction, would have caused them to make reference thereto in their reports on the Company’s consolidated financial statements for such periods.

On October 29, 2010 (the “Engagement Date”), the Company engaged RBSM LLP (“RBSM ”) as its independent registered public accounting firm for the Company’s fiscal year ended December 31, 2010. The decision to engage RBSM as the Company’s independent registered public accounting firm was approved by the Company’s Board of Directors.

The Company announced that Mr. Lester Owens has submitted his retirement from the Company’s Board of Directors effective November 2, 2010. Mr. Owens wishes to focus on his other business activities.

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

FORWARD LOOKING STATEMENTS

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

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

The financial information set forth in the following discussion should be read in conjunction with the consolidated financial statements of Kodiak Energy, Inc. included elsewhere herein.

PLAN OF OPERATION

Oil and Gas Leases and Development Rights

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

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

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

We financed the CREEnergy project and Cougar operations, with small private placements with accredited small investors in Canada and Europe, for the first 10 months. Then as the acquisitions presented opportunities, we found a bridge loan and a vendor take back to close the acquisitions.

Subsequently we reached an agreement with OreMore ( Cougar Oil and Gas Canada, Inc or “COG”) who had previously bought the bridge loan (which had been guaranteed by both Cougar and Kodiak) – to sell Kodiak shares of Cougar Energy to OreMore in exchange for issuing shares of Oremore to Kodiak and cancelling the bridge loan debt.

On January 25, 2010, COG finalized a share purchase agreement between COG and the Company whereby the 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 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 $1,296,889. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Ore-More Resources, Inc were cancelled.

Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of the COG.

Kodiak retains a 64% of the Cougar Oil and Gas Canada Inc.’s outstanding shares at this time. As long as Kodiak retains greater than 50%, of the outstanding shares, we will report Cougar Oil and Gas Canada results on a consolidated basis.

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

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

Cougar Oil and Gas Canada, Inc Properties and Operations

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

First Nation Joint ventures – exploration and development opportunities with the adjacent First Nation Communities and within in the CRE Energy Agreement and other communities;

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

Other Alberta properties.

Kodiak Energy, Inc properties

	1.	Little Chicago – Seismic

	2.	New Mexico Sofia/Spear Draw CO2 Prospects

	3.	New Mexico Sofia/Spear Draw Oil and Gas Prospects.

The Company expects to finance its future capital expenditure programs and acquisitions with combinations of revenue from current operations, debt instruments, farm-outs, equity financings and divestiture, depending upon what vehicle is appropriate to the capital program/acquisition and the overall market economy. A 6 to 12 month payback will be used to benchmark all such capital programs for financing purposes.

A brief description of the Company’s properties and activities is described below. For a more detail description of the properties to better understands the planned operations –.

Cougar Oil and Gas Canada, Inc Trout Properties, Alberta (Core Area)

During the third quarter of 2009, Cougar Energy, Inc. completed the following transactions.

Trout Core Properties-

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

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

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

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

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

The agreed purchase price was Cdn$6,000,000 with an initial payment of Cdn$1,000,000 at closing. The purchase price was negotiated at $52.50 per barrel (bbl) when oil was currently selling at $75+/bbl. Included 7,100 gross acres of mineral rights with an average 85% working interest (all continued through production, no expiries). As of July 31, 2010 approximately 230 barrels per day (bbl/d) net production (275 bbl/d gross) – 85 bbl/d at time of acquisition with 13 pumping wellbores – 8 at time of acquisition 1 observation wellbore and 21 suspended wellbores, 8 single well batteries, 3 water disposal wellbores with associated facilities, 2 multi well batteries with existing fluid handling capacity in excess of 2500bbl/day (oil, gas and water handling and treating capability, approximately 38.7 km of pipelines (oil and produced water), approximately 13 km 2 of 3D seismic over the properties and approximately 84 km of 2D seismic over the properties and adjacent lands. The majority of this acquisition is outside the boundary of the Peerless Trout Lake First Nations. The current surface facilities have a replacement value of Cdn $6,500,000 with a depreciated value of $1,000,000 Cdn. The overall project has an estimated $50,000,000 Cdn in replacement value including wells, facilities, pipelines, roads and power lines.

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

This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs,lower development costs and giving our schedule an enormous leap forward to achieve our goals of creating a 2 - 5,000 bbl/dcompany in a short period of time. Without this kind of infrastructure, the initial production would have lower netbacks due to higher trucking costs and regular non-producing periods due to weather. In lieu of this acquisition, a large amount of capital would have to be spent to bring facilities to this baseline, which we now have. At current costs, the infrastructure replacement value would be substantially in excess of $6,000,000 Cdn. This capital will be spent on the drilling and development work, allowing for a more aggressive growth plan.

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

There are two batteries for the handling and treating of oil and the disposal of the produced water. The batteries are capableof handling an estimated 2,500 bbl/d with nominal refit costs. Many of the wells are piped into the batteries to lower the needfor trucking which is especially important for the higher water cut wells – these pipelines can be expanded to further lower operating costs. The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in our control and not third party pipeline operator dependent. There are 37 wells, which 13 were producing as of July 31, 2010 – the 21 suspended wells have potential upside, as discussed below. As of July 31, 2010 year end - production was averaging 230 bbl/d net of light sweet crude oil from the Trout field at an average operating cost of $20.00 Cdn to $25.00/bbl Cdn. We have completed a substantial amount of due diligence and are comfortable with the projected estimated $50.00 Cdn netbacks from these properties at current commodity prices, and this provides for a safety margin much lower than the lowest price seen in the recent recession.

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

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

(a)

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

(b)

90% BPO & 55% APO working interest in the Alexander property- one producing Wabamun oil well with a single well battery, one suspended well. The Alexander property had some minor repairs completed in June 2010 and was put back on production. Production is currently approximately 15 barrels per day net production.

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

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

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

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

E. Subsequent Maintenance Programs on all Properties

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

These activities have been initiated on a portion of the properties resulting in the increase of production from the 80 bbls/dnet at acquisition to the 205 bbl/d net at September 30, 2010.

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

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

Lucy, Northern British Columbia

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

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

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

In the third quarter of 2007, the Kodiak served its partners with an independent operations notice which resulted in the Company increasing its working interest in the lease to 80%.

In the first quarter of 2008, a second drilling operation was completed and a vertical well was cased. It was determined that the Middle Devonian seismic anomaly was not a reef buildup and the wellbore was cased due to encountering significant gas shows in the previously identified Muskwa Shale with a formation thickness of approximately sixty meters.

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

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

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

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

The prospect is still in the early stages of delineation and no assurance can be given that its exploitation will be successful. Further appraisal work is required before these estimates can be finalized and commerciality assessed.

The severe turn down in gas prices over the past year has made natural gas projects difficult to show returns on investment – especially high capital cost projects such as those in the Horn River Basin – despite the very large reserves and recovery rates attributed to the Muskwa shales. The current $3 to $5 gas prices limit the return for this project in the short term and the availability to obtain development financing.

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

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

Drill and case a 1,000 meter horizontal leg from an existing cased vertical well on the lease, perform a horizontal staged fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to pipeline.

In January 2009, the Kodiak vended its Lucy, British Columbia into Cougar Energy.

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

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

Oil and Gas Leases and Development Rights

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

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

As of September 30, 2010, approximately 70% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

In the Trout Area, Alberta as of September 30, 2010, we held oil and gas leases on approximately 15,500 gross acres, of which approximately 5,000 gross acres (33%) are not currently held by production. The approximate 5,000 acres had an expiry date in the third quarter of 2015 and an application has been submitted to the regulatory agency to extend the expiry of these leases.

In the Alexander Area, Alberta as of September 30, 2010, we held oil and gas leases on approximately 160 gross acres, of which no gross acres are currently held by production. There are no expiry issues for this lease.

In Lucy, British Columbia as of September 30, 2010, we held oil and gas leases on approximately 1,975 gross acres, of which approximately 1,975 gross acres (100%) are not currently held by production. The Lucy mineral lease was extended as part of an approved Experimental Scheme application to the regulatory agency. The Lucy lease is currently extended indefinitely.

PLANS FOR GROWTH

Cougar Oil and Gas Canada

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

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

The Company has finished implementing approximately half of the optimization projects originally identified during the field review which resulted in a production increase in excess of 250%. The projects implemented in the field have included repair and replacement of surface and downhole 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.

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

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

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

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 the 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

Ventures with the First Nation provides additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure. The Company continues to actively work on the First Nation joint ventures with a goal of responsible development of the leased oil and natural gas mineral rights. Private First Nation land represents some of the largest unleased blocks of mineral rights in the province of Alberta and Cougar has identified this type of Joint Venture as a strategically critical growth opportunity. The Company has paid an exclusivity fee to an authorized First Nation agent which provides the opportunity to lease specific mineral rights. The Company is also currently working with other First Nation groups to develop mutually beneficial joint venture agreements which will allow Cougar and the First Nations to explore and develop conventional oil and natural gas prospects on private lands 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.

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. We monthly review the opportunity and balance the risk versus reward and which can be adjusted depending on cash flow, commodity prices and financing. When the stability of natural gas prices over a period of time that then translates into a net back on the Lucy prospect we will look to assign capital dollars to the project. Until then there is no expiry on the lease.

Summary

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

Little Chicago – Northwest Territories

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

Upon review of the overall status of all projects in the area, current commodity prices being much below levels required to justify development on this and other projects, continued delay of the Mackenzie Valley Pipeline Project, the risk that any discovered gas reserves would be indefinitely stranded without such development, the high cost of operations for oil reserves and low potential net back, the Company actively sought partnership in the development; however, the deteriorating economic factors made this very difficult. The other majority working interest in the property would not fund their share of exploration programs, and thus Kodiak would have born 100% of the costs and risk. The license expired on September 17, 2010. However we still retain 98% of the rights to the extensive confidential proprietary seismic data over the area for future assessment of the "Little Chicago Prospect" and the Company will determine the best way to monetize that asset through either divestiture and/or possibly renominating the prospect when conditions are more appropriate.

New Mexico

Sofia/Spear Draw CO2 Prospect

Through its acquisition of Thunder, the Company acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Company’s land position to approximately 79,000 acres. These lands have potential for natural gas and CO2 and oil and helium resources at shallow depths and straddle existing dedicated CO2 sales pipeline and is close to power and other infrastructure – making development models somewhat less capital intensive. With 3 wells drilled and 98% + quality CO2 in the wells, seismic over a major portion of the extensive consolidated land position - the project has some advantages that other projects do not.

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

Sofia/Spear Draw Oil and Gas Prospects

Over the last 3 months, Kodiak has been actively negotiating and has reached an agreement with a third party to farm in on the prospect to explore for Oil and Gas at deeper depths. The Farm in agreement is currently in the option stage and the 3d party has until January 30, to exercise their options to move into either a seismic or a drilling option.

Kodiak would retain a working interest and overall management of the properties.

FINANCIAL INFORMATION

Operating Results

Revenue

Kodiak through Cougar Oil and Gas Canada, Inc continues production on its developed assets which began in the fourth quarter of 2009. There are no operating revenue or expense comparables for the current quarter or nine months year over year.

Net Loss attributable to Kodiak for the three months ended September 30, 2010 totaled $716,126 (September 30, 2009 - $995,580). Net Loss for the nine months ended September 30, 2010 totaled $5,726,498 (2009 - $17,875,668)The decrease in loss for the current periods is due to a major asset write down of a undeveloped CAD property in the second quarter of 2009 in the amount of $16,169,130.

General and administrative expense for the three months ended September 30, 2010 was $648,014 (September 30, 2009 - $658,871). General and Administrative expense for the nine months ended September 30, 2010 totaled $1,928,735 (2009 - $1,506,760). The increases for the current periods are due to higher staffing levels, higher stock based compensation expense and reorganization costs dealing with a Kodiak subsidiary.

Interest expense for the three months ended September 30, 2010 was $84,913 (September 30, 2009 - nil). The increase is a result of the Company’s borrowing to purchase the Trout properties as well as interest on the operating line. Prior to this period the Company did not have the any operating lines of credit. Interest expense for the nine months ended September 30, 2010 was $247,266 (September 30, 2009 - $304). The increase is due to the interest on the financing for the Trout property purchase and interest on the operating line, neither of which the Company had last year.

Depletion, depreciation and accretion including ceiling test impairment write-downs includes the cost of depletion and depreciation relating to production from producing properties in the quarter, ceiling test impairment write-downs and the cost of depreciation relating to office furniture and equipment. Depletion and depreciation charges of $489,713 (September 2009 - $363,156) was recorded and included in this quarter. The increase additional properties placed in service. Depletion and depreciation charges for the nine months ended September 30, 2010 of $5,270,976 (September 30, 2009 - $16,407,480) were recorded and included in the period. The decrease was due to a ceiling test write down of $16,169,130 in 2009 vs a ceiling test write down of $4,144,000 as well as Depletion costs of $590,218 in 2010.

Financial Condition and Changes in Financial Condition:

The Company’s total assets have decreased to $28,902,069 as at September 30, 2010 from $31,657,559 as at December 31, 2009 and decreased from $33,650,570 in September 30, 2009. This decrease is primarily due to net recorded valuations in undeveloped properties due to a ceiling test write down for the quarter ended March 31, 2010 net with the purchase of the remaining non-controlling interest in one of the Company’s subsidiaries . Total assets consist of cash and other current assets of $806,540 (December 31, 2009 - $557,355).

The Company has included in oil and gas properties evaluated and unevaluated properties. Evaluated properties net of accumulated depreciation, depletion and amortization was $5,544,340 (December 31, 2009 - $4,657,403). Unevaluated properties decreased to $22,188,364 from $26,081,786 on December 31, 2009. The major difference write-down of undeveloped properties $4,410,309. There was a requirement for a ceiling test write down for the period ending March 31, 2010.

Other assets increased marginally to $302,652 as of September 30, 2010 (December 31, 2009 - $296,153). The increase is due to the increase in deposit held by regulatory bodies for operational and environmental deposits.

Our total current liabilities increased $1,666,862 to $6,118,390 (December 31, 2009 - $4,451,528). The net increase is due to increases in operating line and current portions of long-term debt and a decrease in notes payable. Accounts payable and accrued liabilities increased to $3,421,098 (December 31, 2009 - $2,548,661). The increase is due to increased work activity during the quarter and capital spending. . Our current debt increased to $2,697,292 (December 31, 2009 - $1,902,866) The increase is caused by an increase in our operating line and current portions of long term debt offset by the elimination of notes payable.

We had long term liabilities of $2,879,699 (December 31, 2009 - $3,400,489). This decrease is due to the nature of payment term on the company’s debt and the classification between current and long-term debt. Asset retirement obligations increased by $116,926 for the nine months ended September 31, 2010 to $1,402,540 (December 31, 2009 - $1,285,614). The increase is a result of accretion expense of $72,145 (September 30, 2009 – $9,966) and asset retirement obligation additions of $61,972 (September 30,2009 – nil)

Liquidity and Capital Resources

The Company is in the process of raising additional financing in its Cougar Oil and Gas Canada Inc. subsidiary that will provide financing to carry out its business plan through 2010. See Subsequent Event Note 16 to the consolidated financial statements. Such additional financing will be required for the company’s 2010 planned activities. In the event that additional capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Company, or the Company’s interest in the subsidiary.

Our registered independent certified public accountants have stated in their report dated March 19, 2010, 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

PETROLEUM AND NATURAL GAS AND RELATED HYDROCARBON PRICES

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

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

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

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

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

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

FOREIGN CURRENCY EXCHANGE RATES

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

INTEREST RATES

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

ITEM 4T. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this report. They concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not adequate and effective in ensuring that material information relating to the Company would be made known to them by others within those entities, particularly during the period in which this report was being prepared.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and in reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

SEGREGATION OF DUTIES AND ACCESS TO CRITICAL ACCOUNTING SYSTEMS

As at December 31, 2009, December 31, 2008 and December 31, 2007, management believes the Company’s Internal Control over Financial Reporting did not meet the definition of adequate control, based on criteria established by Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management identified a material weakness relating the segregation of duties among certain personnel who had incompatible responsibilities within all significant processes affecting financial reporting. We also had a material weakness resulting from our failure to implement controls to restrict access to financially significant systems or to monitor access to those systems, which resulted in conflicting access and/or inappropriate segregation of duties. These material weaknesses affect all significant accounts. In addition, the 2007 restatement issues discussed below demonstrated a need to engage additional personnel or outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP, to assist in income tax planning and compliance and a review of our Canadian and U. S. income tax provisions. As a result of these material weaknesses, management has concluded that internal control over financial reporting was not effective as at September 30, 2010.

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 an additional financial consultants 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 financial statements. Management believes that this additional level of control procedures that will be fully in place before the end of 2010 will effectively 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 retired on December 31, 2009, has joined the Board of Directors and continues to consult to the Company in a financial capacity and alleviate some of the segregation of duties and related weaknesses. The VP of Finance assumed the role of CFO ensuring a smooth transition.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal control over financial reporting during the third quarter ended September 30, 2010 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

None

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. Removed and reserved

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBITS

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

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

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

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.