Kodiak Energy 10Q 2008 Q2 Quarterly report

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 June 30, 2008

[ ] 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.)

734 7th Avenue S.W. Calgary, AB T2P 3P8

(Address of principal executive offices - Zip code)

(403) 262-8044

(Registrant's telephone number, including area code)

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

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

Exchange Act. (Check one):

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

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

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

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

APPLICABLE ONLY TO CORPORATE ISSUERS

State the number of shares outstanding of each of the registrant's classes of common equity, as of the latest practicable date: 110,023,998 common shares, $.001 par value, as at August 8, 2008.

KODIAK ENERGY, INC.

INDEX

PART I.	FINANCIAL INFORMATION	3

ITEM 1.	FINANCIAL STATEMENTS	3

	Consolidated Balance Sheets	3

	Consolidated Statement of Shareholders’ Equity (unaudited)	4

	Consolidated Statements of Operations (unaudited)	5

	Consolidated Statements of Cash Flows (unaudited)	6

	Notes to Consolidated Financial Statements (unaudited)	7

ITEM 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION	27

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	37

ITEM 4.	CONTROLS AND PROCEDURES	38


PART II.	OTHER INFORMATION	39

ITEM 1.	LEGAL PROCEEDINGS	39

ITEM 1A.	RISK FACTORS	39

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	44

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	44

ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	44

ITEM 5.	OTHER INFORMATION	44

ITEM 6.	EXHIBITS AND REPORTS ON FORM 8-K	44

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	June 30			December 31
	2008			2007
	(Unaudited)			(Audited)
Assets

Current Assets:
Cash and Short Term Deposits	$	737,599		$	8,983,682
Accounts Receivable (Note 4)		1,359,618			1,214,253
Prepaid Expenses and Deposits		123,141			90,475
		2,220,358			10,288,410

Other Assets (Note 5)		346,303			359,353

Capital Assets (Note 6):
Unproved Oil & Gas Properties Excluded From
Amortization – Based on Full Cost Accounting		33,567,220			23,967,351
Property & Equipment		80,287			75,654
		33,647,507			24,043,005


Total Assets	$	36,214,168		$	34,690,768


Liabilities and Shareholders' Equity

Current Liabilities:
Accounts Payable	$	1,067,083			1,547,273
Accrued Liabilities		446,303			755,282
		1,513,386			2,302,555

Long-term Liabilities (Note 7)		46,898			110,955

Asset Retirement Obligations (Note 8)		244,401			151,814

Deferred Income Taxes (Note 9)		52,000			57,000

		1,856,685			2,622,32


Shareholders' Equity
Share Capital (Note 10):
Authorized 300,000,000 Common Shares Par Value
.001 Each; Issued and Outstanding
108,023,998 (2007 – 106,692,498) Shares		108,024			106,692
Additional Paid in Capital		42,535,255			39,143,392
Other Comprehensive Loss		(411,013	)		(342,201	)
Deficit Accumulated during the Exploration Stage		(7,874,783	)		(6,839,439	)
		34,357,483			32,068,444


Total Liabilities and Equity	$	36,214,168			34,690,768

(See accompanying notes to the consolidated financial statements)

Contingencies and commitments (Note 13)

Subsequent events (Note 18)

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Shareholders’ Equity

Six Months Ended June 30, 2008

(Exploration Stage Company Going Concern Uncertainty – Note 1)

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

Balance at December 31, 2007		106,692,498	$	106,692	$	39,143,392	$	(6,839,439	)	$	(342,201	)	$	-	$	32,068,444
Net income		-		-		-		1, 035,344			-			-		1,035,344
Foreign currency translation		-		-		-		-			(68,812	)				(68,812	)
		-		-		-		1,035,344			(68,812	)				1,104,156
Common shares issued		1,331,500		1,332		3,036,258		-			-					3,037,590
Stock-based Compensation		-		-		355,605		-			-			-		355,605
Balance at June 30, 2008		108,023,998	$	108,024	$	42,535,255	$	(7,874,783	)	$	(411,013	)			$	34,357,483

(See accompanying notes to the consolidated financial statements)

Kodiak Energy Inc.

Unaudited Consolidated Statements of Operations

(Exploration Stage Company Going Concern Uncertainty – Note 1)

													Cumulative
	Three Months			Three Months			Six Months			Six Months			Since Inception
	Ended June 30,			Ended June 30,			Ended June 30,			Ended June 30,			Apr. 7, 2004 to
	2008			2007			2008			2007			June 30, 2008

INCOME DURING THE EVALUATION PERIOD	$	46		$	42		$	46		$	427		$	27,405

EXPENSES
Operating		4,999			964			5,273			11,600			39,388

General and Administrative		557,918			559,477			1,070,083			853,989			4,941,658
Stock-based Investor Relations		-			-			-			-			337,500
Depletion, Depreciation and Accretion		13,573			12,622			25,277			22,143			1,752,374
Including Ceiling Test Impairment
Write-downs
Interest		1,257			18,818			1,257			18,818			904,151
		577,747			591,881			1,101,890			906,550			7,975,071
Loss Before Other Expenses		(577,701	)		(591,839	)		(1,101,844	)		(906,123	)		(7,947,666	)
Other Expenses (Income)
Loss from valuation adjustment		-			-			-			-			25,000
Interest Income		4,514			267			61,500			509			149,883
		(4,514	)		(267	)		(61,500	)		(509	)		124,883
Net Loss before taxes		(573,187	)		(591,572	)		(1,040,344	)		(905,614	)		(7,822,783	)
Deferred Income Taxes (Recovery)					55,480			(5,000	)		55,480			52,000

NET LOSS	$	(573,187	)	$	(647,052	)	$	(1,035,344	)	$	(961,094	)	$	(7,874,783	)

(See accompanying notes to the consolidated financial statements)

Loss per share data (Note 12)

KODIAK ENERGY, INC.

Unaudited Consolidated Statements of Cash Flows

(Exploration Stage Company Going Concern Uncertainty – Note 1)

	Three Months Ended June 30, 2008			Three Months Ended June 30, 2007			Six Months Ended June 30, 2008			Six Months Ended June 30, 2007			Cumulative Since Inception April 7, 2004 to June 30, 2008
Operating Activities
Net Loss	$	(573,187	)	$	(647,052	)	$	(1,035,344	)	$	(961,094	)	$	(7,874,783	)
Adjustments to reconcile net loss to
net cash used in operating activities:
Depletion, Depreciation and Accretion		13,573			12,622			25,277			22,143			1,752,374
Non-cash Interest Expense		-			18,818			-			18,818			808,811
Stock-Based Investor Relations Expense		-			-			-			-			337,500
Stock-Based Compensation		165,469			155,269			355,605			279,083			1,068,708
Deferred Income Taxes (Recovery)		-			55,480			(5,000	)		55,480			52,000
Bad Debts Written Off		-			-			-			-			11,908
Contributions to Capital		-			-			-			-			900
Non-Cash Working Capital Changes (Note 17)		12,873			31,000			616,337			(79,188	)		87,014
Net Cash Used In Operating Activities		(381,272	)		(373,863	)		(43,125	)		(664,758	)		(3,755,568	)

Investment Activities:
Additions To Capital Assets		(5,583,591	)		(3,227,253	)		(10,857,261	)		(4,895,363	)		(21,217,261	)
Additions To Other Assets		(2,981	)		(4,508	)		13,050			(5,220	)		(346,303	)
Net Cash Used In Investment Activities		(5,586,572	)		(3,231,761	)		(10844,211	)		(4,900,583	)		(21,563,564	)
Financing Activities
Financing Activities Shares Issued and Issuable		2,897,184			1,711,098			2,774,122			3,446,026			26,420,847
Long term liabilities		311			3,000,000			(64,057	)		3,000,000			46,898
Net Cash Provided By Financing Activities		2,897,495			4,711,098			2,710,065			6,446,026			26,467,745

Foreign Currency Translation		10,408			(65,482	)		(68,812	)		(65,593	)		(411,013	)
Net Cash Increase (Decrease)		(3,059,941	)		1,039,992			(8,246,083	)		815,092			737,599

Cash beginning of period		3,797,540			223,446			8,983,682			448,346			-

Cash end of period	$	737,599		$	1,263,438		$	737,599		$	1,263,438		$	737,599


Cash is comprised of:
Balances with banks	$	737,599		$	1,263,438		$	737,599		$	1,263,468		$	737,599
Short-term deposits	$	-			-			-			-			-
	$	737,599		$	1,263,438		$	737,599		$	1,263,468		$	737,599

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

For the Six Months Ended June 30, 2008 and 2007

Stated in US dollars

1. ORGANIZATION, BASIS OF PRESENTATION AND GOING CONCERN UNCERTAINTY

The accompanying consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”) as at June 30, 2008 and December 31, 2007 and for the three and six months ended June 30, 2008 and 2007 and for the cumulative period from April 7, 2004 (inception) until June 30, 2008, and are presented in accordance with generally accepted accounting principles in the United States of America (“U. S. GAAP”).

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

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

Bankruptcy

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

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

The Company emerged from bankruptcy as an exploration stage company.

Going Concern Uncertainty

These consolidated financial statements have been prepared assuming the Company will continue as a going concern, which presumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has not generated positive cash flow since inception and has incurred operating losses and will need additional working capital for completion of its planned 2008 and future programs. 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 management of the Company has developed a strategy to address this uncertainty, including additional equity and/or debt financing; however, there are no assurances that any such financing can be obtained on favorable terms, if at all, or that the Company will generate positive cash flow. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

Use of Estimates in the Preparation of Financial Statements

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

Joint Venture Operations

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

Cash and Short-term Deposits

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

Oil and Gas Properties

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

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

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

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

Property and Equipment

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

Asset Retirement Obligations

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

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

accretion.

Environmental

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

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

Income Taxes

Income taxes are determined using the liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Per FASB Interpretation (FIN 48) (See Note 3) under the liability method, it is the Company’s policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At June 30, 2008, the Company believes it has appropriately accounted for any unrecognized tax benefits. To the extent the Company prevails in matters for which a liability for an unrecognized benefit is established or is required to pay amounts in excess of the liability, the Company’s effective tax rate in a given financial statement period may be affected. Interest and penalties associated with the Company’s tax positions are recorded as Interest Expense.

Stock-Based Compensation

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

Foreign Currency Translation

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

Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title passes from the Company to its petroleum and/or natural gas purchaser and collectability is reasonably assured. The Company will begin recording revenue once it is determined there are proved reserves.

Loss Per Common Share

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

3. RECENT ACCOUNTING PRONOUNCEMENTS

FASB Interpretation No. 48, “Accounting for Uncertainty in Income taxes – an interpretation of FASB Statement No. 109 (FIN 48). In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which the Company has concluded there is a level of uncertainty with respect to the recognition of a tax benefit in the Company’s financial statements. FIN 48 describes the minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of certain transactions.

Effective January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. There was not a material impact on the Company’s consolidated financial position and results of operations as a result of the adoption of the provisions of FIN 48. At June 30, 2008, the Company had no significant unrecognized tax positions and the Company does not believe there will be any material changes in its unrecognized tax positions over the next twelve months.

The Company’s tax positions are subject to examination by tax authorities. As at June 30, 2008, the Company’s tax years 2005 to present are open for United States – Federal and State jurisdictions and Canada – Federal and Provincial jurisdictions.

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

In November, 2007, FASB issued SFAS No. 141(R), Business Combination. FAS 141(R) will change how business acquisitions are accounted for and will impact financial statements both on the acquisition date and in subsequent periods. FAS 141(R) is effective for both public and private companies for fiscal years beginning on or after December 15, 2008. FAS 141(R) will be applied prospectively. Early adoption is prohibited. The Company has not yet determined this pronouncement’s potential impact.

Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157). In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS No 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change the Company’s current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. Under SFAS No. 157, fair value refers to the price that would be received to sell an asset or paid to transfer an liability in an orderly transaction between market participants in the principal or most advantageous market. The standard clarifies that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In February, the FASB issued Staff Position No 157-2, “Effective Date of FASB Statement No. 157” (“FSP FAS 157-2”), which delays the effective date of SFAS No. 157 for all non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the Financial statements on a recurring basis until fiscal years beginning after November 15, 2008. The Company adopted the provisions of SFAS No. 157 for assets and liabilities recognized at fair value on a recurring basis effective January 1, 2008. The partial adoption of SFAS No. 157 did not have a material impact on the Company’s Financial Statements. We do not currently anticipate that full adoption in 2009 will materially impact the Company’s results of operations or financial condition.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159). In February 2007, the FSAB issued SFAS No. 159, which permits entities to choose to measure many new financial instruments and certain other items at fair value. The Comapany adopted SFAS No. 159 effective January 1, 2008, and did not elect the fair value option for any existing items.

4. ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	June		December
	30, 2008		31, 2007

Non-operating Partner joint venture accounts	$	63,888	$	454,179
Operator cash call advances		-		76,388
Government of Canada Goods and Services Tax Claims		131,573		621,254
Accrued interest receivable		-		57,096
Amount due from Brink Energy Ltd. (Note 18)		980,681		-
Amount due from warrant holder on exercise of warrants		180,000		-
Other		3,476		5,336
	$	1,359,618	$	1,214,253

5. OTHER ASSETS

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

	June		December
		30, 2008		31, 2007

Alberta Energy and Utility Board Drilling Deposit	$	86,631	$	87,518
Alberta Energy Royalty Deposit		-		4,723
British Columbia Oil and Gas Commission Deposit		259,672		267,112

	$	346,303	$	359,353

6. CAPITAL ASSETS

	Cost		Accumulated Depreciation and Depletion		Net Book Value June 30, 2008

Oil and Gas Properties:

Canada	$	24,972,263	$	1,651,037	$	23,321,226
United States		10,245,994		-		10,245,994

Sub-total		35,218,257		1,651,037		33,567,220

Furniture and Fixtures		148,635		68,348		80,287

Total	$	35,366,892	$	1,719,385	$	33,647,507

	Cost		Accumulated Depreciation And Depletion		Net Book Value December 31, 2007

Oil and gas Properties:

Canada	$	18,595,042	$	1,651,037	$	16,944,005
United States		7,023,346		-		7,023,346

Sub-total		25,618,388		1,651,037		23,967,351

Furniture and Fixtures		128,412		52,758		75,654

Total	$	25,746,800	$	1,703,795	$	24,043,005

During the six months ended June 30, 2008, the Company has capitalized $116,214 (December 31, 2007 - $ 193,173) of general and administrative personnel costs attributable to acquisition, exploration and development activities.

Unproved Properties

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

	June		December
	30, 2008		31, 2007
Canada
Land acquisition and retention	$	11,647,327	$	9,284,017
Geological and geophysical costs		10,231,402		6,371,954
Exploratory drilling		1,235,015		1,114,763
Tangible equipment and facilities		67,518		127,217
Other		139,964		46,054
	$	23,321,226	$	16,944,005

United States
Land acquisition and retention	$	6,789,173	$	6,206,389
Geological and geophysical costs		929,748		383,800
Exploratory drilling		2,396,504		409,246
Tangible equipment and facilities		50,760		-
Other		79,809		23,911
	$	10,245,994	$	7,023,346
	$	33,567,220	$	23,967,351

In Canada, winter drilling programs are planned for 2008-10 for our North West Territories property and a stimulation and horizontal drilling program is planned for our British Columbia property. In the United States, an initial seismic and drilling program has been conducted on our New Mexico property with additional drilling to follow. These planned activities, when completed, will enable the Company to evaluate the economic viability of these properties. It is estimated by management that the unproved property costs associated with these properties, which in the aggregate constitutes approximately $32,200,000 of our total unproved property costs as at June 30, 2008, will be included in costs subject to depletion by 2010.

Ceiling Test

The Company has performed ceiling tests for its Canadian and United States geographical cost centers and has determined that no impairment exists as at June 30, 2008. As at December 31, 2007, the carrying value of the Company’s unproved properties in its Canadian and United States cost centers were assessed by management and costs attributable to certain Canadian cost center properties were determined to be unsupportable. Consequently, a ceiling test impairment write-down as of December 31, 2007 of $174,380 was recorded and included in depletion, depreciation and accretion for 2007. No impairment existed in the United States cost center as at December 31, 2007.

7. LONG TERM LIABILITIES

As at June 30, 2008, the Company held $ 46,898 (December 31, 2007 - $110,955) in funds advanced by partners for their share of a drilling deposit required to be lodged by the Company with the British Columbia Oil and Gas Commission (See Note 5) as security for future well abandonment and site restoration activities.

8. ASSET RETIREMENT OBLIGATIONS

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

Asset Retirement Obligations, December 31, 2007	151,814
Obligations incurred	82,914
Accretion	9,673
Asset retirement obligations, June 30, 2008	244,401

At June 30, 2008, the estimated total undiscounted amount required to settle the asset retirement obligations was $ 386,654 (December 31, 2007 - $213,880). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 8 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and a rate of inflation of 2.5%.

9. DEFERRED INCOME TAXES

At June 30, 2008, the Company's deferred tax asset is attributable to its net operating loss carry forward of approximately $16,414,000 (December 31, 2007 - $11,191,000), which will expire if not utilized in the years 2024 to 2028. Of this amount, approximately $408,000 (December 31, 2007 - $402,000) is attributable to the Company's Canadian operations. As reflected below, this benefit has been fully offset by a valuation allowance based on management's determination that it is not more likely than not that some or all of this benefit will be realized.

For the periods ended June 30, 2008, June 30, 2007 and for the cumulative period April 7, 2004 (Date of Inception) to June 30, 2008, a reconciliation of income tax benefit at the U.S. federal statutory rate to income tax benefit at the Company's effective tax rates is as follows:

	2008			2007			Cumulative
Income tax benefit at statutory rate	$	(360,000	)	$	316,000		$	2,857,000
Permanent Differences		2,000			(47,000	)		(408,000	)
State tax benefit, net of federal taxes		216,000			(17,000	)		269,000
Foreign taxes, net of federal benefit		(5,000	)		(55,480	)		(44,000	)
Change in valuation allowance		(578,000	)		(252,000	)		(2,726,000	)
Income tax recovery (expense)at effective rate	$	(5,000	)		(55,480	)	$	(52,000	)

Deferred tax assets (liabilities) at June 30, 2008 and December 31, 2007 are comprised of the following:

	2008			2007
Deferred tax assets
Deferred costs	$	-		$	-
Deferred deduction on stock-based Compensation expense		374,000			249,000
Net operating loss carryover		6,096,000			4,053,000
Total deferred tax asset		6,470,000			4,302,000

Deferred tax liabilities
Excess of U.S. tax deductions over book amounts written off		3,744,000			2,154,000

Net deferred tax asset before valuation allowance		2,726,000			2,148,000
Less valuation allowance for net deferred tax asset		(2,726,000	)		(2,148,000	)

Net deferred tax asset	$	-		$	-

Canadian deferred tax liability resulting from flow-through share expenditures renounced	$	52,000		$	57,000

10. SHARE CAPITAL AND ADDITIONAL PAID IN CAPITAL

Authorized:

June 30, 2008 and December 31, 2007 – 300,000,000 common shares at $0.001 par value

The following share capital transactions occurred during the periods:

Issued	Number		Par Value		Additional Paid in Capital
Balance December 31, 2007		106,692,498	$	106,692	$	39,143,392
Share Issue Costs (a)		-		-		(9,594	)
Private Placement, net of costs (b)		1,204,000		1,204		2,854,730
Warrant converted to common shares (c)		127,500		128		191,122
Stock-based compensation (Note 11)		-		-		355,605
Balance June 30, 2008		108,023,998	$	108,024	$	42,535,255

(a)

During the six months ended June 30, 2008, the Company paid $9,594 in share issue costs which related to common shares issued in 2007.

(b)

On June 18, 2008, the Company closed a private placement for an aggregate of 1,204,000 units at a price of US$2.50 per unit, for gross proceeds of $3,010,000 and share issue costs aggregating $154,066. Each unit consisted of one common share and one warrant which entitles the holder to purchase, until June 18, 2010, one common share of the Company at a price per share of $3.50. In connection with 1,200,000 shares of this private placement, an agent was granted warrants to purchase, until June 18, 2010, 96,000 common shares of the Company at $3.50 per common share.

(c)

In June, 2008, warrant holders converted 127,500 warrants into 127,500 common shares at $1.50 per share.

The following common shares were reserved for issuance:

	Exercise Price ($)		Equivalent Shares Outstanding		Weighted Average Years to Expiry		Option Shares Vested
Stock Options (see summary below)	$	1.28-$2.74		1,926,666		3.84		601,667
Warrants (see summary below)	$	2.50-$3.50		6,123,014		1.45		-
Thunder Acquisition (Note 13)				11,000,000				-
Total Shares Reserved				18,953,680				-

Stock Option Plan

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

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

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

Granted to five directors and one officer Oct. 23, 2006	Oct. 23/11		1,280,000		$	1.50	$	1,920,000
Cancellation of one officer’s option			(280,000	)	$	1.50		(420,000	)
Granted to an employee Dec. 1, 2006	Dec. 1/11		125,000		$	1.28		160,000
Balance December 31, 2006			1,125,000		$	$ 1.48		1,660,000

Granted to an officer Jan. 3, 2007	Jan. 3/12		280,000		$	1.29		361,200
Granted to a consultant Feb. 1, 2007	Feb. 1/12		100,000		$	1.35		135,000
Granted to three senior advisors Apr. 2, 2007	Apr.12/12		300,000		$	1.75		525,000
Granted to two consultants Aug. 1, 2007	Aug. 1/12		130,000		$	2.74		356,200
Granted to a consultant Dec. 1, 2007	Dec. 1/12		100,000		$	2.58		258,000
Balance December 31, 2007		$	2,035,000			1.62	$	3,295,400

Granted to an employee Mar. 24, 2008	Mar. 24/13		25,000		$	1.86		46,500
Cancellation of two senior advisors’ options			(133,334	)	$	1.75		(233,334	)
Balance June 30, 2008			1,926,666		$	1.61	$	3,108,566

Warrants

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

	Exercise Price		Expiry Date	Equivalent Shares Outstanding			Weighted Average Years to Expiry
Balance December 31, 2006	$	2.70-$3.50	June 30/11		1,130,000			3.00

Issued February 20, 2007	$	1.50	Feb. 20/09		860,000			.64
Issued May 10, 2007	$	1.50	May 10/09		2,447,900			.86
Issued September 28, 2007	$	2.50	Mar. 28/09		220,480			.74
Issued September 28, 2007	$	3.00	Mar. 28/09		149,334			.74
Issued October 3, 2007	$	3.00	Apr. 3/09		26,800			.75
Issued October 30, 2007	$	2.50	Apr. 30/09		80,000			.83
Issued October 30, 2007	$	3.00	Apr. 30/09		4,000			.83
Issued November 1, 2007	$	2.50	May 1/09		32,000			.83
Total Issued in 2007					3,820,514
Balance December 31, 2007					4,950,514

Issued June 18, 2008	$	3.50	Jun. 18/10		1,300,000			1.95
Converted upon exercise (Note 10)	$	1.50	May 10/09		(127,500	)

Balance June 30, 2008					6,123,014			1.45

11. STOCK-BASED COMPENSATION

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

	2008	2007

Risk free interest rate	3.99%	3.99%
Expected holding period	3 years	3 years
Share price volatility	75%	75%
Estimated annual common share dividend	-	-

For options granted during the six months ended June 30, 2008, the fair value totaled $23,750 (December 31, 2007 - $ 1,166,000). The amount of share-based compensation expense recorded during the six months ended June 30, 2008 is estimated to be $ 355,605 (December 31, 2007 – $643,934) and has been included in General and Administrative Expense with a corresponding credit to Additional Paid in Capital. The balance of the fair value of the options to be expensed in future periods is $1,039,500 (December 31, 2007 - $1,536,937) over a vesting period of three years.

12. NET INCOME (LOSS) PER SHARE

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

	Three			Three			Six			Six
	Months			Months			Months			Months
	Ended			Ended			Ended			Ended
	June			June			June			June
		30, 2008			30, 2007			30, 2008			30, 2007

Numerator:
Numerator for basic and diluted loss per share
Net Loss	$	(573,187	)	$	(647,052	)	$	(1,035,344	)	$	(961,094	)

Denominator:
Denominator for basic loss per share
Weighted average shares outstanding		106,856,707			92,680,982			106,774,602			91,728,572
In the money stock options		694,273			974,332			632,344			749,881
In the money warrants		1,263,272			2,235,826			1,136,686			2,406,070
Contingent Thunder shares		4,500,000			-			4,500,000			-

Denominator for diluted loss per share
Weighted average shares outstanding		113,314,252			95,891,140			113,043,633			94,884,524

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

Of the contingent shares related to the property acquisition described in note 13, only 4.5 million shares of the 11 million total contingent shares are assumed to be issued for purposes of the diluted loss per share calculations. The 6.5 million shares relating to the significant discovery and production milestones have been excluded because their inclusion would be anti-dilutive.

13. COMMITMENTS AND CONTINGENCIES

Thunder Acquisition Commitments

On September 28, 2007 the Company purchased from Thunder River Energy, Inc. (“Thunder”) certain properties in Canada (Exploration License 413 – “EL 413”) and the United States in consideration for cash and common shares of the Company. As part of the transaction, the Company committed to issue up to 11 million additional common shares of the Company upon the achievement of certain milestones in connection with the acquired properties, including 6 million shares to be issued as follows: 2 million shares upon completion of a 2007/08 seismic program for which such shares were issued in July, 2008; 1 million shares upon the spudding of a shallow depth well (1,500 meters TD) by March 31, 2009; 1.5 million shares upon the spudding of a medium depth well (2,500 meters TD) before license expiry in 2009 and 1.5 million shares upon conversion of any part of EL 413 to a Significant Discovery Lease. An extension to the license expiry date has been applied for and is expected to be approved. If, as a result of the Company’s exploration and development activities on the acquired properties, reserves in place exceed 100 million barrels, then, for each excess 10 million barrels in place, 100,000 additional shares could be issued, up to a maximum of 5 million additional shares.

Canadian Flow-through Share Commitments

In September and October, 2007, 2,251,670 private placement shares were issued at a purchase price of $3.00 for gross proceeds of $6,755,010 and on the basis that the Company would provide the investors a Canadian flow through tax deduction. In order to provide such flow through share tax deduction benefits to the investors, the Company committed to expend the proceeds on eligible capital expenditures in Canada prior to December 31, 2008 and renounce such expenditures to the flow through share investors. In 2008, these expenditures were renounced effective December 31, 2007 and as of June 30, 2008, eligible expenditures had been incurred in an amount sufficient to satisfy this commitment.

Potential Litigation

As of December 31, 2007, there was a threatened litigation matter which comprised a potential claim by a partner against the Company regarding the terms of the EL 413 North West Territory farm-out agreement entered into in 2006. A letter of intent has been signed which will result in Kodiak purchasing the working interest from the partner, thus, the likelihood of any litigation arising out of this matter has lessened significantly and it is not expected to result in any material adverse impact on the Company’s financial position.

14. FINANCIAL INSTRUMENTS

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

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

15. RELATED PARTY TRANSACTIONS

For the six months ended June 30, 2008, the Company paid $ Nil (2007 - $49,610) to Sicamous Oil & Gas Consultants Ltd., a company owned by the President and Chief Executive Officer of the Company for consulting services rendered by him. These amounts were charged to General and Administrative Expense.

For the six months ended June 30, 2008, the Company paid $ Nil (2007 - $26,523) to MHC Corp., a company owned by the former Chief Executive Officer of the Company for consulting services rendered by him. These amounts were charged to General and Administrative Expense.

For the six months ended June 30, 2008, the Company paid $59,685 (2007 – $27,377), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services rendered by him. Of this amount, $26,555 (2007 - $ Nil) was capitalized to Unproved Oil and Gas Properties and $33,130 (2007 - $ Nil) was charged to General and Administrative Expense.

For the six months ended June 30, 2008, the Company paid $107,467 (2007 - $56,374) to the Chief Financial Officer of the Company for services rendered by him. These amounts were charged to General and Administrative Expense.

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

As at June 30, 2008 and December 31, 2007, no other amounts were owing to any related parties.

16. SEGMENTED INFORMATION

The Company’s geographical segmented information is as follows:

Three Months Ended June 30, 2008

Six Months Ended June 30, 2008

	U. S.			Canada		Total		U. S.			Canada		Total
Income during the Evaluation Period	$	-			46		46	$	-			46		46
Net Loss (Income)		(6,134	)		579,321		573,187		(20,840	)		1,056,184		1,035,344
Capital Assets		10,245,994			23,401,513		33,647,507		10,245,994			23,401,513		33,647,507
Total Assets		10,266,176			25,947,992		36,214,168		10,266,176			25,947,992		36,214,168
Capital Expenditures		1,435,783			390,806		1,826,589		3,166,750			6,370,425		9,537,175

	Three Months Ended June 30, 2007						Six Months Ended June 30, 2007
	U. S.		Canada		Total		U. S.		Canada		Total
Income during the Evaluation Period	$	-		42		42	$	-		427		427
Net Loss		9,927		637,125		647,052		12,556		948,538		961,094
Capital Assets		589,885		6,945,449		7,735,334		589,885		6,945,449		7,535,334
Total Assets		678,645		8,920,708		9,599,353		678,645		8,920,708		9,599,353
Capital Expenditures		25,050		1,746,330		1,771,380		25,050		6,190,606		6,215,656

17. CHANGES IN NON-CASH WORKING CAPITAL

												Cumulative
												Since
	Three			Three		Six			Six			Inception
	Months			Months		Months			Months			April 7,
	Ended			Ended		Ended			Ended			2004 to
	June 30,			June 30,		June 30,			June 30,			June 30,
	2008			2007		2008			2007			2008

Operating Activities:
Accounts Receivable	$	(20,157	)		19,030		628,762			(23,283	)		(54,924	)
Prepaid Expenses and Deposits		(5,396	)		3,501		(15,853	)		(23,268	)		(113,361	)
Accounts Payable		33,230			22,835		54,361			7,150			179,237
Accrued Liabilities		5,196			30,696		(50,933	)		(39,787	)		51,062
Other		-			-		-			-			25,000

Total	$	12,873			31,000		616,337			(79,188	)		87,014

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

Accounts Receivable	$	(779,282	)	145,557		(594,127	)	217,495		(1,124,694	)
Prepaid Expenses and Deposits		(35,687	)	(35,585	)	(16,813	)	(33,631	)	220
Accounts Payable		(401,830	)	46,050		(421,083	)	954,850		887,847
Accrued Liabilities		(2,540,058	)	(1,625,342	)	(288,046	)	181,512		145,242

Total	$	(3,756,857	)	(1,469,320	)	(1,320,069	)	1,320,226		(91,385	)
Financing Activities:
The total changes in financing activities non-cash working capital accounts detailed below pertains to shares issued and issuable and has been included in that caption in the Statement of Cash Flow:

Accounts Receivable	$	(180,000	)	-	(180,000	)	-		(180,000	)
Prepaid Expenses and Deposits		-		-	-		-		(10,000	)
Accounts Payable		-		1,223	(113,468	)	(28,849	)	-
Accrued Liabilities		30,000		115,000	30,000		220,000		250,000
Convertible Debt		-		-	-		-		-

Total	$	(150,000	)	116,223	(263,468	)	191,151		60,000

18. SUBSEQUENT EVENTS

Brink Acquisition

On June 19, 2008, the Company entered into an agreement with Brink Energy Ltd. (“Brink”), a private Alberta oil and gas corporation, with respect to a proposed plan of arrangement (“Arrangement Agreement”) which will provide for the Company to acquire all of the outstanding shares of Brink. Under the proposed plan of arrangement, the holders of common shares of Brink (“Brink Shares”) will receive for each Brink Share, at the election of the Brink shareholder, either: (i) 0.411 of a common share of the Company, or (ii) $0.575 plus 0.2055 of a Company share, subject to an aggregate maximum amount of cash paid to Brink shareholders of Cdn. $7 million. Assuming Brink shareholders elect to receive the $7 million maximum cash consideration, the balance of the consideration for the Brink Shares will be paid in Company common shares. The Company has arranged bank financing under commercial terms for a substantial part of the cash portion of the acquisition cost. Under certain circumstances, Brink and the Company have each agreed to pay to the other a non-completion fee of Cdn. $1 million. The Arrangement Agreement is subject to regulatory and Alberta court approval and the approval by a majority of at least two-thirds of Brink shareholders and it is estimated the transaction will close in the fourth quarter of 2008.

In connection with this transaction, the Company has loaned $980,681 (Cdn. $1 million) to Brink, which loan has been utilized by Brink to reduce its bank indebtedness. The loan to Brink bears interest at prime plus 2% and is secured by Brink assets and is subordinated to Brink’s bank indebtedness. The loan is also convertible into common shares of Brink under certain circumstances.

Issue of Shares to Thunder River Energy, Inc.

In July, 2008, the Company issued 2 million common shares to Thunder River Energy, Inc. pursuant to its commitments discussed in Commitments and Contingencies Note 13 under “Thunder Acquisition Commitments”.

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

Forward Looking Statements

From time to time, we or our representatives have made or may make forward-looking statements, orally or in writing. Such forward-looking statements may be included in, but not limited to, press releases, oral statements made with the approval of an authorized executive officer or in various filings made by us with the Securities and Exchange Commission, including this Form 10-Q. Words or phrases "will likely result", "are expected to", "will continue", "is anticipated", "estimate", "project or projected", or similar expressions are intended to identify "forward-looking statements". Such statements are qualified in their entirety by reference to and are accompanied by the above discussion of certain important factors that could cause actual results to differ materially from such forward-looking statements.

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

The financial information set forth in the following discussion should be read in conjunction with management’s discussion and analysis contained in our 2007 Annual Report on Form 10-K as well as the consolidated financial statements and notes thereto included elsewhere herein.

Plan of Operation

The first six months of 2008 has been active with substantial development on each of our three major properties and the initiation of a corporate acquisition which, if such acquisition closes, will provide the Company with its first long term reserves and production. See Note 18 to the Consolidated Financial Statements filed as part of this Form 10-Q discussing the “Brink Acquisition”. During the next twelve months, the Company plans to continue the development of its asset base as well as identify additional assets for addition to our overall land base.

All projects to date have been managed on schedule and within budget as the Company proves to be an effective operator in each jurisdiction in which it operates. In late 2007, a $17.4 million private placement financing was completed under difficult market conditions and in December 2007, the Company’s common shares were listed on the Toronto Venture Exchange in Canada on an aggressive timeline. The Company expects to finance its future capital expenditure programs with combinations of debt and equity financings and some divestitures. As of June 30, 2008, the Company has no secured debt. A description of the company’s recent and planned activities for its core properties is included below.

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

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

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

Core Properties

Canada

Lucy – Northern British Columbia

The Company 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. Other industry participants continue to acquire large land positions in this part of British Columbia which are prospective for this type of play.

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

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

In the third quarter of 2007, the Company served partners with an independent operations notice with the intention of increasing its working interest in the lease. The Company was able to increase its working interest to 80%; however, that process required a substantial amount of title work, which was recently completed.

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 Muskwa Shale with a formation thickness of approximately sixty meters.

The Company submitted an application to the British Columbia Oil & Gas Commission (“OGC”) for an experimental scheme to test the Muskwa Shale gas potential. As of July 15, 2008, the final day that any external party could file a notice of objection to the application, no notices had been filed and approval from the OGC is expected soon.

Kodiak contracted an industry-recognized shale gas assessment laboratory to prepare and analyze the drill cuttings from the 2008 well in order to evaluate the Muskwa Shale interval for gas potential. The shale gas assessment is conducted by performing various tests on the rock cuttings that were obtained while drilling the well in order to determine the type, quality and amount of adsorbed gas 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 shales. It should also be noted that the numbers obtained on the laboratory analysis of drill cuttings may be conservative due to the nature of sampling drill cuttings on a drilling rig. Another significant point is that all three wells on the Kodiak lease drilled deep enough to penetrate the Muskwa Shale had elevated gas detector readings while penetrating the shales.

The prospect is still in the early stages of delineation. However, based on well cuttings and drilling data, Kodiak’s internal technique analysis has estimated the volume of adsorbed and free gas in the Muskwa (Evie) shales to have a potential net reserves of 32.8 bcf per section or 98.4 bcf total. We estimate, based on estimated 20% recovery factor on the three sections of land, a total of 19.7 bcf recoverable contingent resources. In calculating this number, the Company used all of the laboratory analysis findings and wellbore information obtained during the drilling operation. For reference, this internally calculated volume is between the “best” and “high” calculations listed in the Chapman report that only had the TOC analysis and industry available data. Further appraisal work is required before these estimates can be finalized and establish commerciality.

Pending the successful approval of the continuation application the company will execute 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 will provide information that will help define the effective exploration area of the Basin and assist in the validation of adjoining properties in a divestiture process, should that occur.

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

Fourth Quarter 2008 and First Quarter 2009 - Perforate the Muskwa intervals, perform a vertical staged fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to pipeline.

Fourth Quarter 2009 and First Quarter 2010 – Drill and case a 1000 meter horizontal leg from an existing cased vertical well on the lease, perform a horizontal staged fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to pipeline.

Kodiak may accelerate the schedule, if the results of the first program are successful in commercial volumes of gas. In that case, the horizontal test would be completed in the 2009 winter work season.

Little Chicago – Northwest Territories

The Company is the operator and largest working interest owner of the 201,160 acre Exploration Licence 413 (“EL 413”)in the Mackenzie River Valley centered along the planned Mackenzie Valley Pipeline. In 2006, the Company signed an exploration farm-in agreement with the two 50% working interest owners of EL 413. The company reprocessed 50 km of existing seismic data in Q4 of 2006 and during the 2006-07 winter work season, the Company expended approximately $6,500,000 to shoot and acquire 84 km of high resolution 2D seismic data on the farm-out Lands, thus earning a 12.5% working interest in the property. In September, 2007, the Company acquired Thunder River Energy, Inc.’s (“Thunder”) remaining 43.75% in the property giving the Company a 56.25% interest in EL 413. Recently, a letter of intent was signed with the Company’s remaining partner in the project that will allow Kodiak to acquire, upon closing, the balance of the working interest in EL 413 and become a 100% working interest owner.

A 2007-08 43 km 2D high resolution seismic program has been completed on the property and results are being processed and interpreted. This project was completed on budget and schedule for a total cost of $4.5 million. The initial seismic results show substantial structural closure and support the planning for a 2008-09 multiple well drilling program. That data was included in an updated Chapman Prospective Resource report published in May, 2008.

EL 413 (Little Chicago) has two prospective target reservoirs identified by the 2007 and 2008 seismic and gravity surveys, plus a further deeper target, yet to be qualified or quantified. While reviewing core samples and well information from previous regional drilling operations, Kodiak also identified a shallow oil reservoir which is an additional prospective target.

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

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

The 2007 seismic also identified a pinchout at the top of the Precambrian formation that overlies the pinchout of the Basal Sand to suggest a hydrocarbon trap. The two overlying pinchouts present an opportunity for both prospects to be explored. Additional geophysical work was required to target optimum drilling locations.

Thus the decision to acquire additional seismic in the winter of 2008 as there was an identified potential to drill both the Devonian Bear Rock and the Basal Cambrian Sand targets from a common drilling site. This would substantially lower drilling costs on a per well basis and reduce the overall project risk.

The addition of 2008 seismic to the 2007 seismic further defined a hydrocarbon trap in the Basal Cambrian Sand sitting on the top of the PreCambrian. This interval, found at a depth of approximately 2,300 meters (7,545 feet), has never been regionally penetrated and tested; however, it has been proven as a productive reservoir in the Colville Hills area approximately 125 kilometers (77 miles) east of EL 413. With this additional data, the Chapman Report identified five drilling locations that will allow the Basal Cambrian Sand and the top of the Precambrian to be drilled and tested.

Physical evidence of hydrocarbons is present with a natural surface oil seep on the northern edge of the license area on the banks of the Mackenzie River. This natural occurrence is suggestive of a shallow oil pool, possibly in the Canol formation, and warrants further investigation. While reviewing core samples and well logs from previous regional drilling activity. Kodiak was able to map out the Canol/Imperial formation and determine that it is the likely source of the natural surface seeps. This prospect will be found on the Northwest quarter of EL 413 and is at a very shallow depth of approximately 350 meters (1,148 feet).

Internal company review has prioritized the drill locations to two high grade locations that will provide the opportunity to test the Devonian Bear Rock Prospect and the Basal Cambrian Sand/Precambrian Prospect with the same drill site.

It is anticipated that the first two exploratory wells will be drilled during the 2008/2009 winter drilling season. Work has commenced on preparing the necessary permitting applications and the Company is currently working on finalizing the Access and Benefits agreements with the beneficiaries of the land claims – the Gwich’in and Sahtu. These agreements are expected to be finalized in the near future. Part of those negotiations would be a post drilling earning into the property by the Gwich’in and Sahtu to become a working interest partner in the license when converted to a significant discovery license.

In addition, Kodiak has started the process to extend the EL 413 license. Kodiak has initiated discussions with regulators and believes the extension is possible. This will permit an expanded development plan to investigate additional targets identified in the previous seismic programs.

The Company is currently in discussions with other industry partners to share in the costs of the drilling programs, thus reducing risk and capital commitments. Financing plans will be finalized when overall partnerships are established. Kodiak intends on retaining operatorship.

The Company has demonstrated that it is a very effective operator in this challenging environment – with on budget, on schedule projects over the last two winters, excellent relationships with all stakeholders from the Beneficiaries of the Land Claims, to all the regulatory bodies and project contractors in the area. Company management feels a drilling program is technically feasible to implement for the winter of 2008/2009.

United States

New Mexico

Through its acquisition of Thunder, the Company acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Company’s land position to approximately 79,000 acres. These lands have potential for natural gas and CO2 and oil and helium resources at shallow depths.

The Company recently completed a 35 mile 2D high resolution seismic program and a three well drilling program. The three wells were drilled with air to reduce formation damage and they were cased to the base of the Yeso formation. Based on gas detector results, drill cutting samples and open hole logs, all wells showed three potential shallow porous sandstone formations capable of CO2 production with up to 200 feet of identified net pay thickness. The Yeso, Glorieta and Santa Rosa formations were perforated and flow tested to determine deliverability and pressure. There were multiple gas samples analyzed at specialized independent laboratories from two separate extended flow tests that identified CO2 concentration quality from 98.4% to 99.5%. Two of the wells were stimulated with a nitrified acid squeeze and were able to sustain an extended flow rate of approximately 375mcf/d. The shallow sands have been mapped using offset well control and the newly acquired seismic data and the company has determined there is a very high likelihood of encountering the target formations throughout the leased project area.

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

In addition a project feasibility study has been commissioned to identify capital development costs and timelines as well as projected operating costs in order to provide information to support a long term plan of development. These tools will provide the information for negotiating pipeline access, transportation agreements, sales contracts for the CO2, additional land acquisition terms and conditions, facility engineering and construction and ultimately the parameters for financing the project development.

Several companies have expressed interest in participating in the New Mexico properties at several levels of involvement.

Montana

During 2006, the Company, under a joint venture farmout agreement, participated in a seismic acquisition program and a two well drilling program to earn a 50% non-operating working interest in the wells and well spacing. This joint venture project provides the company with the right to participate on a 50% basis going forward on this prospect in the Hill County area of Montana. The Operator of the project had 60,000 contiguous undeveloped acres of P&NG rights in the area, as well as some excess capacity in facilities and pipelines. Two wells were drilled in the third quarter of 2006; one is cased for subsequent evaluation of the multiple zones found and one was abandoned. In order to facilitate the efficient exploration of this prospect area, the company has acquired from the original operator a 100% working interest of 12,000 acres of P&NG rights while retaining the right to participate and initiate operations on the remaining approximate 48,000 acres of prospect leases. The Montana prospect is currently being reviewed by the company’s staff geologist and an exploration program consisting of seismic and drilling will be proposed for Q4 2008/Q1 2009.

Financial Condition and Changes in Financial Condition

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

As a result of the brokered private placement financings completed in late 2007 and in June, 2008, the Company was able to conduct an aggressive capital expenditure program in the first half of 2008. The Company’s total assets have increased to $36,214,168 as at June 30, 2008 from $34,690,768 at the end of 2007 and just $2,707,075 at the end of 2006. These increases resulted from the capital expenditure programs undertaken by the Company in the first quarter of 2008 and 2007 and the financings described under “Liquidity and Capital Resources”. Total assets consist of cash and other current assets of $2,220,358 (December 31, 2007 - - $10,288,410); unproved oil and gas properties and equipment of $33,647,507 (December 31, 2007 - $24,043,005); and other assets of $346,303 (December 31, 2007 - $359,353). Our total current liabilities were $1,513,386 (December 31, 2007 - $2,302,555) and consisted of accounts payable and accrued liabilities relating to capital activities and general and administrative costs incurred. We had long term liabilities of $46,898 (December 31, 2007 - $110,955), asset retirement obligations of $244,401 (December 31, 2007 - $151,814), and deferred income taxes payable of $52,000 (December 31, 2007 - $57,000). Shareholders’ equity amounted to $34,357,483 (December 31, 2007 - $32,068,444), net of an accumulated deficit of $7,874,783 (December 31, 2007 - $6,839,439).

Overall Operating Results

In the six months ended June 30, 2008, the Company had income during the evaluation period of $ 46 (2007 - $427) and operating costs of $5,273 (2007 - $11,600) relating to 2006 production from its Granlea, Alberta project. The well watered out in late 2006 and was deemed uneconomic. Except for that small amount of production, the Company remains in the exploration stage.

In the three months ended June 30, 2008, the Company had income during the evaluation period of $ 46 (2007 - $42) and operating costs of $4,999 (2007 - $964) relating to Granlea.

Net Loss for the six months ended June 30, 2008 totalled $1,035,344 (2007 – Net Loss $961,094). As well as the operating expenses referred to above, expenses during the period consist of general and administrative expenses of $1,070,083 (2007 - $853,989), including stock-based compensation expense amounting to $355,605 (2007 - $279,083); depletion, depreciation and accretion of $ 25,277 (2007 - $22,143) and interest expense of $1,257 (2007 - $18,808).

Net Loss for the three months ended June 30, 2008 totalled $573,187 (2007 – Net Loss $647,052). As well as the operating expenses noted above, expenses during the period consist of general and administrative expenses of $557,918 (2007 - $559,477), including stock-based compensation expense amounting to $165,469 (2007 - $155,269); depletion, depreciation and accretion of $13,573 (2007 - $12,622) and interest expense of $1,257 (2007 - $18,808).

General and administrative expenses include the cost of employed and consulting personnel and others who provided investor relations services, public company costs for SEC reporting compliance, accounting, audit and legal fees and other general and administrative office expenses. General and administrative expense also includes stock-based compensation relating to the cost of stock options granted to directors, officers, employees and other personnel. General and administrative costs have been increasing as the scope of the company’s activities have increased and we believe substantial amounts will continue to be spent on such costs in the near term as we progress with the evaluation of our oil and gas prospects. A significant increase in our shareholder base from 1,000 to approximately 8,000 shareholders during the past year has also contributed to our increased general and administrative costs.

Depletion, depreciation and accretion for the three and six months ended June 30, 2008 and 2007 includes the cost of depreciation relating to office furniture and equipment. All of the remaining capitalized costs relate to Canadian and United States unproven properties and have been excluded from the depletable cost pools for ceiling test purposes.

Deferred income tax expense, for the three and six months ended June 30, 2008 includes a provision for future income taxes of $ Nil (2007 - $55,480).

Capital Expenditures:

Capital Expenditures incurred by the Company during the three and six months ended June 30, 2008 and 2007 are set out below.

	Three Months					Six Months
	Ended June 30					Ended June 30
	2008		2007			2008		2007

Land acquisition and carrying costs	$	566,319	$	505	)	$	1,172,250	$	27,441
Geological and geophysical		439,842		1,531,360			4,552,835		5,880,837
Intangible drilling and completion		844,761		234,301			3,779,509		266,234
Tangible completion and facilities		38,361		18,020			95,275		52,940

Total Capital Costs Incurred	$	1,889,283	$	1,783,176		$	9,599,869	$	6,227,452

Land acquisition and retention costs include the cost of new acreage acquired in New Mexico and ongoing property retention.

Geological and geophysical costs include the costs of the seismic programs carried out on the EL 413 Little Chicago, North West Territory project in 2008 and 2007 and the New Mexico seismic program for 2008.

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

Liquidity and Capital Resources:

Since inception to June 30, 2008, the company’s operations have been financed from the sale of securities and loans from shareholders. Working capital at June 30, 2008 amounted to $706,972 (December 31, 2007 - $7,985,855).

During the six months ended June 30, 2008, the Company raised $2,855,934, net of share issue costs, in private placement financing proceeds. This financing has enabled the Company to fund its on-going capital expenditures and general and administrative expenses. The Corporation currently has no long term debt obligations.

The Company is seeking additional financing, either through debt, equity or a combination thereof to cover the estimated cost of its planned programs for the balance of 2008 and into 2009. In addition, we may require funds for additional acquisitions. In the event that additional capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Corporation.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Petroleum and Natural gas and Related Hydrocarbon Prices

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

Foreign Currency Exchange Rates

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

Interest Rates

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

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this report, they concluded that, our disclosure controls and procedures were adequate and effective and appropriate to a company of its size and stage of corporate development in ensuring that material information relating to the Company would be made known to them by others within those entities and that our disclosure controls and procedures were effective to ensure that information required to be disclosed in the reports that the Company files or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms. Our disclosure controls and procedures were also effective to ensure that information that the Company is required to disclose in the reports that it files or submits under the Exchange Act is accumulated and communicated to Company management, including our chief executive officer and chief financial officer, as appropriate to allow for timely decisions regarding required disclosure. 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.

Segregation of Duties and Access to Critical Accounting Systems

As at December 31, 2007, we had a material weakness related to certain employees who had incompatible responsibilities within all significant processes affecting financial reporting. This weakness relates to the fact that our Company has only two individuals in our finance and accounting department, and it is very difficult to have effective delegation of duties in all circumstances. 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.

Our management has discussed the material weaknesses described above and other deficiencies with our Audit Committee. In an effort to remediate the identified material weaknesses, we have initiated plans to undertake the following remediation activities:

We established segregation of duties matrices and reviewed the job responsibilities of our personnel to evaluate how to create appropriate segregation of duties, to the extent economically feasible given the size and complexity of our operation. To the extent technically possible, we limit user access in order to segregate duties within our IT systems and to maintain appropriate corporate confidentiality. Where that is not possible, we plan to implement controls, prior to yearend 2008,to verify that incompatible functions performed by the same individual are appropriately monitored. In any case, our accounting system functions are maintained in a robust external audited system with its own multiple levels of checks and balances.

We have documented this assessment and made this assessment available to our independent registered Chartered Accountants. We recognize that all internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Other than the afore-mentioned material weakness, management believes our internal control over financial reporting has been effective during three and six months ended June 30, 2008.

CHANGES IN INTERNAL CONTROLS

There have been no changes in our internal control over financial reporting during our fiscal quarter ended June 30, 2008 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting other than the consideration and furtherance of our plans to remediate the weakness referred to above.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is not presently a party to any litigation. As at December 31, 2007, there was a threatened litigation matter against the Company which comprised a potential claim by a partner regarding the terms of the EL 413 North West Territory 2006 farm-out agreement. A letter of intent has been signed which will result in Kodiak purchasing the working interest from the partner, thus, the likelihood of any litigation arising out of this matter has lessened significantly and it is not expected to result in any material adverse impact on the Company’s financial position.

ITEM 1A. RISK FACTORS

Going Concern Uncertainty

The Oil and Gas Industry Is Highly Competitive

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

Government and Environmental Regulation

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

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

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

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

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

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

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

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

We are an exploration stage company with only a limited operating history upon which to base an evaluation of our current business and future prospects, and we have just begun to implement our business plan. Since our inception, we have suffered recurring losses from operations and have been dependent on new investment to sustain our operations. During the six months ended June 30, 2008 and the years ended December 31, 2007, 2006 and 2005, we reported losses of $1,035,344, $2,775,663, $2,867,374 and $1,133,790 respectively. In addition, our consolidated financial statements for the six months ended June 30, 2008 and the years ended December 31, 2007, 2006 and 2005 contained a going concern qualification and we cannot give any assurances that we can achieve profits from operations.

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

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

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

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

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

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

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

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

Risks Of Penny Stock Investing

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

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

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

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

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

On June 18, 2008, pursuant to subscription agreements, the Company closed a private placement with three investors for 1,204,000 units at a price of $2.50 per unit for gross proceeds of $3,010,000. Each unit entitled the subscriber to one common share of the Company and one common share purchase warrant. Each warrant entitles the warrant holder to exchange one warrant for one common share of the Company at a price of $3.50 until June 18, 2010. The common shares were issued pursuant to Regulation “S” (“Regulation “S”) under the Securities Act of 1933, as amended (the “1933 Act”).

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

Item 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBITS

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

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

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

SIGNATURES

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

	KODIAK ENERGY, INC.
		(Registrant)

Dated: August 11, 2008		By: /s/ William S. Tighe
		William S. Tighe
		Chief Executive Officer

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Kodiak Energy (KDKN) Inactive 10-Q2008 Q2 Quarterly report

Content analysis