Cougar Oil & Gas Canada 20F 2010 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)
[ ]	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934

[ ]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

	For the transition period from July 31, 2010 to December 31, 2010

[ ]	SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	Date of event requiring this shell company report: _______________

333-149325
Commission File Number

COUGAR OIL AND GAS CANADA INC.
(Exact name of registrant as specified in its charter)

N/A
(Translation of Registrant’s name into English)

Alberta, Canada
(Jurisdiction of incorporation or organization)

833 4th Avenue S.W., Suite 1120; Calgary, Alberta T2P 3T5 Canada
(Address of principal executive offices)

William S. Tighe 833 4th Avenue S.W., Suite 1120; Calgary, Alberta T2P 3T5 Canada Tel: (403) 262-8044 E-mail: wmstighe@cougarenergyinc.com
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class	Name of each exchange on which registered
N/A	N/A

Securities registered pursuant to Section 12(g) of the Exchange Act:

Title of class

Common Shares

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Exchange Act:

Title of class

N/A

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the close of the period covered by the annual report.

66,485,661 shares of common stock issued and outstanding as of March 21, 2011

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes

[ ]

[X]

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes

[ ]

[X]

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 of 1934 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 ]

[ ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes

[ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definitions of “large accelerated filer,” “accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	[ ]	Accelerated filer	[ ]
Non-accelerated filer	[X]

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP	[X]	Other	[ ]

International Financial Reporting Standards as issued by the International Accounting Standards Board			[ ]

If “Other” has been checked in response to the previous questions, indicate by check mark which financial statement item the registrant has elected to follow.

Item 17

[ ]

Item 18

[ ]

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes

[ ]

[X]

APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PAST 5 YEARS:

Indicate by check mark whether the issuer has filed all documents and reports required to be filed by Section 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

Yes

[ ]

TABLE OF CONTENTS

		Page
PART I
	Glossary	4
	Forward Looking Statements	6
Item 1.	Identity of Directors, Senior Management and Advisors	6
Item 2.	Offer Statistics and Expected Timetable	6
Item 3.	Key Information	6
Item 4.	Information on our Company	15
Item 4A.	Unresolved Staff Comments	26
Item 5.	Operating and Financial Review and Prospects	27
Item 6.	Directors, Senior Management and Employees	38
Item 7.	Major Stockholders and Related Party Transactions	45
Item 8.	Financial Information	46
Item 9.	The Offer and Listing	46
Item 10.	Additional Information	47
Item 11.	Quantitative and Qualitative Disclosures about Market Risk	55
Item 12.	Description of Securities other than Equity Securities	55

PART II
Item 13.	Defaults, Dividend Arrearages and Delinquencies	55
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds.	55
Item 15T.	Controls and Procedures	55
Item 16.	[Reserved]	57
Item 16A.	Audit Committee Financial Expert	57
Item 16B.	Code of Ethics	57
Item 16C.	Principal Accountant Fees and Services	57
Item 16D.	Exemptions from the Listing Standards for Audit Committees	58
Item 16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	58
Item 16F	Change in Registrant’s Certifying Accountant	58
Item 16G	Corporate Governance	58

PART III
Item 17.	Financial Statements	59
Item 18.	Financial Statements	59
Item 19.	Exhibits	67
	Signatures	67

GLOSSARY

Following is a glossary of terms used throughout this Annual Report. Some of the definitions below have been abbreviated from the applicable definition contained in Rule 4-10(a) of Regulation S-X

Development Stage	Includes all companies engaged in the preparation of an established commercially producible oil or gas accumulations (reserves) for its extraction, which are not in the production stage.
Exploration Stage	All companies engaged in the search for oil or gas accumulations (reserves), which are not in either the development or production stage.
Feasibility Study	A detailed report assessing the feasibility, economics and engineering of placing an oil or gas mineralization into commercial production.
Development and Production status	Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories.
Proven reserves	Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable reserves	Reserves for which quantity and grade and/or quality are computed from information similar to Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible reserves	Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Developed Reserves	Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
Developed Producing Reserves	Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed Non-Producing Reserves	Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
Undeveloped Reserves	Undeveloped Reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
Prospect	An area prospective for economic mineralization’s based on geological, geophysical, geochemical and other criteria
Equisetum Field.	This is a strike area where a gas or oilfield has been established and the Energy Resources Conservation Board (ERCB) of the Province of Alberta had issued a spacing unit or other approval. The Equisetum Field is located in the general area of West of the 5th Meridian, Township 88, and Ranges 5 to 6.

Kidney Field

This is a strike area where a gas or oilfield has been established and a spacing unit or other approval had been issued by the ERCB of the Province of Alberta. The Kidney Field is located in the general area of West of the 5th Meridian, Townships 89 to 92, and Ranges 3 to 7.

Muskwa Shale.

The Muskwa formation occurs in northern Alberta, northeastern British Columbia and in the southern part of the Northwest Territories. Gas is produced from the Muskwa formation shales in the Horn River Basin in the Greater Sierra oil field in northeastern British Columbia. Horizontal drilling and fracturing techniques are used to extract the gas from the low permeability shales. The formation typically has a thickness of 34 meters (110 ft.).

For ease of reference, the following conversion factors are provided:

1 mile (mi)	= 1.609 kilometers (km)
1 yard (yd.)	= 0.9144 meter (m)
1 acre	= 0.405 hectare (ha)

PART I

Cautionary Notice Regarding Forward-Looking Statements

Except for the statements of historical fact contained herein, some information presented in this annual report constitutes forward-looking statements as that term is defined in Section 27A of the United States Securities Act of 1933 and Section 21E of the United States Securities Exchange Act of 1934. These statements relate to future events or our future financial performance. When used in this annual report, the words "estimate", "project", "believe", "anticipate", "intend", "expect", "predict", "may", "should", the negative thereof or other variations thereon or comparable terminology are intended to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of our company to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include those discussed in the section entitled "Risk Factors". Although we have attempted to identify important factors that could cause actual results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. Accordingly, prospective investors should not place undue reliance on forward-looking statements. The forward-looking statements in this annual report speak only as to the date hereof. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to actual results.

As used in this annual report, the terms "we", "us" "our" and Company mean Cougar Oil and Gas Canada, Inc., unless otherwise indicated.

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable for annual reports.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable for annual reports.

ITEM 3. KEY INFORMATION

Financial Information and Accounting Principles

The financial statements and summaries of financial information contained in this annual report are reported in Canadian dollars unless otherwise stated. All such financial statements have been prepared in accordance with United States generally accepted accounting principles.

The financial statements of our Company for the 5 month period ended December 31, 2010 have been audited by RBSM LLP, a registered public accounting firm.

A. Selected Financial Data

The following tables summarize selected financial data for our Company, stated in Canadian dollars and prepared in accordance with United States generally accepted accounting principles for the 5 month periods ended December 31, 2010 and December 31, 2009. Accordingly, we are presenting only two periods of selected financial data. The information in the table was extracted from the financial statements and related notes included in this annual report and reports that were previously filed and should be read in conjunction with such financial statements.

	5 Months ended December 31,			5 Months ended December 31,
	2010			2009
Operating Revenues	$	1,178,303		$ 629,993
Income (loss) from Operations	$	(968,200	)	$	(2,716,290	)
Net Income (loss)	$	(1,127,354	)	$	(2,315,670	)
Net Income (loss) per share	$	(0.02	)	$	(0.05	)

	5 Months ended December 31,		5 Months ended December 31,
	2010		2009
Total assets	$	10,267,188	$	9,243,042
Stockholder equity	$	1,020,452	$	1,521,938
Common stock	$	5,207,027	$	4,219,164
Additional paid in capital	$	622,174	$	128,210
Number of shares issued and outstanding		64,047,111		44,997,979

Exchange Rates

All of the transactions undertaken by the Company are reported in Canadian Dollars. Therefore, this annual report may contain conversions of certain amounts in United States dollars into Canadian dollars based upon the exchange rate in effect at the end of the month or of the fiscal year to which the amount relates, or the exchange rate on the date specified. For such purposes, the exchange rate means the noon buying rate for United States dollars from the Bank of Canada. These translations should not be construed as representations that the Canadian dollar amounts actually represent such United States dollar amounts or that Canadian dollars could be converted into United States dollars at the rate indicated or at any other rate.

The exchange rate (represented as the amount US$ that CAD$1.00 would be converted to) as of December 31, 2010, the latest practicable date, was USD: $1.0054.

The monthly high and low exchange rates for the most recent six months:

	July		August		September		October		November		December
High for period		0.9724		0.9844		0.9783		0.9970		0.9987		1.0054
Low for period		0.9381		0.9397		0.9506		0.9690		0.9743		0.9825

The average period exchange rate, calculated by using the average of the exchange rates on the last day of each month during the period:

	5 months ended December 31,		5 months ended December 31
	2010		2009
Average Rate:		0.9744		0.9348

B. Capitalization and Indebtedness

Not applicable.

C. Reasons for the Offer and Use of Proceeds

Not applicable.

D. Risk Factors

Our business entails a significant degree of risk, and an investment in our securities should be considered highly speculative. An investment in our securities should only be undertaken by persons who can afford the loss of their entire investment. The following is a general description of material risks, which may adversely affect our business, our financial condition, including liquidity and profitability, and our results of operations, ultimately affecting the value of an investment in shares of our common stock.

RISKS RELATING TO OUR BUSINESS

Financial Markets Instability and Uncertainty

The 2008/09 worldwide financial and credit crisis severely restricted the availability of capital and credit to fund the continuation and expansion of junior oil and gas operations worldwide. The shortage of capital and credit, combined with substantial losses in worldwide equity markets, led to an extended worldwide economic recession and a very slow drawn out recovery. This limited access to capital still exists today except on extremely dilutive or restrictive terms for exploration and development. This recession has reduced worldwide demand for energy, resulting in generally lower and more volatile oil and natural gas and other commodity prices. Oil has recovered from its lows somewhat, however, natural gas continues to be depressed due to an excess of supply due to technological advancements. The prolonged reduction in oil and natural gas prices has depressed the levels of exploration, development and production activity that impacting negatively on our Company’s ability to raise capital to finance our ongoing capital projects. The Company may be required to consider divestiture of some properties or working interests to raise funds. Until the financial market conditions improve, we will face significant challenges in meeting our ongoing financial obligations. This continuing global financial crisis may have differing impacts on our business and financial condition that we cannot currently predict. Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our business, financial condition and results of operations. A general slowdown in economic activity could adversely affect our business by impacting our ability to access additional exploration and development capital in the interim.

The Oil and Gas Industry Is Highly Competitive

The oil and 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 financing and 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.

Trends and Uncertainties

We are subject to the following trends and uncertainties:

Adverse weather conditions that may affect our ability to conduct our exploration activities;

	·	General economic conditions, including supply and demand for petroleum based products in Canada, the United States, and remaining parts of the world;

Political instability in the Middle East and other major oil and gas producing regions;

Domestic and foreign tax policy;

Price of oil and gas foreign imports;

Cost of exploring for, producing, and delivering oil and gas;

Overall supply and demand for oil and gas;

Availability of alternative fuel sources;

Discovery rate of new oil and gas reserves; and

Pace adopted by foreign governments for the exploration, development and production of their national reserves.

Any one trend or uncertainty, or a combination of, could have an adverse impact on our operations, revenues or our ability to continue our business as currently contemplated.

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.

We Are an Early Stage Company Implementing a New Business Plan

We are an early 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 for the development stage prospects.

The Successful Implementation of Our Business Plan is Subject to Risks Inherent in the Oil and 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 in the Future and May Need to Raise Additional Funds

As our operations grow and develop, so will our operating expenses. We have a history of net losses and may incur additional losses and operating expenses over the next 12 months as we continue to develop our business plan. In addition, we may experience a material decrease in liquidity due to unforeseen expenses or other events beyond our control. As a result, we will 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.

Operational Risks

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state, provincial, territorial and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies – federal, state, provincial, and territorial – are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply.

Legislation continues to be introduced and revised. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility, security laws or regulations, but such expenditures could be substantial.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating hazards and risks that could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation, and penalties and suspension of operations.

In addition, we may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We carry business interruption insurance and protection against loss of revenues. In addition we purchase specific exploration insurance to cover typical exploration risks. Any insurance we obtain may not be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. We may elect to self-insure if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have material adverse effects on our financial condition and results of operations.

We are not currently participating in any non-operated wells and accordingly are not exposed to the risks associated with non-operated participation in oil and natural gas operations.

Title to Oil and Natural Gas Properties

We believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry in Canada and specific to the jurisdiction in which the properties reside.

Although title to these properties is subject to encumbrances, in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry; we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In some cases, lands over which leases have been obtained may be subject to prior liens that have not been subordinated to the leases. In addition, we believe we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Pipeline Rights-of-Way

Substantially, all of our gathering systems and pipelines are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our facilities are located on property owned in fee or on property obtained via long-term leases or surface easements.

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and provincial or state highways, where necessary.

Certain of our rights to lay and maintain pipelines are derived from recorded oil and gas leases for wells that are currently in production, however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-ways will not be used for any other purpose once the related wells cease to produce.

Seasonal Nature of Business

Seasonal weather conditions, road bans and lease stipulations can limit our developmental activities and other operations and, as a result, we seek to perform a significant percentage of our development during the summer, fall and winter months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the summer, fall and winter months, which could lead to shortages, increase costs or delay our operations.

In addition, freezing weather, winter storms, and flooding in the spring and summer may impact operations, which could adversely affect our production volumes and revenues and increase our lease operating costs due to the time spent by field employees to bring the wells back on-line.

Environmental, Health and Safety Matters and Regulation

General

Our operations are subject to stringent and complex federal, provincial and local laws and regulations governing environmental protection as well as the discharge of materials into the environment, the generation, storage, transportation, handling and disposal of wastes, the safety of employees and governing the protection of human health and safety. These laws and regulations may, among other things:

require the acquisition of various permits before exploration or development commences;

limit or curtail some or all of the operations of facilities deemed in non-compliance with permits or other legal requirements;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production, gathering, treating and transportation activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas;

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells, and restore, remediate or mitigate impacted environmental media.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, federal, provincial and territorial agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The oil and gas industry, in particular, has recently come under greater scrutiny by environmental regulators and non-governmental organizations. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements, or restrictions, or other regulatory burdens on operations of the oil and gas industry, could have a significant impact on our operating costs.

Waste Management

Waste management is governed by various regulatory agencies enforcing specific federal, provincial, territorial, and state regulations and statutes. These regulatory agencies regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. The Company is strictly compliant and will maintain compliance with all applicable waste management regulations and requirements regarding drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas.

Comprehensive Environmental Response, Compensation, and Liability

We currently own, lease or operate numerous properties that have been used for oil and gas exploration, production, and transportation. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. Under such laws, we could be required to remove previously disposed substances and wastes, including wastes disposed of or released by us or prior owners or operators in accordance with the then current laws or otherwise, remediate contaminated property, perform plugging or pit closure operations to prevent future contamination, or take other environmental response actions.

Water Discharges and Water Quality

Water discharge and water quality is governed by various regulatory agencies enforcing specific federal, provincial, territorial, and state regulations and statutes. These regulatory agencies impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the province. The Company is strictly compliant and will maintain compliance with all applicable regulations and requirements regarding water discharges and water quality. Spill prevention, control and countermeasure requirements of the regulatory agencies may require appropriate containment berms and similar structures to help prevent any type of fluid discharge in the event of a petroleum hydrocarbon tank spill, rupture or leak.

Our operations also produce wastewaters that are disposed via underground injection wells. These activities require a permit and are subject to applicable regulatory agency requirements. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.

Air Emissions

Air emissions are governed by various regulatory agencies enforcing specific federal, provincial, territorial and state regulations and statutes. These regulatory agencies regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require The Company to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

Our Ability to Produce Sufficient Quantities of Oil and Gas from Our Properties May Be Adversely Affected by a Number of Factors outside Our Control

The business of developing and exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil wells involves the risk that wells may be unproductive or, although productive, 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, the environmental and access issues that could limit future drilling activities for the industry and various forms of political instability in oil producing regions of the world.

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 RELATING TO OUR COMMON SHARES AND THE TRADING MARKET

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 the NASD's automated quotation system (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 disclosures 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.

Since we are a “Foreign Private Issuer” under United States Securities Laws, our stockholders may have less complete and timely data about us.

We are considered a “foreign private issuer” under the Securities Act of 1933, as amended. As an issuer incorporated in Alberta, Canada, we are exempt from Section 14 proxy rules and Section 16 of the Securities Exchange Act of 1934, as amended. The submission of proxy and annual meeting of stockholders information (prepared to Canadian standards) on Form 6-K and the exemption from Section 16 rules regarding sales of Common Shares by insiders may result in stockholders having less complete and timely data as compared to information that may be available about U.S. issuers.

We have not and do not intend to pay any cash dividends on our Common Shares, and consequently our stockholders will not be able to receive a return on their shares unless they sell them.

We intend to retain any future earnings to finance the development and expansion of our business. We have not, and do not, anticipate paying any cash dividends on our Common Shares in the foreseeable future. Unless we pay dividends, our stockholders will not be able to receive a return on their shares unless they sell them.

We may, in the future, issue additional Common Shares or other securities,

We may for purposes of growth, development and or debt restructuring issue Common shares or other securities including our Preferred Shares, which would reduce investors’ percentage ownership and may dilute the value of our shares.

Our Articles of Incorporation authorize the issuance of an unlimited number of Common Shares without par value and an unlimited number of Preferred Shares without par value. We may value any securities issued in the future on an arbitrary basis. The issuance of additional securities for future services or acquisitions or other corporate actions may also have the effect of diluting the value of the shares held by our investors and might have an adverse effect on the trading market for our Common Shares.

Our Board of Directors may issue, without stockholder approval, Preferred Shares that have rights and preferences superior to those of Common Shares and that may delay or prevent a change of control. At the present time, there are no Preferred Shares outstanding. However, our Board of Directors may set the rights and preferences of any class of Preferred Shares in its sole discretion without the approval of the holders of Common Shares. The rights and preferences of these Preferred Shares may be superior to those of the Common Shares. Accordingly, the issuance of Preferred Shares may adversely affect the rights of holders of Common Shares. The issuance of Preferred Shares also could have the effect of delaying or preventing a change of control of the Company.

ITEM 4. INFORMATION ON OUR COMPANY

History and Development of the Company

Cougar Oil and Gas Canada, Inc. (“Cougar”, “we”, “us”, “our”), formerly Ore-More Resources, Inc., was incorporated under the laws of the Province of Alberta, Canada on June 20, 2007. Our principal activity is in the exploration, development, production and sale of oil and natural gas.

Our main operations are currently in the Alberta and British Columbia provinces of Canada. Our focus has developed into the specific projects of:

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

Peerless/Trout Lake Joint Venture Projects, Alberta - mineral leases, exploration and development opportunities within and adjacent to the Peerless Lake/Trout Lake Land Entitlement Claim.

Other Joint Ventures with Alberta Treaty Land Entitlement Claims;

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

Other Alberta properties.

The consolidated financial statements include the accounts of Cougar and Cougar Energy, Inc., a wholly-owned subsidiary, are thereafter collectively referred to as “we”, “us”, “our” or, the “Company”. All significant intercompany balances and transactions have been eliminated in consolidation. See subsequent event note regarding the amalgamation of Cougar Energy, Inc. and Cougar Oil and Gas Canada Inc.

Reverse Acquisition

In January 2010, the Company entered into a stock purchase Agreement (the “Agreement”) with Cougar Energy, Inc. (referred to as CEI) and CEI’s then shareholders whereby the Company agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:

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

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

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

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

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

b) On January 25, 2010, the Company finalized a share purchase agreement between the Company and Kodiak Energy Inc. (“Kodiak”) whereby the Company purchased from Kodiak a total of 8,461,549 (38,076,933 shares post split) shares of the common shares of CEI held by Kodiak. The share purchase agreement called for the Company to issue a total of 1.5 shares of common stock for each share of CEI tendered by Kodiak, resulting in the Company issuing a total of 12,692,324 shares of common stock. As further consideration for the acquisition of the CEI common shares, the Company forgave all current indebtedness owed to the Company by Kodiak and guaranteed by CEI, which was in the amount of $1,296,889 (CDN $1,357,714). An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Company were cancelled.

Upon consummation of the acquisition, CEI became the only wholly owned subsidiary of the Company. Subsequently, on February 4, 2010, the Company filed a Certificate of Amendment to its Certificate of Incorporation with the Registrar of Corporations in Alberta, Canada, changing the Company’s name to “Cougar Oil and Gas Canada Inc.”. As a result of the change of name, the OTC Bulletin Board symbol under which the common stock trades changed from “OMORF.OB” to “COUGF.OB” effective February 22, 2010.

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

Prior to the acquisition of CEI, the Company had operating assets and activities within the oil and gas industry, and therefore the acquisition of CEI is not characterized as a shell transaction under SEC rules and regulations.

On January 25, 2010, Cougar Oil and Gas Canada Inc. (“Cougar Canada”) announced that its board of directors and shareholders approved a forward split of the outstanding common stock at the rate of one share into three shares. The forward stock split had a record date of February 22, 2010 and a payment date of February 25, 2010. As a result of the forward stock split, the number of issued and outstanding shares of the Company's common stock increased from 19,635,397 to 58,906,191 shares.

Kodiak Energy acquired 64.6% of the common stock ownership of the Company. The Company’s ownership of Cougar Energy was 92% prior to that point.

On March 15, 2010, the board of directors of the Company held a meeting and appointed Mr. Glenn Watt and Mr. William Brimacombe as directors to the Board of Directors, to take effect immediately. The Board of Directors also appointed Mr. William Tighe as Chief Executive Officer and Mr. Glenn Watt as Chief Operating Officer of Cougar Canada.

The Company held its annual meeting of shareholders on June 1, 2010, at which the shareholders approved the size of the board of directors to be five persons.

The Company’s principal executive offices are located at 833 4th Avenue S.W., Suite 1120, Calgary, AB, Canada and our telephone number is (403) 262-8044.

Oil and Gas Assets

Through the Company’s wholly owned subsidiary, Cougar Energy, Inc., the Company’s focus is in the primary projects of:

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

First Nation Joint ventures – exploration and development opportunities with the adjacent First Nation Communities and other communities;

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

Other Alberta properties.

Cougar Trout Properties, (Alberta Core Area)

During the third quarter of calendar 2009, Cougar Energy, Inc., the Company’s wholly owned subsidiary, completed the following transactions.

Trout Core Properties-

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

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

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

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

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

The agreed purchase price was Cdn$6,000,000 with an initial payment of Cdn$1,000,000 at closing. The purchase price was negotiated at $52.50 per barrel (bbl) when oil was currently selling at $75+/bbl. Included 7,100 gross acres of mineral rights with an average 85% working interest (all continued through production, no expiries). 85 bbl/d at time of acquisition with 13 pumping wellbores – 8 at time of acquisition 1 observation wellbore and 21 suspended wellbores, 8 single well batteries, 3 water disposal wellbores with associated facilities, 2 multi well batteries with existing fluid handling capacity in excess of 2500bbl/day (oil, gas and water handling and treating capability, approximately 38.7 km of pipelines) (oil and produced water), approximately 13 km2 of 3D seismic over the properties and approximately 84 km of 2D seismic over the properties and adjacent lands. The majority of this acquisition is outside the boundary of the Peerless Trout Lake First Nations. The current surface facilities have a replacement value of Cdn$6,500,000 with a depreciated value of Cdn$1,000,000. The overall project has an estimated Cdn$50,000,000 in replacement value including wells, facilities, pipelines, roads and power lines.

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

This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs, lower development costs and giving our schedule an 1-3 year leap forward to achieve our goals of creating a 3- 5,000bbl/d company in a short period of time. Without this kind of infrastructure, the initial production would have lower netbacks due to higher trucking costs and regular non-producing periods due to weather. In lieu of this acquisition, a large amount of capital would have to be spent to bring facilities to this baseline, which we now have. At current costs, the infrastructure replacement value would be substantially in excess of Cdn$6,000,000. This capital will be spent on the drilling and development work, allowing for a more aggressive growth plan.

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

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

During 2010 the Company had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. The Companies monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day but this production potential has been curtailed as a result of ongoing maintenance and repair issues over the reporting period. As these maintenance and repair issues are resolved over the next year, it is anticipated production will increase accordingly. It is also anticipated production will increase as a result of the ongoing development drilling operations. We averaged $30.00/bbl for the year ended 2010 for operating costs including maintenance costs. We believe that through ongoing maintenance and upgrades, we will reduce those costs to the $25 Cdn range and perhaps as low as $17 Cdn which we have experienced for short periods of time. We continue to receive $50 plus as a net back after royalties and are net positive for operations at year end.

Refer to the Companies reserves report for additional information regarding NPV and forecast production.

The Trout field is a technically complicated field to operate as a result of two common wellbore scenarios. These scenarios include managing very high water cuts which results in excessive equipment fatigue and the extremely corrosive uphole formations which result in multiple casing failures. The Company identified these two scenarios prior to purchasing the Trout properties and believes the technical complexity of the Trout field reduces competition from entering the area resulting in additional available economic upside. Through our close attention to detail, extensive operations/maintenance experience, both down hole and at surface – we have the ability to manage costs, technical problems at a level not typically possible by majors.

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

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

(a)

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

(b)

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

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

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

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

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

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

Subsequent Maintenance Programs on all Properties

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

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

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

G. Acquisition of Seismic - Cougar has purchased and evaluated 10.4Km2 of high resolution Trout Core area 3D seismic data. From the review we identified five (5) drilling targets and proceeded with the permitting for a three (3) well Keg River light oil drilling program for the winter of 2010/2011. – two wells were licensed, leases built and one well spudded and drilled to depth. The well has been put on production for testing at time of filing.

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

Reserve Evaluations and Operations Update Reviews (October 1, 2009, December 31, 2009 and July 31, 2010 and December 31, 2010).

These independent engineering reports were prepared by GLJ and are based on the acquisitions of September 30, 2009 and October 1, 2009. The reports update the look forward reports that were prepared as part of the negotiations for property acquisitions. The October 1, 2009 report provided the initial analysis of the consolidated properties in the Trout Field and other Alberta properties acquired at Alexander and Crossfield. The December 31, 2009 report gave the analysis with the initial work programs implemented and plans for the balance of the winter work season. The July 31, 2010 year-end report provides the analysis after 10 months of operations and one work program. The December 31, 2010 – provided analysis with 15 months of operations including several work programs initiated. See analysis of our oil and gas information included as a supplement to this document as required by SEC release 33-8995

First Nation Joint Venture and status of CREEnergy Project

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

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

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

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

To develop and strengthen the relationship with CREEnergy, Kodiak formed a subsidiary company, Cougar Energy, Inc., to focus on this relationship. As a result, Cougar Energy, Inc became the operating entity for Kodiak in Western Canada. Cougar Energy Inc subsequently became Cougar Oil and Gas Canada, Inc.

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

Current Status

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

Northern Alberta – First Nations Joint Ventures:

•

Approximately 75,000 gross acres for access and development inside the land claim

•

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

–

Light crude and natural gas prospects

Project Status:

•

Negotiations underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.

•

In Parallel - Develop Joint Venture agreement to acquire, explore, develop and operate adjacent lands to the benefit of both Cougar and the Peerless Trout First Nation – Native Joint Ventures have priority with province over other industry and thus reduced competition for a Cougar/Peerless Trout First Nation JV.

Operating Plan – 2011/2012:

•

Explore and develop lands already identified by 2D and 3D seismic acquired - targeting Keg River light oil prospects

•

Acquire additional seismic and perform drilling programs

•

Execute similar maintenance programs on existing wells as Trout properties

•

Acquire additional lands adjacent to the land claim in a Joint Venture structure (anticipated model is 85/15 shared ownership).

Lucy, Northern British Columbia

Cougar Energy, Inc is the operator and 80% working interest owner of a 1,920-acre lease located in Northeastern British Columbia. The Company believes the lease is situated on the southeast edge of the Horn River Basin and the Muskwa Shale gas prospect. The Oil and Gas 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.

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

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

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

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

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

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

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

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

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

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

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

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

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

In January 2009, the Kodiak vended (sold for shares in the subsidiary CEI) its Lucy, British Columbia into Cougar Energy.

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

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

Oil and Gas Leases and Development Rights

As of December 31, 2010, we had approximately 58 leases covering approximately 15,500 gross acres in the Trout Area. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount typically ranges from 12% to 30% resulting in a 70% to 88% net revenue interest to us.

The acquisition of oil and gas leases is a very competitive process, whether they are freehold or acquired from the Province and or other oil and gas operators and involves certain geological and business risks to identify productive areas.

In the even that such identified lands are held by other operators, a transaction may be completed whereby the lands are purchased outright for the company for cash, or shares or a land exchange – or where a capital expenditure is required such as drilling or seismic where by value is added to the land holding – and thus earn a working interest in the property. In some instances the Company may earn up to 100% working interest and the assignor of such leases will reserve an overriding royalty interest, ranging from 1% to 15%, which further reduces the net revenue interest available to us.

As of December 31, 2010, approximately 65% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

In the Trout Area, Alberta as of December 31, 2010, the Company holds oil and gas leases on approximately 15,500 gross acres, of which approximately 5,500 gross acres (35%) are not currently held by production. The approximate 5,000 acres had an expiry date in the third quarter of 2015. In the event where these lands are drilled and validated, the continuation of this acreage would also be for an indefinite period.

In the Alexander Area, Alberta as of December 31, 2010, the Company oil and gas leases on approximately 160 gross acres, of which no gross acres are currently held by production. There are no expiry issues for this lease.

In Lucy, British Columbia as of December 31, 2010, we held oil and gas leases on approximately 1,920 gross acres, of which approximately 1,920 gross acres (100%) are not currently held by production. The Lucy mineral lease was extended as part of an approved Experimental Scheme application to the regulatory agency. The Lucy lease is currently extended indefinitely.

Property, Plant and Equipment

See the discussion above and in Item 5 with respect to the property, plant and equipment.

COMPETITIVE STRENGTHS OF THE COMPANY

Dominant Position in the Trout Area, Alberta

The Company has acquired a strategically valuable core area in the Trout properties. By acquiring the operations of wells, facilities, gathering system pipelines, sales pipelines and all weather roads, the Company can set the pace for the development rather than be dependent on other non-receptive operators. This infrastructure was originally capable of up to 2500, bbl/d and with minor capital upgrades should be able to achieve similar volumes as the well production is achieved through drilling programs.

Attractive Underlying Economics

During 2010 the Company had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. The Companies monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day with all of the production consisting of light sweet crude oil coming from mature fields with an average decline rate of 10% per year. An average operating cost Cdn 30/bbl. results in a netback of $40 to $50 after royalites at the current yearly range of $80 to $100/bbl commodity prices. These attractive economics are the result of acquiring an extensive production infrastructure including wells, pipelines, treating facilities, roads, and access to power. This infrastructure also contributes to low Find and Development costs (F&D) which then translates into a recycle ratio (net back/F&D) of approximately eight. With additional available development projects which will add production at $10,000 per flowing barrel - based on the previous 12 months operations - there is additional opportunities for low risk development.

Stable Base Production

The majority of the Company’s current producing properties are located in mature reservoirs with predictable lower annual decline rates. This allows the Company to more accurately predict cash flow and plan development and exploration opportunities.

Commodity Position

All the Company’s current proved and probable production in the Trout Area is light sweet crude oil, which receives the going price for crude without discounts.

Valuable Acreage Positions

Trout Area, Alberta

As described above, the Trout land position as the core area with the adjacent Peerless block – as a consolidated land position, average working interest of 85% with infrastructure, this project provides a foundation for growth and expansion.

Lucy, NE British Columbia

As described above, the 3 sections with 80% working interest, with shale gas opportunity to diversify commodities when justified.

Development and Exploration Opportunities

Core Trout Project, Alberta (Trout and Peerless)

The infrastructure will support substantially increased production levels (up to 2,500bbl/d) from the area with nominal increases in costs – providing opportunities to consolidate other properties into this Core Project, which the Company is actively working on.

The existing Trout and Peerless land base provides many opportunities for drilling programs to add reserves and production. The Company has acquired 2D and 3D seismic on much of these lands. In addition, the existing suspended wells provide many opportunities for work overs to add reserves and production at much lower costs than drilling or acquisition , which has been demonstrated with the current programs initiated.

The First Nation Joint Ventures provides additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure

Oil Marketing Contracts

The Company currently has an oil-marketing contract with an established Canadian marketing company. The contract is a monthly evergreen contract for oil purchased at the 40-degree price for light sweet crude oil at Edmonton, Alberta. The contract can be terminated with 30 days notice.

Hedging Contracts and Policies

We have no commodity hedging contracts in place at December 31, 2010.

Exploration and Production

Our operations are subject to various types of regulation at federal, state, provincial, territorial and local levels. These types of regulations may include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most provinces, states, territories and some municipalities in which we operate also regulate one or more of the following:

the location of wells;

the method of drilling and casing wells;

the surface use and restoration of properties upon which wells are drilled;

the plugging and abandoning of wells; and

notice to surface owners and other third parties.

Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

See additional discussion in Item 1A. Risk Factors.

Employees and Consultants

The Company had one employee during fiscal 2009. After the closing of the acquisition of the majority of the shares of Cougar Energy, The Company took over operations of Cougar Energy effective March 1, 2010, including the employees and consultants.

As of December 31, 2010, the Company has a total of eight executive, administrative and operational personnel – both direct employee and consultants, part time and full time, located at our headquarters in Calgary, Alberta, Canada. The Company has a total of three field contractors located in the Trout Area properties, north central Alberta, and one field contractor located in the Alexander property, central Alberta Canada. Professional consultants are utilized on an as needed basis. Our employees and consultants are covered by employment and consulting agreements. Management considers its relations with our employees to be satisfactory.

Where to Find Additional Information

Additional information about us can be found on our website at www.cougarenergyinc.com. Information on our website is not part of this document. The Company also provides free of charge on our website our filings with the SEC, including our annual reports, quarterly reports and current reports, along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC.

You may also find information related to our corporate governance, board committees and Company code of ethics on our website. Among the information you can find there is the following:

Code of Conduct – previously filed

Mandate of the Board of Directors - previously filed

	·	Audit Committee Charter - previously filed

	·	Nomination Committee Charter - previously filed

	·	Compensation Committee Charter – previously filed

Corporate Disclosure & Insider Trading Policy - previously filed

Whistleblower Policy - previously filed

Health, Safety and Environment Policy - previously filed

ITEM 4A. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

FORWARD LOOKING STATEMENTS

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

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

Certain statements contained in this report, including statements regarding the anticipated development and expansion of our business, our intent, belief or current expectations, our directors or officers, primarily with respect to the future operating performance of the Company and the products we expect to offer and other statements contained herein regarding matters that are not historical facts, but are “forward-looking” statements. Future filings with the SEC, future press releases and future oral or written statements made by us or with our approval, which are not statements of historical fact, may contain forward-looking statements, because such statements include risks and uncertainties, actual results may differ materially from those expressed or implied by such forward-looking statements.

All forward-looking statements speak only as of the date on which they are made. We undertake no obligation to update such statements to reflect events that occur or circumstances that exist after the date on which they were made.

Unless otherwise stated, all amounts shown in this “Operating and Financial Review” section of this report are in Canadian Dollars.

The following discussions and analysis should be read in conjunction with the ‘Selected Consolidated Financial Information’ included elsewhere herein and our historical consolidated financial statements and the accompanying notes.

Overview

History

Cougar Oil and Gas Canada Inc. (“Cougar”, “we”, “us”, “our”), formerly Ore-More Resources Inc., was incorporated under the laws of the Province of Alberta, Canada on June 20, 2007. Our principal activity is in the exploration, development, production and sale of oil and natural gas.

Our main operations are currently in the Alberta and British Columbia provinces of Canada. Our focus has developed into the specific projects of:

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

·	First Nations Projects, Alberta - mineral leases, exploration and development opportunities adjacent to the Trout Core Properties and other areas of the Province of Alberta, with several current and proposed Northern Alberta Treaty Land Entitlement Claims;

·	Lucy, British Columbia - Horn River Basin Muskwa shale gas project;
·	Manning Heavy Oil Project

·	Other Alberta properties.

The consolidated financial statements include the accounts of Cougar and Cougar Energy, Inc., a wholly-owned subsidiary, and are hereafter collectively referred to as “we”, “us”, “our” or, the “Company”. All significant intercompany balances and transactions have been eliminated in consolidation.

In January 2010, the Company entered into a stock purchase agreement (the “Agreement”) with Cougar Energy, Inc. (which we refer to as CEI) and CEI’s then shareholders whereby Cougar agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:

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

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

·	2,025,000 warrants to purchase common shares exercisable at $0.288 per common share and expiring on October 31, 2010.

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

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

b) On January 25, 2010, the Company finalized a share purchase agreement between the Company and Kodiak Energy Inc. (“Kodiak”) whereby the Company purchased from Kodiak a total of 8,461,549 shares of the common shares of CEI held by Kodiak. The share purchase agreement called for the Company to issue a total of 1.5 shares of common stock for each share of CEI tendered by Kodiak, resulting in the Company issuing a total of 12,692,324 (38,076,933 shares post split) shares of common stock. As further consideration for the acquisition of the CEI common shares, the Company forgave all current indebtedness owed to the Company by Kodiak and guaranteed by CEI, which was in the amount of $1,296,889 (CDN $1,357,714). An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Company were cancelled.

Upon consummation of the acquisition, CEI became the only wholly owned subsidiary of the Company. Subsequent to the completion of the reverse acquisition, the Company amended its article of incorporation and changed its name to Cougar Oil and Gas Canada, Inc.

Prior to the acquisition of CEI, the company had operating assets and activities within the oil and gas industry, and therefore the acquisition of CEI is not characterized as a shell transaction under SEC rules and regulations

GENERAL

Cougar Energy, Inc. is an oil and gas company that engaged in the development and exploration for natural resources. Since 2008 and until the fourth quarter of 2009, Cougar Energy, Inc. was active in Canada in acquiring properties that are prospective for petroleum and natural gas and related hydrocarbons. The prospects that Cougar Energy, Inc. holds are generally under leases and include partial and full working interests. In all of the core properties, Cougar Energy, Inc. is the operator and majority interest owner. The prospects are subject to varying royalties due to the state, province, territory, or federal governments and, in some instances, to other royalty owners in the prospect.

In January 2009, Kodiak sold for shares in the subsidiary its Lucy, British Columbia and CREEnergy Project, into Cougar Energy, Inc. for financing purposes. Cougar Energy, Inc., acquisition of producing properties was effective September 30, 2009 and October 1, 2009, and as a result Cougar Energy, Inc. became a development company with oil and gas reserves, production, and recognized revenue.

On February 4, 2010, Ore More Resources Inc. changed its name to Cougar Oil and Gas Canada Inc.

OIL AND GAS PRODUCTION

See SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING for detailed analysis of reserves, production, land, revenue and expenses as per SEC release 33-8995

PLANS FOR GROWTH

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

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

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

During the last couple of months Cougar has been working on several well reactivations in the Trout production field.

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

The 13-25 reactivation involved repairing a wellbore and pumpjack that had been shut in for over three years. The downhole work was successfully repaired with no problems but the pumpjack repair took longer due to time required to get the gear box repaired. A maintenance crew recently finished all of the repair work and the well is currently on production.

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

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

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

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

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

In December of 2010, the company initiated licensing of 2 wells for an infill drilling program for Q1 2011. The horizontal well was initiated in late February of 2011.

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

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

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

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

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

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

(a)

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

(b)

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

(c)

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

Continued Development of the Trout Area through Systematic Operational Controls

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

Consolidate the Trout Area

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

Develop Trout Area Assets

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

The First Nation Joint Ventures

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

Current Status

Northern Alberta – First Nations Joint Ventures:

•

Approximately 75,000 gross acres for access and development inside the land claim

•

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

–

Light crude and natural gas prospects

Project Status:

•

Negotiations underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.

•

Operating Plan – 2011/2012:

•

Explore and develop lands already identified by 2D and 3D seismic acquired - targeting Keg River light oil prospects

•

Acquire additional seismic and perform drilling programs

•

Execute similar maintenance programs on existing wells as Trout properties

•

Acquire additional lands adjacent to the land claim in a Joint Venture structure (anticipated model is 85/15 shared ownership).

Lucy, British Columbia

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

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

Manning Heavy Oil Project

See subsequent event notes

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

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

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

Cougar has also continued the preparation for the Manning area heavy oil farm-ins. The geological review has included core and log analysis and detailed geological mapping. Several drilling locations have been identified and the Corporation expects to begin the permitting process for these heavy oil prospects by the end of April.

Summary

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

Regulatory Matters

We are not aware that there are any Oil and Gas regulatory matters that may affect our business other than those disclosed herein.

Organizational Structure

Cougar Oil and Gas Canada, Inc. has a wholly owned (100%) subsidiary Cougar Energy, Inc. Cougar Energy, Inc. owns the assets and liabilities associated with the oil and gas operations. The intention is to merge Cougar Oil and Gas Canada, Inc. and Cougar Energy, Inc. when all the documentation can be prepared and completed for this merger as per Alberta Corporate requirements. This was completed January 1, 2011 - See additional information in section 5. See subsequent event notes.

BUSINESS STRATEGIES

Financial Flexibility

The Company has used and expects to use a variety of sources of funding to finance its acquisitions and capital development and exploration programs for 2010 - 2011.

Internally generated cash flow from operations – this will be key going forward and used as a priority when possible.

Debt financing – both revolving line of credit and specific debt instruments for specific projects – normally lower risk projects or acquisitions. Convertible debt instruments will be used as a priority over standard debt. Also vendor take backs – in certain circumstances when it benefits both the vendor and the purchaser – a type of debt structure may be set up with the vendor.

Equity issues when terms and conditions are appropriate – to pay down debt, or for higher risk exploration projects or larger acquisitions.

This ability to adjust projects and timelines, due to large land bases and multiple projects and work within different financing models, has allowed the Company to survive the recent recession and actually show growth in difficult times.

FINANCIAL INFORMATION

Financial Condition and Changes in Financial Condition:

The Company’s total assets have increased to $10,267,188 as at December 31, 2010 from $9,234,042 at December 31, 2009. This increase resulted from the earlier acquisition of Cougar Energy, Inc. and the subsequent capital expenditure programs undertaken by Cougar Energy, Inc. Total assets also include cash and other current assets of $579,240 (December 31, 2009 - $405,980).

The Company has evaluated and unevaluated properties net of accumulated depreciation, depletion and amortization of $9,682,585 (December 31, 2009 - $8,828,062). Unevaluated or undeveloped properties increased to $3,936,797 as at December 31, 2010 from $3,920,062 at December 31, 2009. The increase results from the purchase of undeveloped property less amounts transferred to developed property.

The Corporation reports its reserves in the United States based on a “constant pricing and cost assumptions” model to meet US GAAP requirements and the values shown in that portion of the GLJ report and the resultant differences are due to those base assumptions.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of July 31, 2010 in conjunction with our year-end reserve report as filed in the US, as a change in accounting principles that is inseparable from a change in accounting estimates. Under the SEC’s final rule, prior period reserves were not restated. We have adopted the guidance also in subsequent reports including the December 31, 2010 report.

For the United States, the primary impacts of the SEC’s final rule on our reserve estimates and future net revenues include the use of the unweighted 12-month average first-day-of-the-month reference price of $73.93 USD per barrel for oil compared to an actual price of $79.81 USD being received on December 31, 2010.

Our total current liabilities at December 31, 2010 were $5,206,803 (December 31, 2009 - $2,964,219) and consisted of accounts payable and accrued liabilities relating to capital activities and general and administrative costs incurred. Also included in current liabilities were notes payable of $15,623 (December 31, 2009 – $75,000), an operating bank credit line of $2,025,000 (December 31, 2009 -$ nil), related party obligations of $458,008 (December 31, 2009- $1,104,252) and current maturities of long term debt of $818,906 (December 31, 2009 – $566,311).

At December 31, 2010, we had long term debt of $2,707,186 (December 31, 2009 - $3,526,092) resulting from the property acquisition made in the third quarter of 2009. See Cougar Core Trout properties in Item 4. Asset retirement obligations of $1,332,747 (December 31, 2009 - $1,221,793) were recorded at December 31, 2010. This increase resulted from the transfer of certain assets from unevaluated to evaluated.

Total stockholders’ equity as at December 31, 2010 amounted to $1,020,452 (December 31, 2009 - $1,521,938), net of a deficit of $4,810,977 (December 31, 2009 - $2,825,399) and comprehensive gain of $2,228 (December 31, 2009 – loss of $37).

Overall Operating Results (All dollar values are expressed in Canadian dollars unless otherwise stated)

In the 5 months ended December 31, 2010, the Company had revenue of $1,178,303 (December 31, 2009 - $629,993) and operating loss of $968,200 (December 31, 2009 - $2,716,290) primarily relating to its producing operations from its Trout, Alberta project. The Company has now moved from an exploratory stage to an early development stage company.

Net Loss for the 5 months ended December 31, 2010 totaled $1,127,354 (December 31, 2009 - $2,315,670). These losses include general and administrative expenses of $1,039,009 (December 31, 2009 - $623,563), which includes stock-based compensation expense amounting to $301,311 (December 31, 2009 - $58,931), interest expense of $160,326 (December 31, 2009 – $115,449), depletion depreciation and accretion including ceiling test impairment write-downs of $418,212 (December 31, 2009 - $2,300,133) and gains on settlement of an operating agreement and asset retirement aggregating $933 (December 31, 2009 - $516,000).

General and administrative expenses include the cost of 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 and other personnel as noted above. 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 15 to approximately 420 shareholders during the past year has also contributed to our increased general and administrative costs.

Depletion, depreciation and accretion including ceiling test impairment write-downs includes the cost of depletion and depreciation relating to production from producing properties in the 5 months ended December 31, 2010, ceiling test impairment write-downs and the cost of depreciation relating to office furniture and equipment. The remaining capitalized costs relating to Canadian unproven properties have been excluded from the depletable cost pools for ceiling test purposes.

Financial Condition and Changes in Financial Condition for the year ended July 31, 2010 as compared to from November 21, 2008 (date of inception) through July 31, 2009:

The Company’s total assets have increased to $9,957,120 as at July 31, 2010 from $4,080,435 as at July 31, 2009. This increase resulted from the acquisition of Cougar Energy, Inc. and the subsequent capital expenditure programs undertaken by Cougar Energy, Inc. Total assets also include cash and other current assets of $517,406 (July 31, 2009 - $15,705).

For the first time, the Company has evaluated and unevaluated properties. Evaluated or proved properties net of accumulated depreciation, depletion and amortization was $5,500,000 (July 31, 2009 - $ nil). The $5,500,000 addition of proved properties is net of a year-end ceiling test write down of $2,132,179. Unevaluated or undeveloped properties decreased to $3,934,051 as at July 31, 2010 from $4,064,730 on July 31, 2009. The decrease results from a transfer of certain assets from unevaluated to evaluated.

For the United States, the primary impacts of the SEC’s final rule on our reserve estimates and future net revenues include the use of the unweighted 12-month average first-day-of-the-month reference price of $69.87 USD per barrel for oil compared to an actual average price of $74.87 USD per barrel received for the 10 months of reported operations. - thus, a price point was used for estimating reserves and future revenues which was 93% of actual.

Our total current liabilities were $4,822,937 (July 31, 2009 - $1,118,057) and consisted of accounts payable and accrued liabilities relating to capital activities and general and administrative costs incurred. Also included in current liabilities were notes payable of $65,833 (July 31, 2009 – $ nil), an operating bank credit line of $1,425,000 (July 31, 2009 -$ nil), related party obligations of $674,519 (July 31, 2009- $180,668) and current portion of long term debt of $672,124 (July 31, 2009 – $ nil).

We had long term liabilities of $3,051,978 (July 31, 2009 - $ nil) resulting from the property acquisition made in the third quarter of 2009. See Cougar Core Trout properties in Item 4. Asset retirement obligations of $1,311,206 (July 31, 2009 - $107,667) were recorded at year end. This increase resulted from the October, 2009 acquisitions and the transfer of certain assets from unevaluated to evaluated.

Shareholders’ equity as at July 31, 2010 amounted to $770,999 (July 31, 2009 - $2,854,711), net of a deficit of $3,683,623 (2009 - $509,729) and comprehensive loss of $280 (July 31, 2009 - $34).

Overall Operating Results (All dollar values are expressed in Canadian dollars unless otherwise stated)

In the year ended July 31, 2010, the Company had revenue of $2,657,720 (July 31, 2009 - $ nil) and operating costs of $1,327,376 (July 31, 2009 - $ nil) relating to its first ten months of producing operations from its Trout, Alberta project. The Company has now moved from an exploratory stage to a early development stage company.

Net Loss for the year ended July 31, 2010 totalled $3,173,894 (July 31, 2009 - $509,729). These losses include general and administrative expenses of $1,618,635 (July 31, 2009 - $505,216), which includes stock-based compensation expense amounting to $251,584 (July 31, 2009 - $69,279), interest expense of $314,358 (July 31, 2009 - nil), depletion depreciation and accretion including ceiling test impairment write-downs of $3,164,664 (July 31, 2009 - $4,513) and gains on settlement of an operating agreement and debt aggregating $593,419 (July 31, 2009 - $ nil).

Reserves, Production, and Related Revenue and Expenses Information

In 2010, Cougar Canada began economic production on its evaluated proven assets. The tables in the supplementary information at the end of this Form 20-F provide information for this production, revenue, royalties, expenses, G&A related to the operations and netbacks.

Property and Equipment

Property and equipment is recorded at cost. Depreciation of assets is provided by use of a straighe line basis 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.

Liquidity and Capital Resources

Since inception to January 25, 2010, the Company’s operations have been financed from the sale of securities and loans from shareholders. Since that date, the Company’s operations have been financed from cash flow, the sale of securities and credit lines established at banks. The working capital deficiency increased from $2,558,239 as at December 31, 2009 to 4,627,563 at December 31, 2010. Of this amount, $15,623 (December 31, 2009 – $75,000) is a short-term note payable, $2,025,000 represents our drawn operating credit line as at December 31, 2010 (December 31, 2009 - $ nil) and $818,906 (December 31, 2009 – $566,311) is the current maturities of long-term debt. At December 31, 2010, the Company was not in breach or default of any material covenants or terms of any credit or lending agreements.

During 5 months ended December 31, 2010, the Company raised $590,220 in proceeds from the exercise of outstanding warrants and issued shares to repay debt in the amount of $482,768. The Company increased its operating credit line to $2.5 million with a Canadian chartered bank, which was established subsequent to December 31, 2009. These financings have and will enable the Company to finance ongoing capital expenditures and general and administrative expenses.

The Company has had negative net cash flow from operations for the 5 months ended December 31, 2010 of $566,920 and December 31, 2009 - $568,654. The Company is in the process of seeking additional financing that will provide financing to carry out its business plan through 2011 and has commitments for a $5 million convertible debenture of which $1 million has been received and $1.5 million due in 30 days. (see subsequent events note). Such additional financing will be required for the Company’s 2011 exploration activities. In the event that additional equity capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Company, or the Company’s interest in its subsidiary. No assurances can be given that the Company will raise additional capital, or if offered, will be on acceptable terms.

Our independent registered public accountants have stated in their report dateed March 30, 2011 that we have incurred operating losses since inception, and that we are dependent upon management's ability to develop profitable operations and/or obtain necessary funding from outside sources, including by the sale of our securities, or obtaining loans from financial institutions, where possible. These factor, among others, may raise substaintial doubt about our ability to continue as a going concern. The report may cause difficulty in raising future financings.

ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.	Directors and Senior Management

The current Executive Officers and Directors of the Company as of the filing date of this Annual Report and their ages are as follows:

Name	Age	Position	Date Elected/ Appointed
William S. Tighe	60	Chairman of the Board, CEO	January 25, 2010
Paul Galachiuk	51	Director	September 10, 2010
Lee Lischka	34	Director	August 25, 2009
Glenn Watt	37	Director, COO and President	June 1, 2010 /August 17,2010
Bruce Dowell	55	Director	August 25, 2009
William Brimacombe	68	Director	June 1, 2010
Michael Hamilton	63	Director	October 29, 2010
Richard Carmichael	55	CFO and VP Finance	March 4, 2011
Steven Peter	54	VP Exploration	June 1, 2010

The following are brief biographies of our directors and officers:

William S. Tighe, Chairman of the Board

Mr. William Tighe has held the position of Chief Operating Officer, and Director of the Company since January 2010 and Chief Executive Officer Kodiak Energy, Inc. since December 2007. Mr. Tighe has focused on developing the Company's business interests. His past experience includes approximately thirty years in management, operations, maintenance, and more recently major and minor projects for both Canadian and other international energy companies. These positions were in a variety of field settings from the heavy oil industry, sour gas and liquids plants in Alberta and British Columbia and the sub-arctic in Canada, to design offices, construction, construction and startup, and operation of large gas/liquids processing operations in Southeast Asia. From 2004 to 2005, Mr. Tighe worked for Suncor Energy Ltd. as a Business Services Manager, Growth Planning and Development. From 2000 until 2004, he worked for Petro China International as Operations Development and Commissioning Manager. Prior to that, Mr. Tighe had extensive experience in both Alberta and internationally in the oil and gas industry. He attended the University of Calgary where he studied general science and computer science. Mr. Tighe is a director of Tamm Oil and Gas Corp., a junior heavy oil exploration and development company based in Calgary, Alberta, Canada. He holds an Interprovincial Power Engineering Certification II Class. The Company believes that the extensive Canadian and international oil and gas experience, coupled with the 5 years as President and COO of the Company as a fully reporting SOX compliant issuer, makes Mr. Tighe an asset to the Board of Directors of Cougar Oil and Gas Canada Inc. Mr. Tighe is also the Chairman and CEO of Kodiak Energy, Inc and the Chairman of TAMM Oil and Gas Corp.

Paul Galachiuk, Director

Mr. Galachiuk is currently President of Bow Engineering Ltd in Calgary, Alberta, Canada and has been involved in the oil refining and oil sands industry for over 28 years. He served in various roles with Suncor Energy since 1982. Most recently, he was Vice President, Growth Planning and Development of Suncor Energy, Inc, from 2004 to 2009. This role provided direction for the key growth initiatives and sustaining projects with respect to the Suncor Energy Oil Sands facility in Fort McMurray, Alberta. Areas of responsibility included technical scope and process development, strategy charting, planning and major project economics. He serves on two other boards including the Climate Change and Emissions Management Corporation and the Alberta Innovates - Energy and Environment Solutions. He is a registered Professional Engineer in the Province of Alberta with APEGGA. The Company believes that the senior corporate experience in both operations and project development makes Mr. Galachiuk an asset to the Board of Directors of Cougar Oil and Gas Canada Inc.

Michael J Hamilton, Director

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

Lee Lischka, Director

On August 25, 2009, Mr. Lee Lischka was appointed as a Director and as President and Secretary-Treasurer of the Company. Mr. Lischka is presently the Sales Manager and Managing Partner of XL Fluid Systems. In 2000, Mr. Lischka graduated from the Southern Alberta Institute of Technology in Calgary, Alberta in Petroleum Engineering Technology. From 2000 to 2008, Mr. Lischka was employed with Newpark Drilling Fluids as a Drilling Fluids Technician, Programmer and Technical Sales. Prior to entering his academic education, Mr. Lischka was employed in the oil and gas service industry in the hauling business and pipeline business. Mr. Lischka resigned as president on August 17, 2010. The Company believes that the industry related experience, contacts and relationships are a valuable asset to the development plans.

Glenn Watt, Director

Mr. Glenn Watt has been a director of The Company since June 2010 and Chief Operating Officer and President since August of 2010. Prior to joining the Company, he worked primarily in the Western Canadian Sedimentary Basin and, from May 2003 to March 2007, was drilling and completions superintendent for a large Canadian oil and gas royalty trust. Prior to that, Mr. Watt worked for a major oil and gas company as a completions superintendent. He has additional field experience working on drilling rigs in Alberta and British Columbia. Mr. Watt has an honors diploma in Petroleum Engineering Technology from the Northern Alberta Institute of Technology and a Bachelor of Applied Petroleum Engineering Technology Degree from the Southern Alberta Institute of Technology. We believe that Mr. Watt’s formal education and extensive work experience in drilling and project management in the Western Canada Sedimentary Basin makes him a valuable and key member of management and Board of Directors of Cougar Oil and Gas, Inc. Mr. Watt is a director of Kodiak Energy, Inc.

Bruce Dowell, Director

Mr. Dowell became a Director of Ore-More Resources on August 25, 2009. Mr. Dowell is currently employed with TAQA North (formerly Amoco Canada) as a power field engineer, working in the Crossfield Gas Plant since 1978. Previously, he worked as a mechanic at the Milt Ford Motors from 1975 to 1978. Throughout Mr. Dowell’s career, he has accumulated extensive experience and knowledge of the natural gas plant industry. This experience will be valuable as the Company implements development work.

William Brimacombe, Director

Mr. William E. Brimacombe is a Canadian Chartered Accountant and, since January 2007, had been Chief Financial Officer of The Company until his retirement in December 2009 when he joined our Board of Directors. From 2000 to 2006, he was Vice-President Finance of AltaCanada Energy Corp., a publicly traded Canadian oil and gas company. Prior thereto, Mr. Brimacombe has over thirty years financial experience working for a number of public and private oil and gas companies with operations in Canada, the United States and other countries, including experience as an independent financial consultant during the years 1988 to 2000. In 2009, he became a Life member of the Institute of Chartered Accountants of Alberta with forty years membership in that organization. We believe that Mr. Brimacombe’ s qualifications, including knowledge of both Canadian GAAP and US GAAP, oil and gas accounting and financial principles and prior successful public company roles including CFO of those companies, successful SOX compliance for Kodiak during his tenure as CFO, adds additional financial oversight for the Board of Directors. Mr. Brimacombe is a director of Kodiak Energy, Inc. The Company believes that the extensive audit, accounting, reporting experience of Mr Brimacombe coupled with the background with Kodiak Energy, Inc is an invaluable asset to the continued growth of Cougar.

Richard Carmichael

Richard is a Chartered Accountant who has held senior financial positions within the oil and gas exploration and production, and oil and gas service industries over the past 20 years. He is an experienced financial manager with publicly traded companies using Canadian GAAP and U.S. GAAP and has had responsibilities covering corporate accounting and financial reporting, treasury and financial analysis, budgeting and planning, and acquisitions and corporate financing. Most recently, Richard was the CFO of Steen River Oil & Gas Ltd. (formerly Jed Oil Inc.) from 2007 to 2010. Richard is also CFO of Kodiak Energy, Inc

Steven Peter - VP Exploration

Steven has held the position of Vice President, Exploration of the Company since January 2010. He is a professional geologist with over 25 years of diversified experience in the Canadian oil and gas industry. For the last 10 years, Steven has worked for small to medium-sized companies including Koch Exploration Canada Corporation, Compton Petroleum Corporation, Infiniti Resources International and G2 Resources Inc. He has a broad range of geological expertise in the Western Canadian Sedimentary Basin. Steven's proven ability to find oil and gas is an asset to the Cougar team. He graduated from McMaster University in 1982 with a Bachelor of Science Degree in Geology. Steven is a member of the Association of Professional Engineers, Geologists, and Geophysicists of Alberta (APEGGA) and the Canadian Society of Petroleum Geologists.

B.	Compensation of Directors

To date, the Company has not compensated directors; however, it provided equity awards to several of its directors. During the 7 months ended July 31, 2010, the Company issued an aggregate of 600,000 options to Directors to purchase the Company’s common stock at $2.38 per share for 5 years: vesting in 3 years and with an aggregate value of $1,075,800. During 5 months ended December 31, 2010, the Company issued an aggregate of 100,000 options to Directors to purchase the Company’s common stock at prices averaging $1.46 per share for five years; vesting in three years. The fair value of those issued options was $115,150.

Because the Company has expanded the board of directors to include persons who are also not executives of the Company or otherwise compensated by the Company, it is expected that the Company will start to provide compensation to its independent directors and certain of its other directors for their duties as directors and members of various committees. The compensation may include cash and stock awards, as determined by the board of directors and compensation committee.

C.	Board Practices

The directors are elected to serve until the next annual meeting of stockholders and until their successors have been elected. Executive officers serve at the discretion of the Board of Directors.

There are no current employment contracts with any directors. William Tighe, Glenn Watt and Dave Wilson and Steven Peter have employment contracts as officers of the Company. William Brimacombe has a consulting contract for services on an ad hoc basis.

D.	Management Team and Employees

Management Compensation

From the date of last filing until January 25, 2010, when we acquired the operations and assets of Cougar Energy, Inc., our operations were carried out by our President and a Director, Lee Lischka and Bruce Dowell, on a part-time basis. There were no full-time employees. There was no salary or other compensation paid, earned, or accrued to any of the officers and directors. Outside accounting and consulting persons were engaged for all accounting and required regulatory filings, and these persons were compensated on an hourly basis.

On January 25, 2010, when we acquired the majority of the shares of Cougar Energy, Inc. the Company acquired its operations, including employees and contractors. The acquisition was completed on March 1, 2010, and we have included these persons employment expenses since that date.

Our current management team consists of William Tighe as CEO, Glenn Watt as COO and President and Mr. Richard Carmichael as VP Finance and CFO. William Brimacombe provides third level review of financial information and project specific consulting.

We have internal accounting personnel and we contract out the production accounting to a third party. We have internal geological personal and contract out, as required, geophysical, petrophysical and other third party geological services. We also have internal minerals and surface lease consultants. We have part-time administrative personnel.

William Tighe, Glenn Watt, Richard Carmichael and Steven Peter have employment contracts as officers of the Company. These persons are referred to as the Named Executive Officers. William Brimacombe has a consulting contract for services on an as needed basis.

Compensation Principles

For the year ended July 31, 2009, no compensation was paid to any of the directors and officers of the Company.

From January through October 2010 executive and director compensation was determined by the board of directors, based in part on the input from the President and the Chief Executive Officer of the Company in respect of all executive officers other than the CEO. Since October 29, 2010, upon the appointment of a Compensation Committee of the board of directors and the adoption of the related committee charter all aspects of compensation of the directors and senior executives, and generally employees, will be determined by the committee, and it is expected that they will be based on the following principles.

A compensation generally is based on the philosophy that it should be competitive with other corporations of similar size and should be reflective of the experience, performance and contribution of the individuals involved and the overall performance of the Company.

Compensation generally consists of a combination of base salary, bonuses and participation in the stock option plan. These elements contain both short-term incentives, comprised of cash payments, being those provided by way of base salaries and bonuses, and long-term incentives, comprised of equity-based incentives, under the stock option plan. Dental and health insurance benefits are provided to employees. The process for determining perquisites and approval of benefits are based on comparisons to those usually offered by other corporations of a similar size and industry to the Company. The Company attempts to choose each element of its executive compensation program in order to maintain its competitive position in the marketplace.

Stock Option Plan and Other Equity Plans

As more fully described in Note 9 to the financial statements, the Company granted equity-based compensation over the years to employees of the Company under its equity plans. In the five months ended December 31, 2010, the Company granted non-qualified stock options to purchase 625,000 shares of common stock of the Company with an exercise price from $2.02 to $2.38 expiring five years from issuance.

Cougar Energy, Inc. Stock Option Plan – exercisable for Cougar Energy, Inc shares.

As more fully described in Note 9, Cougar Energy, Inc. the subsidiary, granted equity based compensation over the years to employees of Cougar Energy, Inc. As of December 31, 2010 there were 990,000 (net of cancellations of 55,000) shares of Cougar Energy, Inc. outstanding.

Cougar Energy, Inc. (a wholly owned subsidiary of the Company) has a stock option plan under which it granted 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. No further options have been granted since the acquisition of Cougar Energy, Inc.

Under Alberta Corporate Law, the Company has taken steps to amalgamate Cougar Oil and Gas Canada, Inc, and Cougar Energy, Inc. under statutory amalgamation proceedings. Once that process is completed, the employment contracts, including option plans of Cougar Energy, Inc will be assumed by Cougar Oil and Gas Canada, Inc. After giving effect to the Cougar Oil and Gas Canada/Cougar Energy Inc. share exchange at 1:1.5 and the subsequent 3:1 split of Cougar Canada Oil and Gas Canada Inc. shares, the 990,000 outstanding Cougar Energy, Inc. stock options made up of 725,000 exercisable at $0.65 per share and 265,000 stock options exercisable $1.30 per share, will become 3,262,500 and 1,192,500 outstanding Cougar Oil and Gas Canada stock options exercisable at $.144 per share and $.289 per share, respectively. No options have been exercised to date. See subsequent event note.

Cougar Oil and Gas Canada Inc. Stock Option Plan

The Company has a stock option plan, under which it issues equity awards and into which was amalgamated the prior outstanding options of Cougar Energy, Inc. as of January 1, 2011. Therefore, currently, the under the Cougar Oil and Gas (Canada) Inc. stock option plan there are stock options outstanding to acquire an aggregate of 5,715,000 shares, which represents approximately 9% of the currently outstanding shares of the Company. Of the 5,715,000 shares, 1,395,018 are currently vested and under exercisable options. The exercise prices of these options range from $.144 per share to $2.38 per share and the expiration dates range from three to five years.

The stock option plan of the Company that currently governs all the outstanding options was adopted on January 25, 2010, and amalgamated with the stock option plan of Cougar Energy, Inc. as of January 1, 2011. The stock option plan provides for awards to be issued to officers, directors, employees and consultants of the Company for the purpose of providing incentive compensation as part of any other compensation awarded to these persons. The stock option plan is characterized as an evergreen plan, meaning that the number of shares will increase if the issued and outstanding shares of common stock increase. The maximum number of shares that may be subject to the plan has been established at 10% of the outstanding common stock; therefore, the current maximum number of shares that may be subject to stock option awards is 6,187,916 . The board of directors, or the compensation committee if one is constituted, sets the number of shares subject to each individual option and the exercise price at the time of grant, and any other terms of the option. The exercise price is usually based on the five-day closing price on a weighted average basis. The options granted under the stock option plan are exercisable on a three year vesting schedule, at the rate of 33.33% (1/3) of the grant amount on each of the first, second and third anniversary dates of the date of grant, unless otherwise determined by the board of directors or compensation committee. Stock options granted under the stock option plan will be for a term of no longer than 5 years from the date of grant.

Summary Compensation Table of Named Executive Officers of Cougar Oil and Gas Canada, Inc.

The following table sets forth, for the Named Executive Officers, for the 5 months ended December 31, 2010, a summary of total compensation:

Name and

principal position

Year

Salary

($)

Share-based

awards

Option-based awards

($)

Non-equity incentive

plan compensation

($)

Pension

value

($)

All other

compensation

($)

Total

compensation

($)

Annual incentive plans

Long-term incentive plans

William Tighe

CEO and Director

2010

25,000

Nil

25,000

Glenn Watt

COO and Director

2010

50,000

Nil

50,000

Dave Wilson

CFO (1)

2010

8,473

Nil

8,473

Steven Peter

VP Exploration

2010

50,000

Nil

50,000

(1) Retired March 4, 2011

Outstanding Share-Based Awards and Option–Based Awards

The following table sets forth information in respect for all amounts of compensation provided to the directors and officers of Cougar Energy, Inc for the year ended July 31, 2009. Amounts provided directly from Cougar Oil and Gas Canada, Inc are not included – but are disclosed in tables above.

Name and

principal position

Year

Salary

($)

Share-based

awards

Option-based awards

($)

Non-equity incentive

plan compensation

($)

Pension

value

($)

All other

compensation

($)

Total

compensation

($)

Annual incentive plans

Long-term incentive plans

William Tighe

CEO and Director

2009

Nil

200,000

97,000

Nil

97,000

Glenn Watt

President

2009

Nil

200,000

97,000

Nil

97,000

Bill Brimacombe

Director and CFO retired

2009

Nil

100,000

48,500

Nil

48,500

Steven Peter

VP Exploration

2009

Nil

75,000

36,375

Nil

36,375

Les Owens

Director (2)

2009

Nil

100,000

48,500

Nil

48,500

Note: Kodiak Energy, Inc incurred all salary costs as part of its management prior to January 1, 2010.

(1)	Retired March 4, 2011

(2)	Retired in Amalgamation January 1, 2011

Pension Plan Benefits

The Company does not have a pension plan or any other plan that provides for payments or benefits at, following or in connection with retirement. The Company does not have a deferred compensation plan.

Termination and Change of Control Benefits

The Company employment contracts and option plans provides for vesting of the options granted with any external change in control of 30% of the Company as defined by SEC guidelines.

Director Compensation

Summary Compensation

The following table sets forth information in respect of all amounts of compensation provided to the directors of the Company for the last financial period ended December 31, 2010. Directors Glenn Watt and William Tighe disclosed in table above.

Name and

principal position

Year

Salary

($)

Share-based

awards

Option-based awards

($)

Non-equity incentive

plan compensation

($)

Pension

value

($)

All other

compensation

($)

Total

compensation

($)

Annual incentive plans

Long-term incentive plans

Lee Lischka Director

2010

Nil

300,000

537,900

Nil

537,900

Bruce Dowell Director

2010

Nil

300,000

537,900

Nil

537,900

Bill Brimacombe Director

2010

Nil

Paul Galichiuck

2010

Nil

50,000

52,450

Nil

52,450

Michael Hamilton

2010

Nil

50,000

62,700

Nil

62,700

E.	Share Ownership

Summarized below is the share and option ownership of our officers and directors as of March 15, 2011

Beneficial Owner	Shares		Percent of total issued (1) %	Options

All Executive Officers and Directors as a Group		924,707	1.44	4,337,500
William Tighe		81,207	*	900,000
William Brimacombe		54,000	*	450,000
Glenn Watt		385,000	*	900,000
Steven Peter		100,000	*	337,500
Richard Carmichael		100,000	*	450,000

(1) Based on 64,047,111 Common Shares issued and outstanding on December 31, 2010.

* Represents less than 1.0%.

In addition to the amounts indicated above for their holdings of shares of common stock of the Company, indirectly through holdings of shares in Kodiak, Glenn Watt, William Brimacombe and William Tighe hold approximately 18.26% of Kodiak who holds 59.74% of the Company or indirectly 11% of total issued shares of the Company.

ITEM 7. MAJOR STOCKHOLDERS AND RELATED PARTY TRANSACTIONS

A.	Major Stockholders

The following table sets forth certain information, as of December 31, 2010, concerning the ownership of our Common Shares by each person who, to the best of our knowledge, beneficially owned on that date more than 5% of our outstanding Common Shares.

Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities. In accordance with SEC rules, shares of Common Shares issuable upon the exercise of options or warrants which are currently exercisable or which become exercisable within 60 days following the date of the information in this table are deemed to be beneficially owned by, and outstanding with respect to, the holder of such option or warrant. Except as indicated by footnote, and subject to community property laws where applicable, to our knowledge, each person listed is believed to have sole voting and investment power with respect to all shares of Common Shares owned by such person.

Beneficial Owner		Shares				Percent of total issued (1)
Kodiak Energy, Inc. Suite 1120, 833 4th Avenue S.W. Calgary, AB T2P 3T5			38,262,812				59.74	%

(1) Based on 64,047,111 shares issued and outstanding on December 31, 2010.

Our major stockholder does not have voting rights that differ from the other holders of shares of our Common Shares.

We are not aware of any arrangements that would result in a change in control of our Company at a subsequent date.

B.	Related Party Transactions

From time to time, the Company’s majority shareholder, Kodiak Energy, Inc. has provided working capital and services to the Company. There are no formal repayment terms and the loan is interest free. As of December 31, 2010 and 2009, the balance due on the Kodiak loan was $458,008 and $1,104,252, respectively. See subsequent event note.

During the 5 month period ended December 31, 2010, the Company issued 185,840 common shares in payment of debt totaling $482,768 held by Kodiak Energy, Inc. the Company’s parent.

The Company paid $25,000 to a company owned and controlled by the chairman of the Company for management consulting services during the 5 month period ended December 31, 2010. Of this amount, $21,000 was payable on December 31, 2010. The Company paid the wife of the chairman of the Company $13,560 for administration consulting services. Of this amount, $5,292 was outstanding on December 31, 2010. These amounts were charged to General and Administrative Expense.

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

C. Interests of Experts and Counsel

Not applicable.

ITEM 8. FINANCIAL INFORMATION

A.	Financial Statements and Other Financial Information

Financial Statements

We have appended the consolidated financial statements filed as part of this Annual Report under Item 18 “Financial Statements.” The financial statements presented take into account the fact that the Company had minimum operations with no significant assets and liabilities prior to its acquisition of Cougar Energy, Inc. The historical consolidated financial statements, including the financial condition, results of operations and cash flows, are those of the accounting acquirer, Cougar Energy, Inc, from its date of inception on November 21, 2008.

Dividend Policy

We have never declared or paid any dividends, nor do we have any present plan to pay any cash dividends on our ordinary shares in the foreseeable future. We currently intend to retain most, if not all, of our available funds and any future earnings to operate and expand our business.

B.	Significant Changes

Other than as disclosed herein and the financial statements under Note 14, Subsequent Events, no significant change has occurred in our financial statements or financial condition since the fiscal year ended December 31, 2010.

ITEM 9. THE OFFER AND LISTING

A.	Offer and Listing Details.

Our common stock is traded on the OTC Bulletin Board under the symbol "COUGF". Our common stock commenced trading on October 14, 2008. We have no other classes of stock quoted on any markets. All trading is quoted in United States dollars.

For the month of December 2010, the high and low market price was $3.98 and $2.10 respectively, and on March 15, 2010, the high and low market prices were $3.09 and $2.70 and the close was $3.09. Below is a table of the historical prices of our common stock.

	High		Low		Close
Annual Periods
2008 (after Oct 14)	none		none			N/A
2009	none		none			N/A
2010		3.98		1.20		3.91
2011 (until March 15, 2011)		5.24		2.00		3.09

Monthly Periods 2010
January		2.33		2.00		2.33
February		2.33		2.00		2.01
March		2.11		2.00		2.05
April		2.34		2.01		2.16
May		2.55		2.05		2.35
June		2.49		1.80		1.97
July		1.95		1.20		1.55
August		1.65		1.40		1.55
September		1.55		1.25		1.40
October		1.78		1.25		1.67
November		2.10		1.45		2.10
December		3.98		2.10		3.91

Monthly Periods 2011
January	5.24	3.00	3.36
February	4.20	2.00	3.43
March (until March 15)	3.77	2.70	3.09

B.	Plan of Distribution

Not applicable

Markets

See above for the markets in which our common stock trades.

D.	Selling Shareholders

Not applicable

Dilution

Not applicable

F.	Expense of the Issue

Not applicable

ITEM 10. ADDITIONAL INFORMATION

A.	Share Capital

Not applicable

B.	Memorandum and Articles of Association

We were established pursuant to the issuance on June 20, 2007, of a Certificate of Incorporation by the Registrar of Corporations of the Province of Alberta pursuant to the provisions of the Alberta Business Corporations Act (the “ABCA”). Our Alberta Corporate Access Number is 2013313669. We have a primary place of business in the Province of Alberta. Our Articles of Incorporation (the “Articles”) do not limit the nature of the business that we may carry on.

A majority of the directors or of a committee of directors holding office at the time of the meeting constitutes a quorum provided that no business may be transacted unless at least half of the directors present are resident Canadians. Business cannot be transacted without a quorum. A quorum of directors may vote on any matter of business properly brought before the meeting provided that where a director is a party to a material contract or proposed material contract or is a director or an officer of or has a material interest in any person who is a party to a material contract or proposed material contract with us, such director must disclose his or her interest at the earliest possible date, request the conflict be noted in the minutes of the meeting, and with a few limited exceptions enumerated in the By-Laws, refrain from voting on the matter in which the director has a conflict of interest. There is no limitation on the Board of Directors to vote on matters of their remuneration as a director, officer, employee or agent of the company or an affiliate of the company.

The board of directors may, without authorization of our stockholders: (a) borrow money on credit; (b) issue, reissue, sell or pledge debt obligations; (c) subject to restrictions respecting financial assistance prescribed in the ABCA, give a guarantee on our behalf to secure performance of an obligation of any person; and (d) mortgage, hypothecate, pledge or otherwise create a security interest in all or any property, owned or subsequently acquired, to secure any obligation. The directors may, by resolution, delegate to a director, a committee of directors or an officer all or any of the foregoing borrowing powers.

A person is qualified to be or stand for election as a director provided such person is at least 18 years of age, is not a bankrupt and is not mentally incapacitated pursuant to applicable Alberta mental health legislation or pursuant to an order of the Alberta courts. There is no provision in our Articles or By-Laws relating to the retirement or non-retirement of directors under an age limit requirement. There is also no requirement in our Articles or By-Laws for a director to hold our shares.

We are authorized to issue an unlimited number of shares designated as Common Shares and an unlimited number of shares designated as Preferred Shares. The Common Shares have attached to them the following rights, privileges, restrictions and conditions: (a) except for meetings at which only holders of another specified class or series of our shares are entitled to vote separately as a class or series, each holder of a Common Share is entitled to receive notice of, to attend and to vote at all meetings of our stockholders; (b) subject to the rights, privileges, restrictions and conditions attached to any other class of our shares, the holders of our Common Shares are entitled to receive dividends if, as and when declared by our directors; and (c) subject to the rights, privileges, restrictions and conditions attached to any other class of our shares, the holders of our Common Shares are entitled to share equally in our remaining property upon liquidation, dissolution or winding-up of our Company.

The preferred shares may be issued in one or more series, each being comprised of the number of shares with the designation, rights, privileges, restrictions and conditions attached to that series of preferred shares, including the rate or amount of dividends or the method of calculating dividends, the dates of payment of dividends, the redemption, purchase and/or conversion prices and terms and conditions of redemption, purchase and/or conversion, and any sinking fund or other provisions, as our board of directors may fix from time to time. Preferred shares of each series shall, if issued, with respect to the payment of dividends and the distribution of assets or return of capital in the event of liquidation, dissolution or winding-up of our company, whether voluntary or involuntary, or any other return of capital or distribution of our assets among our stockholders for the purpose of winding up its affairs, rank on a parity with the preferred shares of every other series and be entitled to preference over the common stock and over any other shares ranking junior to the preferred shares. Preferred shares of any series may also be given other preferences, not inconsistent with the Articles, over the common stock and any other shares ranking junior to the preferred shares of a series as may be fixed by the board of directors. If any cumulative dividends or amounts payable on the return of capital in respect of a series of preferred shares are not paid in full, all series of preferred shares shall participate ratably in respect of accumulated dividends and return of capital. Unless the board of directors otherwise determine in the articles of amendment designating a series of preferred shares, the holder of each share of a series of preferred shares shall not, as such, be entitled to receive notice of or vote at any meeting of stockholders, except as otherwise specifically provided in the ABCA.

Under the ABCA, any substantive change to our Articles (including, but not limited to, change of any maximum number of shares that we are authorized to issue, creation of new classes of shares, add, change or remove any rights, privileges, restrictions and conditions in respect of all or any of its shares, whether issued or unissued, change the shares of any class or series, whether issued or unissued, into a different number of shares of the same class or series or into the same or a different number of shares of other classes or series) or other fundamental changes to our capital structure, including a proposed amalgamation or continuance out of the jurisdiction, requires shareholder approval by not less than 2/3 of the votes cast by stockholders voting in person or by proxy at a stockholders’ meeting called for that purpose. In certain prescribed circumstances, holders of shares of a class or of a series are entitled to vote separately as a class or series on a proposal to amend the Articles whether or not shares of a class or series otherwise carry the right to vote. The holders of a series of shares of a class are entitled to vote separately as a series only if the series is affected by an amendment in a manner different from other shares of the same class.

Our By-Laws provide that the board of directors shall call an annual meeting of stockholders to be held not later than eighteen months after the date of incorporation and subsequently, not later than fifteen months after holding the last preceding annual meeting. Our By-Laws provide that the board of directors, the managing director or the president may at any time call a special meeting of stockholders. Only the registered holders of shares are entitled to receive notice of and vote at annual and special meetings of stockholders, except to the extent that: (a) if a record date is fixed, the person transfers ownership of any of the person’s shares after the record date; or (b) if no record date is fixed, the person transfers ownership of any of the person’s shares after the date on which the list of stockholders is prepared; and (c) the transferee of those shares: (i) produces properly endorsed share certificates; or (ii) otherwise establishes ownership of the shares; and (iii) demands, not later than ten (10) days before the meeting, that the transferee’s name be included in the list before the meeting; in which case the transferee is entitled to vote the shares.

The ABCA also permits the holders of not less than 5% of the issued voting shares to give notice to the directors requiring them to call and hold a meeting. The only persons entitled to be present at a meeting of stockholders are: (a) stockholders entitled to vote at the meeting; (b) directors; (c) the auditor of the company; and (d) any others who, although not entitled to vote, are entitled or required under any provision of the ABCA, any unanimous stockholder agreement, the Articles or the By-laws to be present at the meeting. Any other person may be admitted only on the invitation of the Chairperson of the meeting or with the consent of the meeting.

There are no restrictions in our Articles or By-Laws on the number of shares that may be held by non-residents other than restrictions set out in the Investment Canada Act (Canada).

There are no specific provisions in our Articles or By-Laws that have the effect of delaying; deferring or preventing a change of control and that would operate only with respect to a merger, acquisition or corporate restructuring involving us (or any of our subsidiaries). Notwithstanding this, the board of directors, under the general powers conferred to it under our By-Laws, has the authority to approve and invoke a stockholders rights plan that will protect stockholders from unfair, abusive or coercive take-over strategies, including the acquisition or control by a bidder in a transaction or series of transactions that does not treat all stockholders equally or fairly or that does not afford all stockholders an equal opportunity to share in any premium paid upon an acquisition of control. We have not adopted such a plan. There are no provisions in our By-Laws regarding public disclosure of individual shareholdings.

The law applicable to us in the Province of Alberta in these areas is not significantly different from that in the United States.

Under the ABCA, we may indemnify any director, officer, employee, or corporate agent "who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, except an action by or in the right of the corporation" due to his corporate role. The ABCA extends this protection "against expenses, including attorneys' fees, judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with the action, suit or proceeding if he acted in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful."

Article 6 of our By-laws provides for indemnification of its officers and directors to the fullest extent permitted by law. Specifically, Section 6 of our By-laws provides for:

“6.01 Conflict of Interest: A director or officer shall not be disqualified by his office, or be required to vacate his office, by reason only that he is a party to, or is a director or officer or has a material interest in any person who is a party to, a material contract or proposed material contract with the Corporation or subsidiary thereof. Such a director or officer shall, however, disclose the nature and extent of his interest in the contract at the time and in the manner provided by the ABCA. Any such contract or proposed contract shall be referred to the Board or stockholders for approval even if such contract is one that in the ordinary course of the Corporation's business would not require approval by the Board or stockholders. Subject to the provisions of the ABCA, a director shall not by reason only of his office be accountable to the Corporation or to its stockholders for any profit or gain realized from such a contract or transaction, and such contract or transaction shall not be void or voidable by reason only of the director's interest therein, provided that the required declaration and disclosure of interest is properly made, the contract or transaction is approved by the directors or stockholders, and it is fair and reasonable to the Corporation at the time it was approved and, if required by the ABCA, the director refrains from voting as a director on the contract or transaction and absents himself from the director's meeting at which the contract is authorized or approved by the directors, except attendance for the purpose of being counted in the quorum.”

“6.02 Limitation of Liability: Every director and officer of the Corporation in exercising his powers and discharging his duties shall act honestly and in good faith with a view to the best interest of the Corporation and exercise the care, diligence and skill that a reasonable and prudent person would exercise in comparable circumstances. Subject to the foregoing, no director or officer for the time being of the Corporation shall be liable for the acts, receipts, neglects or defaults of any other director or officer or employee or for joining in any receipt or act of conformity, or for any loss, damage, or expense happening to the Corporation through the insufficiency or deficiency of title to any property acquired by the Corporation or for or on behalf of the Corporation or the insufficiency or deficiency of any security in or upon which any of the monies of or belonging to the Corporation shall be placed out or invested or for any loss, conversion, misapplication or misappropriation of or any damage resulting from any dealings with any monies, securities or other assets belonging to the Corporation or for any other loss, damage or misfortune whatever which may happen in the execution of the duties of his respective office or trust in relation thereto; provided that nothing herein shall relieve any director or officer from the duty to act in accordance with the ABCA and the regulations thereunder or from liability for any breach thereof. The directors for the time being of the Corporation shall not be under any duty or responsibility in respect of any contract, act or transaction whether or not made, done or entered into the name or on behalf of the Corporation, except such as shall have been submitted to and authorized or approved by the Board.”

“6.03 Indemnity: Subject to the ABCA, the Corporation shall indemnify a director or officer, a former director or officer, or a person who acts or acted at the Corporation's request as a director or officer of a body corporate of which the Corporation is or was a stockholder or creditor, and his heirs, executors, administrators and other legal representatives, from and against, (a) any liability and all costs, charges and expenses that he sustains or incurs in respect of any action, suit or proceeding that is proposed or commenced against him for or in respect of anything done or permitted by him in respect of the execution of the duties of his office; and (b) all other costs, charges and expenses that he sustains or incurs in respect of the affairs of the Corporation, except where such liability relates to his failure to act honestly and in good faith with a view to the best interests of the Corporation. The Corporation shall also indemnify such persons in such other circumstances as the ABCA permits or requires. Nothing in this Section shall limit the right of any person entitled to indemnity to claim indemnity apart from the provisions of this Section.”

“6.04 Insurance: Subject to the ABCA, the Corporation may purchase and maintain insurance for the benefit of any person referred to in the preceding section against any liability incurred by him in his capacity as a director or officer of the Corporation or of any body corporate where he acts or acted in that capacity at the Corporation's request.”

C.	Material Contracts

Purchase and Sale Agreement dated August 18, 2009

On August 18, 2009, the Company entered into a Purchase and Sale Agreement to acquire certain oil and gas properties from a Sword Energy. The gross purchase price of $6,000,000 is payable over a 54 month term with variable monthly payments. $1,300,000 was paid as down payment. The Purchase and Sale Agreement is interest free. The Company has the right to prepay the vendor loan in full, without penalty, semi-annually commencing March 31, 2010, at a proportionate discount to the original purchase price. The indebtedness is secured by a debenture covering a fixed and floating charge over Cougar's interest in the acquired properties.

Operating Line of Credit Agreement

During the year ended July 31, 2010, the Company reached formal agreement with a Canadian bank for two credit facilities. The first credit facility is a revolving demand loan in the amount of Cdn$1,485,000 bearing an interest rate of prime interest plus 3.5%. The second credit facility is a non-revolving acquisition/development demand loan bearing an annum interest rate of prime plus 3.0%. Under the terms of the Agreement, the two credit facilities are committed for the development of existing proved non-producing /undeveloped petroleum and natural gas reserves. As at July 31, 2010, $1,425,000 of the revolving line was drawn and no amount had been drawn on the second facility. On October 14, 2010, the revolving demand loan facility was increased to Cdn$2,500,000, and the non-revolving acquisition/development demand loan (second facility) was terminated. The current amount outstanding on the credit facility is $2,025,000 at December 31, 2010.

D.	Exchange Controls

As of the date hereof, there are no governmental laws, decrees or regulations in Canada on the export or import of capital, or which impose foreign exchange controls or affect the remittance of interest, dividends or other payments to non-resident holders of our common stock. However, dividends paid to U.S. residents, are subject to a 15% withholding tax or a 5% withholding tax for dividends if the stockholder is a corporation owning at least 10% of the outstanding voting shares of our company pursuant to Article X of the reciprocal tax treaty between Canada and the U.S. (see Item 10E "Taxation" below).

Except as provided in the Investment Canada Act, which has provisions that restrict the holding of voting shares by non-Canadians, there are no limitations specific to the rights of non-Canadians to hold or vote our common stock under the laws of Canada or Alberta, or in our charter documents. The following summarizes the principal features of the Investment Canada Act for non-Canadian residents proposing to acquire our common stock.

This summary is of a general nature only and is not intended to be, and should not be construed to be, legal advice to any holder or prospective holder of our common stock, and no opinion or representation to any holder or prospective holder of our common stock is hereby made. Accordingly, holders and prospective holders of our common stock should consult with their own legal advisors with respect to the consequences of purchasing and owning our common stock.

The Investment Canada Act governs the acquisition of Canadian businesses by non-Canadians. Under the Investment Canada Act, non-Canadian persons or entities acquiring "control" (as defined in the Investment Canada Act) of a corporation carrying on business in Canada are required to either notify, or file an application for review with, Industry Canada. Industry Canada may review any transaction which results in the direct or indirect acquisition of control of a Canadian business, where the gross value of corporate assets exceeds certain threshold levels (which are higher for investors from members of the World Trade Organization, including United States residents, or World Trade Organization member-controlled companies) or where the activity of the business is related to Canada’s cultural heritage or national identity. No change of voting control will be deemed to have occurred, for purposes of the Investment Canada Act, if less than one-third of the voting control of a Canadian corporation is acquired by an investor.

If an investment is reviewable under the Investment Canada Act, an application for review in the form prescribed is normally required to be filed with Industry Canada prior to the investment taking place, and the investment may not be implemented until the review has been completed and the Minister responsible for the Investment Canada Act is satisfied that the investment is likely to be of net benefit to Canada. If the Minister is not satisfied that the investment is likely to be of net benefit to Canada, the non-Canadian applicant must not implement the investment, or if the investment has been implemented, may be required to divest itself of control of the Canadian business that is the subject of the investment.

Certain transactions relating to our common stock would be exempt from the Investment Canada Act, including: (a) the acquisition of our common stock by a person in the ordinary course of that person’s business as a trader or dealer in securities; (b) the acquisition of control of our company in connection with the realization of security granted for a loan or other financial assistance and not for a purpose related to the provisions of the Investment Canada Act; and (c) the acquisition of control of our company by reason of an amalgamation, merger, consolidation or corporate reorganization following which the ultimate direct or indirect control in fact of our company, through ownership of our common stock, remains unchanged.

Taxation

Material Canadian Federal Income Tax Consequences

We consider that the following general summary fairly describes the principal Canadian federal income tax consequences applicable to a holder of our common stock who is a resident of the United States, who is not, will not be and will not be deemed to be a resident of Canada for purposes of the Income Tax Act (Canada) and any applicable tax treaty and who does not use or hold, and is not deemed to use or hold, his common stock in the capital of our company in connection with carrying on a business in Canada (a "non-resident holder").

This summary is based upon the current provisions of the Income Tax Act, the regulations under the act (the "Regulations"), the current publicly announced administrative and assessing policies of the Canada Revenue Agency and the Canada-United States Tax Convention (1980), as amended (the "Treaty"). This summary also takes into account the amendments to the Income Tax Act and the Regulations publicly announced by the Minister of Finance (Canada) prior to the date hereof (the "Tax Proposals") and assume that all such Tax Proposals will be enacted in their present form. However, no assurances can be given that the Tax Proposals will be enacted in the form proposed, or at all. This summary is not exhaustive of all possible Canadian federal income tax consequences applicable to a holder of our common stock and, except for the foregoing, this summary does not take into account or anticipate any changes in law, whether by legislative, administrative or judicial decision or action, nor does it take into account provincial, territorial or foreign income tax legislation or considerations, which may differ from the Canadian federal income tax consequences described herein.

This summary is of a general nature only and is not intended to be, and should not be construed to be, legal, business or tax advice to any particular holder or prospective holder of our common stock, and no opinion or representation with respect to the tax consequences to any holder or prospective holder of our common stock is made. Accordingly, holders and prospective holders of our common stock should consult their own tax advisors with respect to the income tax consequences of purchasing, owning and disposing of our common stock in their particular circumstances.

Dividends and Paying Agents

Dividends paid on our common stock to a non-resident holder will be subject under the Income Tax Act to withholding tax which tax is deducted at source by our company. The withholding tax rate for dividends prescribed by the Income Tax Act is 25% but this rate may be reduced under the provisions of an applicable tax treaty. Under the Treaty, the withholding tax rate is reduced to 15% on dividends paid by our company to residents of the United States and is further reduced to 5% where the beneficial owner of the dividends is a corporation resident in the United States that owns at least 10% of the voting stock of our company.

The Treaty provides that the Income Tax Act standard 25% withholding tax rate is reduced to 15% on dividends paid on stock of a corporation resident in Canada (such as our company) to residents of the United States, and also provides for a further reduction of this rate to 5% where the beneficial owner of the dividends is a corporation resident in the United States that owns at least 10% of the voting stock of the corporation paying the dividend.

Capital Gains

A non-resident holder is not subject to tax under the Income Tax Act in respect of a capital gain realized upon the disposition of a common share of our company unless such share is "taxable Canadian property" (as defined in the Income Tax Act) of the non-resident holder. Our common stock generally will not be taxable Canadian property of a non-resident holder unless the non-resident holder alone or together with non-arm’s length persons owned, or had an interest in an option in respect of, not less than 25% of the issued stock of any class of our capital stock at any time during the 60 month period immediately preceding the disposition of the stock. In the case of a non-resident holder resident in the United States for whom stock of our company is taxable Canadian property, no Canadian taxes will generally be payable on a capital gain realized on such stock by reason of the Treaty unless the value of such stock is derived principally from real property situated in Canada.

Material United States Federal Income Tax Consequences

The following is a general discussion of certain possible United States Federal foreign income tax matters under current law, generally applicable to a U.S. Holder (as defined below) of our common stock who holds such stock as capital assets. This discussion does not address all aspects of United States Federal income tax matters and does not address consequences peculiar to persons subject to special provisions of Federal income tax law, such as those described below as excluded from the definition of a U.S. Holder. In addition, this discussion does not cover any state, local or foreign tax consequences. See "Certain Canadian Federal Income Tax Consequences" above.

The following discussion is based upon the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations, published Internal Revenue Service ("IRS") rulings, published administrative positions of the IRS and court decisions that are currently applicable, any or all of which could be materially and adversely changed, possibly on a retroactive basis, at any time. In addition, this discussion does not consider the potential effects, both adverse and beneficial, of any recently proposed legislation, which, if enacted, could be applied, possibly on a retroactive basis, at any time. No assurance can be given that the IRS will agree with such statements and conclusions, or will not take, or a court will not adopt, a position contrary to any position taken herein.

The following discussion is for general information only and is not intended to be, nor should it be construed to be, legal, business or tax advice to any holder or prospective holder of our common stock, and no opinion or representation with respect to the United States Federal income tax consequences to any such holder or prospective holder is made. Accordingly, holders and prospective holders of common stock are urged to consult their own tax advisors with respect to Federal, state, local, and foreign tax consequences of purchasing, owning and disposing of our common stock.

U.S. Holders

As used herein, a "U.S. Holder" includes a holder of less than 10% of our common stock who is a citizen or resident of the United States, a corporation created or organized in or under the laws of the United States or of any political subdivision thereof, any entity which is taxable as a corporation for United States tax purposes and any other person or entity whose ownership of our common stock is effectively connected with the conduct of a trade or business in the United States. A U.S. Holder does not include persons subject to special provisions of Federal income tax law, such as tax-exempt organizations, qualified retirement plans, financial institutions, insurance companies, real estate investment trusts, regulated investment companies, broker-dealers, non-resident alien individuals or foreign corporations whose ownership of our common stock is not effectively connected with the conduct of a trade or business in the United States and stockholders who acquired their stock through the exercise of employee stock options or otherwise as compensation.

Distributions

The gross amount of a distribution paid to a U.S. Holder will generally be taxable as dividend income to the U.S. Holder for United States federal income tax purposes to the extent paid out of our current or accumulated earnings and profits, as determined under United States federal income tax principles. Distributions which are taxable dividends and which meet certain requirements will be "unqualified dividend income" and taxed to U.S. Holders at a maximum United States federal rate of 15%. Distributions in excess of our current and accumulated earnings and profits will be treated first as a tax-free return of capital to the extent the U.S. Holder’s tax basis in the common stock and, to the extent in excess of such tax basis, will be treated as a gain from a sale or exchange of such stock.

Capital Gains

In general, upon a sale, exchange or other disposition of common stock, a U.S. Holder will generally recognize a capital gain or loss for United States federal income tax purposes in an amount equal to the difference between the amount realized on the sale or other distribution and the U.S. Holder’s adjusted tax basis in such stock. Such gain or loss will be a United States source gain or loss and will be treated as a long-term capital gain or loss if the U.S. Holder’s holding period of the stock exceeds one year. If the U.S. Holder is an individual, any capital gain will generally be subject to United States federal income tax at preferential rates if specified minimum holding periods are met. The deductibility of capital losses is subject to significant limitations.

Foreign Tax Credit

A U.S. Holder who pays (or has had withheld from distributions) Canadian income tax with respect to the ownership of our common stock may be entitled, at the option of the U.S. Holder, to either a deduction or a tax credit for such foreign tax paid or withheld. Generally, it will be more advantageous to claim a credit because a credit reduces United States Federal income taxes on a dollar-for-dollar basis, while a deduction merely reduces the taxpayer’s income subject to tax. This election is made on a year-by-year basis and generally applies to all foreign income taxes paid by (or withheld from) the U.S. Holder during that year. There are significant and complex limitations which apply to the tax credit, among which is an ownership period requirement and the general limitation that the credit cannot exceed the proportionate share of the U.S. Holder’s United States income tax liability that the U.S. Holder’s foreign source income bears to his or its worldwide taxable income. In determining the application of this limitation, the various items of income and deduction must be classified into foreign and domestic sources. Complex rules govern this classification process. There are further limitations on the foreign tax credit for certain types of income such as "passive income", "high withholding tax interest", "financial services income", "shipping income", and certain other classifications of income. The availability of the foreign tax credit and the application of these complex limitations on the tax credit are fact specific and holders and prospective holders of our common stock should consult their own tax advisors regarding their individual circumstances.

Passive Foreign Investment Corporation

We do not believe that we are a passive foreign investment corporation (a "PFIC") because we have realized no income, domestic or foreign. However, since PFIC status depends upon the composition of a company’s income and assets and the market value of its assets and stock from time to time, there is no assurance that we will not be considered a PFIC for any taxable year. If we were treated as a PFIC for any taxable year during which a U.S. Holder held stock, certain adverse tax consequences could apply to the U.S. Holder.

If we are treated as a PFIC for any taxable year, gains recognized by such U.S. Holder on a sale or other disposition of stock would be allocated ratably over the U.S. Holder’s holding period for the stock. The amount allocated to the taxable year of the sale or other exchange and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations, as applicable, and an interest charge would be imposed on the amount allocated to such taxable year. Further, any distribution in respect of stock in excess of 125% of the average of the annual distributions on stock received by the U.S. Holder during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, would be subject to taxation as described above. Certain elections may be available to U.S. Holders that may mitigate some of the adverse consequences resulting from PFIC status. However, regardless of whether such elections are made, dividends paid by a PFIC will not be "qualified dividend income" and will generally be taxed at the higher rates applicable to other items of ordinary income.

We may establish an office for the Company in the U.S. and engage in a U.S. trade or business for U.S. tax purposes. Therefore, future foreign source income should not result in the Company being classified as a PFIC.

U.S. Holders and prospective holders should consult their own tax advisors regarding the potential application of the PFIC rules to their ownership of our common stock.

F.	Dividends and Paying Agents

Not applicable

G.	Statements by Experts

Not applicable

H.	Documents on Display

Documents and agreements concerning our Company may be viewed by appointment during regular business hours at the offices of the Company.

I.	Subsidiary Information

Cougar Energy, Inc – 100% owned by the Company, operating entity in Canada for the assets and liabilities.

ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable

PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

There have been no material modifications to the rights of security holders.

ITEM 15T. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, under supervision and with the participation of the Chief Executive Officer and the Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures, as defined under Exchange Act Rule 13a-15(e). Based upon this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2010, our disclosure controls and procedures were effective.

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Report On Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined under Exchange Act Rules 13a-15(f) and 14d-14(f). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations and may not prevent or detect misstatements. Therefore, even those systems determined to be effective can only provide reasonable assurance with respect to financial reporting reliability and financial statement preparation and presentation. In addition, projections of any evaluation of effectiveness to future periods are subject to risk that controls become inadequate because of changes in conditions and that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010. In making the assessment, management used the criteria issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on its assessment, management concluded that, as of December 31, 2010, the Company’s internal control over financial reporting was effective.

As defined by Auditing Standard No. 5, “An Audit of Internal Control Over Financial Reporting that is Integrated with an Audit of Financial Statements and Related Independence Rule and Conforming Amendments,” established by the Public Company Accounting Oversight Board (“PCAOB”), a material weakness is a deficiency or combination of deficiencies that results in more than a remote likelihood that a material misstatement of annual or interim financial statements will not be prevented or detected. In connection with the assessment described above, management concluded the Company does not have control deficiencies that represent material weaknesses as of December 31, 2010.

Changes in Internal Control over Financial Reporting

As of December 31, 2010, management assessed the effectiveness of our internal control over financial reporting and based on that evaluation, they concluded that during the period November 21, 2008 ( date of inception) through December 31, 2010 and to date, the internal controls and procedures were effective. During the course of their evaluation, we did not discover any fraud involving management or any other personnel who play a significant role in our disclosure controls and procedures or internal controls over financial reporting.

We believe that our financial statements contained in our Transition Report on Form 20-F for the five months ended December 31, 2010, fairly present our financial position, results of operations and cash flows for the years covered thereby in all material respects.

We are committed to improving our financial organization. We will continue to monitor and evaluate the effectiveness of our internal controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements as necessary.

This transition report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to the temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

There were no changes in our internal control over financial reporting during the five months ended fiscal December 31, 2010, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 16. [RESERVED]

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

As of the date of this report, the board of directors has an audit committee. The board of directors believes that Michael Hamilton, a member of the audit committee, meets the criteria for an audit committee financial expert, as that term is defined by Rule 4200(a)(15) of the NASDAQ Market Place Rules

Mr. Hamilton will not be deemed an “expert” for any purpose, including, without limitation, for purposes of Section 11 of the Securities Act of 1933, as amended, as a result of being designated or identified as an audit committee financial expert. The designation or identification of Mr. Hamilton as an audit committee financial expert does not impose on him any duties, obligations or liability that are greater than the duties, obligations and liability imposed on him as a member of our Audit Committee and board of directors in the absence of such designation or identification. The designation or identification of Mr. Hamilton as an audit committee financial expert does not affect the duties, obligations or liability of any other member of our Audit Committee or board of directors. Mr. Hamilton is independent director.

ITEM 16B. CODE OF ETHICS

On August 17, 2010, our board of directors adopted a code of ethics for our employees and directors, including our co-chief executive officers and our principal financial officer (i) to promote the honest and ethical conduct of our senior executive and financial officers, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships, (ii) to promote full, fair, accurate, timely and understandable disclosure in periodic reports required to be filed with or submitted to the SEC and in other public communications by us; (iii) to promote compliance with all applicable laws, rules and regulations that apply to us and our senior executive and financial officers; (iv) to deter wrongdoing; and (v) to promote prompt internal reporting of breaches of, and accountability for adherence to, this code. A copy of the code of ethics is filed as an exhibit to the July 31, 2010 Annual Report by incorporation and to this Report by reference.

ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent auditors for the 5 month period ended December 31, 2010 and fiscal year ended July 31, 2010 and the period November 21, 2008 (date of inception) through July 31, 2009 were RBSM, LLP, New York, NY.

Audit Fees

The fees billed by Child, Van Wagoner & Bradshaw PLLC for professional services rendered for the audit of our annual financial statements for the fiscal year ended July 31, 2009 was $6,000.

The fees billed by RBSM, LLP for professional services rendered for the audit of our annual financial statement for the fiscal year ended July 31, 2010 and the period November 21, 2008 (date of inception) through July 31, 2009 was $83,439.

The fees billed by RBSM, LLP for professional services rendered for the audit of our financial statements for the 5 month period ended December 31, 2010 was approximately $74,167 to date.

Audit Related Fees

The fees billed for assurance and related services by RBSM, LLP relating to the performance of the audit or review of our financial statements for the fiscal years ended July 31, 2010 and the period November 21, 2008 (date of inception) through July 31, 2009 respectively, which are not reported under the heading "Audit Fees" above, were Nil.

The fees billed for assurance and related services by RBSM, LLP relating to the performance of the audit or review of our financial statements for the 5 month period ended December 31, 2010, which are not reported under the heading "Audit Fees" above, were Nil.

Tax Fees

For the fiscal years ended July 31, 2010 and the period November 21, 2008 (date of inception) through July 31, 2009 respectively, the aggregate fees billed for tax compliance, tax advice and tax planning by RBSM, LLP were Nil.

For the 5 months ended December 31, 2010 the aggregate fees billed for tax compliance, tax advice and taxes planning by RBSM, LLP were Nil.

All Other Fees

For the fiscal years ended July 31, 2010 and the period November 21, 2008 (date of inception) through July 31, 2009 respectively, the aggregate fees billed by RBSM, LLP as applicable, for products and services, other than the services set out above, were Nil.

For the 5 months ended December 31, 2010 the aggregate fees billed by RBSM, LLP as applicable, for products and services, other than the services set out above, were Nil.

Audit Committee Pre-Approved Procedures

Our Audit Committee pre-approves all services provided by our principal accountant. All of the services and fees described under the heading "Audit Fees", "Audit Related Fees", "Tax Fees" and "All Other Fees" above were reviewed and approved by our board of directors before the respective services were rendered and none of such services were approved by our board of directors pursuant to paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

Not applicable.

ITEM 16E. PURCHASES OF EQUITY SECURITIES BY OUR COMPANY AND AFFILIATED PURCHASERS

Not applicable.

ITEM 16F. CHANGES IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

Not Applicable.

PART III

ITEM 17. FINANCIAL STATEMENTS

See Item 18 “Financial Statements” below.

ITEM 18. FINANCIAL STATEMENTS

Our audited financial statements for the five month periods ended December 31, 2010 and December 31, 2009, year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009 are provided herein starting on Page F-1.

COUGAR OIL AND GAS CANADA, INC

INDEX TO FINANCIAL STATEMENTS

		Page
Report of Independent Registered Public Accounting Firm		F-1

Consolidated Balance Sheets as of December 31, 2010 and 2009; and as of July 31, 2010 and 2009		F-2

Consolidated Statements of Operations for the five month periods ended December 31, 2010 and 2009; for the year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009		F-3

Consolidated Statement of Stockholders’ Equity from November 21, 2008 (date of inception) through December 31, 2010		F-4

Consolidated Statements of Cash Flows for the five month periods ended December 31, 2010 and 2009; for the year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009		F-5

Notes to Consolidated Financial Statements		F-6 - 21

Report of Independent Registered Public Accounting Firm

To the Board of Directors

Cougar Oil and Gas Canada, Inc.

Alberta, Canada

We have audited the accompanying consolidated balance sheets of Cougar Oil and Gas Canada, Inc. and subsidiaries (the “Company”) as of December 31, 2010, 2009 and July 31, 2010 and 2009 and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash flows for the five month periods ended December 31, 2010 and 2009 and year ended July 31, 2010 and November 21, 2008 (date of inception) through July 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based upon our audits.

We have conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Cougar Oil and Gas Canada, Inc. at December 31, 2010, 2009 and July 31, 2010 and 2009 and the results of its operations and its cash flows for the five month periods ended December 31, 2010 and 2009 and year ended July 31, 2010 and November 21, 2008 (date of inception) through July 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1, the Company has suffered recurring losses since its inception and has a working capital deficiency. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ RBSM, LLP

New York, New York

March 30, 2011

F-1

COUGAR OIL AND GAS CANADA, INC.

CONSOLIDATED BALANCE SHEETS

(REPORTED IN CANADIAN DOLLARS)

	December 31,						July 31,
	2010			2009			2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	1,678		$	-		$	1,804		$	-
Accounts receivable		467,359			322,872			432,205			15,705
Accounts receivable, other		51,165			12,960			-			-
Prepaid expenses and deposits (note 2)		59,038			70,148			83,397			-
Total current assets		579,240			405,980			517,406			15,705

Oil and natural gas properties, full cost accounting (note 3)
Proved properties		9,212,427			7,184,463			8,587,053			-
Less: accumulated depreciation, depletion and amortization		(3,466,639	)		(2,276,463	)		(3,087,053	)		-
Net		5,745,788			4,908,000			5,500,000			-
Undeveloped properties excluded from amortization (note 3)		3,936,797			3,920,062			3,934,051			4,064,730
Furniture and fixtures, net		5,363			-			5,663			-
		9,687,948			8,828,062			9,439,714			4,064,730

Total assets	$	10,267,188		$	9,234,042		$	9,957,120		$	4,080,435

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses (note 4)	$	1,889,266		$	1,218,656		$	1,985,461		$	937,389
Operating line of credit (note 5)		2,025,000			-			1,425,000			-
Current maturities of long term debt (note 6)		818,906			566,311			672,124			-
Short term notes payable (note 6)		15,623			75,000			65,833			-
Related party obligations (note 10)		458,008			1,104,252			674,519			180,668
Total current liabilities		5,206,803			2,964,219			4,822,937			1,118,057

Long term debt (note 6)		2,707,186			3,526,092			3,051,978			-

Asset retirement obligations (note 7)		1,332,747			1,221,793			1,311,206			107,667
Total liabilities		9,246,736			7,712,104			9,186,121			1,225,724

Commitments and contingencies (note 11)

Stockholders' equity (notes 8 and 9)
Common stock, no par value; unlimited authorized; 64,047,111 and 44,997,979 shares issued and outstanding as of December 31, 2010 and 2009, respectively; 61,853,353 and 40,665,860 issued and outstanding as of July 31, 2010 and 2009, respectively		5,207,027			4,219,164			4,134,039			3,295,195
Additional paid in capital		622,174			128,210			320,863			69,279
Deficit		(4,810,977	)		(2,825,399	)		(3,683,623	)		(509,729	)
Other comprehensive income (loss)		2,228			(37	)		(280	)		(34	)
Total stockholders' equity		1,020,452			1,521,938			770,999			2,854,711

Total liabilities and stockholders' equity	$	10,267,188		$	9,234,042		$	9,957,120		$	4,080,435

The accompanying notes are an integral part of these financial statements

F-2

COUGAR OIL AND GAS CANADA, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(REPORTED IN CANADIAN DOLLARS)

										From November 21, 2008
	Five Months Ended			Five Months Ended			Year Ended			(date of inception)
	December 31,			December 31,			July 31,			Through July 31,
	2010			2009			2010			2009
REVENUE:
Oil sales, net of royalties	$	1,178,303		$	629,993		$	2,657,720		$	-

EXPENSES:
Operating		689,282			422,587			1,327,376			-
General and administrative		1,039,009			623,563			1,618,635			505,216
Impairment of oil and gas properties		-			2,030,267			2,132,179			-
Depletion and amortization		418,212			269,866			1,032,485			4,513
Total expenses		2,146,503			3,346,283			6,110,675			509,729

Net loss from operations		(968,200	)		(2,716,290	)		(3,452,955	)		(509,729	)

OTHER INCOME (EXPENSE):
Gain on settlement of operating agreement		-			516,000			516,000			.
Gain on asset retirement		933			-			77,419			-
Interest income		240			69			-			-
Interest expense		(160,326	)		(115,449	)		(314,358	)		-

Net loss before income taxes		(1,127,354	)		(2,315,670	)		(3,173,894	)		(509,729	)

Provision for income taxes (benefit) (note 13)		-			-			-			-

NET LOSS	$	(1,127,354	)	$	(2,315,670	)	$	(3,173,894	)	$	(509,729	)

Loss per common stock, basic and fully diluted	$	(0.02	)	$	(0.05	)	$	(0.06	)	$	(0.02	)
Weighted average number of outstanding shares, basic and fully diluted		62,083,745			43,071,212			52,044,457			22,262,318

Comprehensive loss:
Net loss	$	(1,127,354	)	$	(2,315,670	)	$	(3,173,894	)	$	(509,729	)
Foreign currency translation gain (loss)		2,508			(3	)		(246	)		(34	)

Comprehensive loss	$	(1,124,846	)	$	(2,315,673	)	$	(3,174,140	)	$	(509,763	)

The accompanying notes are an integral part of these financial statements

F-3

COUGAR OIL AND GAS CANADA, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
FROM NOVEMBER 21, 2008 (DATE OF INCEPTION) THROUGH DECEMBER 31, 2010
(REPORTED IN CANADIAN DOLLARS)

						Additional					Other
	Common stock					Paid in					Comprehensive
	Shares		Amount			Capital		Deficit			Income (loss)			Total
Balance, November 21, 2008 (date of inception)		45	$	-		$	-	$	-		$	-		$	-
Common stock issued in exchange for undeveloped properties from related party		38,076,933		2,821,287			-		-			-			2,821,287
Sale of common stock		2,588,882		473,908			-		-			-			473,908
Fair value of issued options		-		-			69,279		-			-			69,279
Foreign currency transaction loss		-		-			-		-			(34	)		(34	)
Net Loss		-		-			-		(509,729	)		-			(509,729	)
Balance, July 31, 2009		40,665,860		3,295,195			69,279		(509,729	)		(34	)		2,854,711
Foreign currency translation loss		-		-			-		-			(3	)		(3	)
Fair value of issued options							58,931								58,931
Sale of common stock		3,634,619		722,469			-		-			-			722,469
Common stock issued in exchange for oil & gas property		697,500		201,500											201,500
Net Loss		-		-			-		(2,315,670	)		-			(2,315,670	)
Balance, December 31, 2009		44,997,979		4,219,164			128,210		(2,825,399	)		(37	)		1,521,938
Common stock issued to acquire related party note receivable		648,444		1,357,714			-		-			-			1,357,714
Effect of merger with Cougar Oil and Gas Canada, Inc. (formerly Ore-More Resources, Inc.)		16,200,000		(1,446,838	)		-		-			-			(1,446,838	)
Common stock issued in exchange for exercise of warrants		6,930		3,999			-		-			-			3,999
Fair value of issued options		-		-			192,653		-			-			192,653
Foreign currency translation loss		-		-			-		-			(243	)		(243	)
Net loss		-		-			-		(858,224	)		-			(858,224	)
Balance, July 31, 2010		61,853,353		4,134,039			320,863		(3,683,623	)		(280	)		770,999
Common stock issued in exchange for exercise of warrants		2,007,918		590,220			-		-			-			590,220
Common stock issued for debt repayment to related party		185,840		482,768			-		-			-			482,768
Fair value of issued options							301,311								301,311
Foreign currency translation gain		-		-			-		-			2,508			2,508
Net loss		-		-			-		(1,127,354	)		-			(1,127,354	)
Balance, December 31, 2010		64,047,111	$	5,207,027		$	622,174	$	(4,810,977	)	$	2,228		$	1,020,452

The accompanying notes are an integral part of these financial statements

F-4

COUGAR OIL AND GAS CANADA, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(REPORTED IN CANADIAN DOLLARS)

										From November 21, 2008
	Five Months Ended			Five Months Ended			Year Ended			(date of inception)
	December 31,			December 31,			July 31,			Through July 31,
	2010			2009			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,127,354	)	$	(2,315,670	)	$	(3,173,894	)	$	(509,729	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation, accretion and depletion		418,212			269,866			1,032,485			-
Impairment loss on oil and gas properties		-			2,030,267			2,132,179			-
Gain on settlement of operating agreement		-			(516,000	)		(516,000	)		-
Gain on asset retirement		(933	)		-			(77,419	)		-
Fair value of vested options for services rendered		301,311			58,931			251,584			69,279
Changes in operating assets and liabilities:
Accounts receivable		(86,319	)		(307,167	)		(416,328	)		(3,368	)
Prepaid and other		24,359			(70,148	)		(83,397	)		-
Accounts payable and accrued expenses		(96,196	)		281,267			1,047,891			937,390
Net cash used in operating activities		(566,920	)		(568,654	)		197,101			493,572

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of undeveloped properties		(642,853	)		(993,561	)		(2,887,649	)		(1,135,776	)
Purchase of equipment		(1,118	)					(6,858	)		-
Cash acquired from acquisition of Ore-More Resources, Inc.		-			-			7,708			-
Net cash used in investing activities		(643,971	)		(993,561	)		(2,886,799	)		(1,135,776	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock		-			722,469			722,469			473,908
Proceeds from exercise of warrants		590,220			-			3,999			-
Proceeds from operating line of credit		600,000			-			1,425,000			-
Proceeds from (repayments of) short term borrowing		(50,210	)		75,000			540,000			-
Proceeds from related party loans		266,257			910,625			-			168,330
Net repayments of long-term debt		(198,010	)		(145,876	)		-			-
Net cash provided by financing activities		1,208,257			1,562,218			2,691,468			642,238

Effect on foreign currency rate change on cash		2,508			(3	)		34			(34	)

Net increase in cash and cash equivalents		(126	)		-			1,804			-

Cash and cash equivalents-beginning of period		1,804			-			-			-
Cash and cash equivalents-end of period	$	1,678		$	-		$	1,804		$	-

Supplemental disclosures of cash flow information:
Taxes paid
Interest paid	$	160,012		$	115,148		$	303,807

Non cash financing activities:
Common stock issued in exchange for undeveloped property	$	-		$	201,500		$	201,500		$	2,821,287
Debt issued in exchange for related party debt	$	482,768		$	-		$	-		$	-
Property received in settlement of operating agreement	$	-		$	516,000		$	516,000		$	-
Gain on settlement of debt	$	-		$	-		$	77,419		$	-
Common stock issued to acquire related party receivable	$	-		$	-		$	1,357,714		$	-
Effect of Merger with Cougar Oil and Gas Canada, Inc. (formerly Ore-More)	$	-		$	-		$	(1,446,838	)	$	-
Transfer of notes payable to related party	$	-		$	-		$	490,000		$	-

The accompanying notes are an integral part of these financial statements

F-5

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements are as follows:

Basis and business presentation

Our main operations are currently in the Alberta and British Columbia provinces of Canada. Our focus has developed into the specific projects of:

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

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

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

Other Alberta properties.

Reverse Acquisition

In January 2010, the Company entered into a stock purchase Agreement (the “Agreement”) with Cougar Energy, Inc. (which we refer to as CEI) and Cougar then shareholders whereby CEI agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:

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

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

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

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

F-6

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

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

b) On January 25, 2010, the Company finalized a share purchase agreement between the Company and Kodiak Energy Inc. (“Kodiak”) whereby the Company purchased from Kodiak a total of 8,461,549 shares of the common shares of CEI held by Kodiak. The share purchase agreement called for the Company to issue a total of 1.5 shares of common stock for each share of CEI tendered by Kodiak, resulting in the Company issuing a total of 12,692,324 (38,076,933 shares post split) shares of common stock. As further consideration for the acquisition of the CEI common shares, the Company forgave all current indebtedness owed to the Company by Kodiak and guaranteed by CEI, which was in the amount of $1,296,889 (Cdn $1,357,714). An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Company were cancelled.

Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of the Company. Subsequent to the completion of the reverse acquisition, the Company amended its article of incorporation and changed its name to Cougar Oil and Gas Canada, Inc.

Functional currency

The reporting and functional currency of the Companies is the Canadian dollar. When a transaction is executed in a foreign currency, it is re-measured into Canadian dollars based on appropriate rates of exchange in effect at the time of the transaction. The resulting foreign currency transactions gains (losses) are included in general and administrative expenses in the accompanying consolidated statements of operations.

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

F-7

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Estimates

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

Reclassification

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

Revenue Recognition

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

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

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

Cash and Cash Equivalents, and Concentrations of Credit Risk

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

F-8

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Accounting for Bad Debts and Allowances

Bad debts and allowances are provided based on historical experience and management's evaluation of outstanding accounts receivable. Management periodically evaluates past due or delinquency of accounts receivable in evaluating its allowance for doubtful accounts. For oil and gas sales receivables we generally only consider booking an allowance if and when a specific instance of nonpayment occurs. Allowance for doubtful accounts was $nil at December 31, 2010 and 2009; July 31, 2010 and July 31, 2009.

Segment Information

The Company adopted Accounting Standards Codification subtopic Segment Reporting 280-10 (“ASC 280-10”). ASC 280-10 establishes standards for reporting information regarding operating segments in annual consolidated financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. ASC 280-10 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision making group, in making decisions concerning how to allocate resources and assess performance. The Company applies the management approach to the identification of our reportable operating segment as provided in accordance with ASC 280-10 and concluded that the Company operates as a single segment and will evaluate additional segment disclosure requirements as it expands its operations. The information disclosed herein, materially represents all of the financial information related to the Company's principal operating segment.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of properties within a relatively large geopolitical cost center in our case, by country, and are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs designated as unproven properties are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at December 31, 2010 and 2009 and July 31, 2010 and 2009. Unevaluated and undeveloped costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

F-9

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable country cost center. The Company has assessed the impairment for oil and natural gas properties for the full cost pool at each reporting date and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes is compared to (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues is based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test takes into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price is consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities from November 21, 2008 (date of inception) through December 31, 2010. Application of the ceiling test is required for reporting purposes, and any write-downs are not reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss as recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no recognized in current period operations.

Furniture and Fixtures

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

Reserves

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

F-10

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Impairment of long lived assets

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

Fair Values

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

Income Taxes

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

Comprehensive Income (Loss)

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

F-11

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Net Loss per Share

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

Fully diluted shares outstanding were 66,292,403 and 43,071,212 shares for the five months ended December 31, 2010 and 2009, respectively.

Fully diluted shares outstanding were 68,278,265 and 40,665,860 for the year ended July 31, 2010 and for the period November 21, 2008 (date of inception) through July 31, 2009, respectively.

Stock based compensation

Effective since inception, the Company has adopted Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”) which requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro-forma disclosure is no longer an alternative. This statement does not change the accounting guidance for share based payment transactions with parties other than employees provided in ASC 718-10. The Company implemented ASC 718-10 on November 21, 2008 (date of inception) using the modified prospective method.

As more fully described in Note 9 below, the Company granted equity based compensation over the years to employees of the Company under its equity plans. The Company granted non-qualified stock options of 625,000 and nil shares of common stock of the Company and nil (cancellations of 30,000) and 235,000 shares of the Company’s wholly owned subsidiary, Cougar Energy, Inc. during the five months ended December 31, 2010 and 2009, respectively, to employees and directors of the Company under the Employee Retention Plan. During the year ended July 31, 2010 and from November 21, 2008 (date of inception) through July 31, 2009, the Company granted non-qualified stock options to purchase 635,000 and nil shares of common stock of the Company and 920,000 (net of cancellations of 125,000) and nil shares of the Company’s wholly owned subsidiary, Cougar Energy, Inc., respectively, to employees and directors of the Company under the Employee Retention Plan.

As of December 31, 2010, there were outstanding employee stock options to purchase 2,240,000 shares of the Company's common stock, 310,004 shares of which were vested.

F-12

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

Recent accounting pronouncements

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

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

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

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

2. PREPAID EXPENSES AND DEPOSITS

Prepaid expenses and deposits were comprised of the following:

	December 31, 2010		December 31, 2009			July 31, 2010		July 31, 2009
Prepaid general and administrative expenses	$	20,043	$	-	$	50,340	$	-
Prepaid rent		27,885		27,885		27,885		-
Prepaid insurance		-		10,227		4,008		-
Deposits and other		11,110		32,036		1,164		-
Total	$	59,038	$	70,148	$	83,397	$	-

F-13

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

3. OIL AND GAS PROPERTIES

Major classes of oil and gas properties under the full cost method of accounting consist of the following:

	December 31,
	2010		2009
Proved properties, net of cumulative impairment charges	$	9,212,427	$	7,184,463
Unevaluated and Unproved properties		3,936,797		3,920,062
Gross oil and gas properties		13,149,224		11,104,525
Less: accumulated depletion, accretion and impairments		(3,466,639)		(2,276,463)
Net oil and gas properties	$	9,682,585	$	8,828,062

	July 31,
	2010			2009
Proved properties, net of cumulative impairment charges	$	8,587,053		$	-
Unevaluated and Unproved properties		3,934,051			4,064,730
Gross oil and gas properties		12,521,104			4,064,730
Less: accumulated depletion, accretion and impairments		(3,087,053	)		-
Net oil and gas properties	$	9,434,051		$	4,064,730

Unevaluated and Unproved Properties

The Company has certain unevaluated and unproved properties, valued at cost, that have been excluded from costs subject to depletion. These costs amounting to $3,936,797 as at December 31, 2010 (December 31, 2009 - $3,920,062, July 31, 2010-$3,934,051, July 31, 2009-$4,064,730) are subject to a test for impairment that is separate from the test applied to proved properties.

Included in the Company’s oil and gas properties are asset retirement obligations of $1,207,371 and $1,185,439, comprising both current and long term items as of December 31, 2010 and 2009, respectively and $1,222,105 and $94,982, comprising both current and long term items as of July 31, 2010 and 2009, respectively.

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

Impairment Charges

During the year ended July 31, 2010, total impairment charges under the full cost ceiling test were $2,132,179 and is reported within the expense category “Impairment of Oil and Gas Properties”. The most significant factor causing the full year charge was the write off during the year of reserves, which represented approximately 13% of carrying cost at July 31, 2009, together with earlier than expected depletion on a number of other wells, leading to other reserve reductions. Also oil prices continued to fall during the year ended July 31, 2010. Weighted average product prices in our July 31, 2010 reserves report, and used for the ceiling test at that date, were $69.87/bbl (CND).

During the five months ended December 31, 2010, total impairment charges under the full cost ceiling test were Nil (December 31, 2009 - $2,030,267- see above).

F-14

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

4. ACCOUNTS PAYABLE AND ACCRUED LIABLITIES

Accounts payable and accrued liabilities are comprised of the following:

	December 31,
	2010		2009
Accounts payable	$	1,185,027	$	922,130
Accrued expenses		604,886		158,320
Cash calls and Joint venture payables		99,353		134,769
Royalties and GST taxes payable		-		3,437
Total	$	1,889,266	$	1,218,656

	July 31,
	2010		2009
Accounts payable	$	1,598,827	$	901,031
Accrued expenses		264,913		-
Cash calls and Joint venture payables		111,390		36,358
Royalties and GST taxes payable		10,331		-
Total	$	1,985,461	$	937,389

5. OPERATING LINE OF CREDIT

During the year ended July 31, 2010 the Company reached formal agreement with a Canadian bank for two credit facilities. The first credit facility is a revolving demand loan facility in the amount of Cdn$1,500,000 bearing an interest at prime plus 3.5% per annum. The second credit facility is a $1,000,000 non-revolving acquisition/development demand loan bearing an annual interest rate of prime plus 3.0% per annum. Under the terms of the Agreement, the two credit facilities are committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves.

On October 14, 2010, the first credit facility revolving demand loan was increased from $1,500,000 to $2,500,000 and the second credit facility was then cancelled.

As at December 31, 2010, $2,025,000 of the revolving line was drawn (December 31, 2009 – nil, July 31, 2010-$1,425,000).

F-15

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

6. LONG TERM AND SHORT TERM NOTES PAYABLE

Long term and short term notes payable are comprised of the following:

	December 31,
	2010			2009
Obligation under purchase and sale agreement to acquire property from vendor, gross amount	$	3,930,000		$	4,700,000
Amount of discount to be accreted in the future (at 7.5% annually - .0625% per month)		(413,908	)		(683,597	)
Net carrying value		3,516,092			4,016,403
Less current portion		(808,906	)		(500,311	)
Long term portion	$	2,707,186		$	3,516,092

Current portion of long term debt-as above	$	808,906	$	500,311
Note payable-non- interest bearing, due on demand		10,000		66,000
Total current maturities of long term debt	$	818,906	$	566,311

	July 31,
	2010			2009
Obligation under purchase and sale agreement to acquire property from vendor, gross amount	$	4,210,000		$	-
Amount of discount to be accreted in the future (at 7.5% annually - .0625% per month)		(519,898	)		-
Net carrying value		3,690,102			-
Less current portion		(638,124	)
Long term portion	$	3,051,978		$	-

Current portion of long term debt-as above	$	638,124	$	-
Note payable-non- interest bearing, due on demand		34,000		-
Total current maturities of long term debt	$	672,124	$	-

On August 18, 2009, the Company entered into a Purchase and Sale Agreement to acquire certain oil and gas properties. The Gross purchase price of $6,000,000 is payable over a 54 month term with variable monthly payments. Amounts owing under the Purchase and Sale Agreement are non-interest bearing.

The Company recorded the obligation at present value using an interest rate of 7.5% per annum and is accreting using the effective interest method over the term of the obligation.

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

On January 6, 2010, the Company issued a $200,000 unsecured promissory note, due one year from the date of the note with interest at Bank of Canada prime plus 1%,. As of December 31, 2010, the balance under this promissory note was $Nil.

F-16

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

6. LONG TERM AND SHORT TERM NOTES PAYABLE

On December 19, 2009, the Company issued a $15,000 U.S. promissory note, due on demand with interest at Canada prime plus 2%. As of December 31, 2010, the balance under this promissory note was $15,623 CAN.

7. ASSET RETIREMENT OBLIGATIONS

The Company’s financial statements reflect the provisions of Accounting Standards Codification Subtopic 410-20, Asset Retirement Obligations (“ASC 410-20”) ASC 410-20 provides that, if the fair value for an asset retirement obligation can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by ASC 410-20, the retirement obligation is recorded as a liability at its estimated present value at the asset’s inception, with an offsetting increase to producing properties on the Consolidated Balance Sheet. Periodic accretion of discount of the estimated liability is recorded, as appropriate, as an expense in the Consolidated Statement of Operations and is included in depletion, depreciation and accretion. The Company’s asset retirement obligations relate to all of the wells. The Company has recognized an asset retirement liability of $1,332,747 and $1,221,793 at December 31, 2010 and 2009, respectively, and of $1,311,206 and $107,667 at July 31, 2010 and 2009, respectively.

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,023,859 (December 31, 2009 - $2,992,241, July 31, 2010-$3,067,453, July 31, 2009-$162,362). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 14 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and a rate of inflation of 2.5%.

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

	December 31,
	2010		2009
Asset retirement obligations, beginning of the period	$	1,311,206	$	107,667
Additions		-		1,090,456
Accretion		37,207		23,670
Assets retired		(15,666)		-
Asset retirement obligations, end of period	$	1,332,747	$	1,221,793

	July 31,
	2010		2009
Asset retirement obligations, beginning of the period	$	107,667	$	-
Additions		1,127,123		103,154
Accretion		76,416		4,513
Asset retirement obligations, end of period	$	1,311,206	$	107,667

F-17

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

8. STOCKHOLDERS EQUITY

The Company is authorized to issue an unlimited number of no par value preferred and common stock.

As of December 31, 2010 and 2009, the Company had no preferred stock issued and outstanding and had outstanding common stock totaling 64,047,111 and 44,997,979 shares, respectively.

As of July 31, 2010 and 2009, the Company had issued and outstanding 61,853,353 and 40,665,860 shares of common stock, respectively.

On January 25, 2010, in connection with the reverse acquisition, the Company affected a three-for-one (3 to 1) stock split of its issued and outstanding shares of no par value common stock. All references in the consolidated financial statements and the notes to consolidated financial statements, number of shares, and share amounts have been retroactively restated to reflect the split.

During the period ended July 31, 2009, the Company issued an aggregate of 38,076,933 shares of common stock to acquire oil and gas properties. The fair value was determined based on the acquisition cost of Kodiak Energy, Inc., the Company’s parent.

During the period ended July 31, 2009, the Company sold 2,588,822 shares of the Company’s common stock for $473,908. This was the initial startup investment into the private subsidiary by early investors for non-liquid shares of Cougar Energy, Inc. Subsequent to the share exchange with Oremore, these shares were converted to shares of Cougar Oil and Gas Canada, Inc.

During the five months ended December 31, 2009, the Company issued 697,500 shares to acquire oil and gas property. As previously disclosed as the Mystahiya transaction

During the year ended July 31, 2010 (and December 31, 2010), the Company issued 6,930 shares of the Company’s common stock in exchange for exercise of warrants

During the five months ended December 31, 2009, the Company issued 3,634,619 shares of the Company’s common stock for cash totaling $722,469.

During the five months ended December 31, 2010, the Company issued 185,840 common shares, at fair value, in repayment of debt in the amount of $482,768, issued 2,007,918 common shares in exchange for the exercise of warrants and cash totaling $590,220 after expenses and 648,444 shares of the Company’s common stock in exchange for a related party note receivable. As previously disclosed – Kodiak Energy, Inc acquired debt instruments of Cougar Energy, Inc and then converted the debt to shares in Cougar Oil and Gas Canada, Inc.

9. STOCK OPTIONS AND WARRANTS

Options

Cougar Oil and Gas Canada Stock Option Plan

Cougar Oil and Gas Canada has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable 1/3 per year over the first three years of the term of the option.

F-18

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

9. STOCK OPTIONS AND WARRANTS (continued)

Transactions involving options issued to employees are summarized as follows:

	Number of Shares		Weighted Average Price Per Share
Outstanding at November 21, 2008		-	$	-
Granted		-		-
Exercised		-		-
Canceled or expired		-		-
Outstanding at December 31, 2008		-	$	-
Granted		-		-
Exercised		-		-
Canceled or expired		-
Outstanding at December 31, 2009		-	$
Granted		1,260,000		2.47
Exercised		-		-
Canceled or expired		-		-
Outstanding at December 31, 2010		1,260,000	$	2.47

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

December 31, 2010
Weighted average
Exercise Price			Shares
$ 1.40			50,000
$ 1.52			50,000
$ 1.83			45,000
$ 2.02			35,000
$ 2.36			30,000
$ 2.38			600,000
$ 2.92			450,000
$ 2.47			1,260,000

Outstanding							Exercisable
Number outstanding at December 31, 2010	Weighted Average remaining Contractual life		Weighted average Exercises Price		Aggregate intrinsic value		Number outstanding at December 31, 2010		Weighted average Exercise price		Aggregate Intrinsic Value
35,000		4.25	$	2.02		-		-				-
600,000		4.42	$	2.38		-		-				-
50,000		4.78	$	1.40		-		-
50,000		4.82	$	1.52		-		-				-
45,000		4.91	$	1.83		-		-				-
30,000		4.93	$	2.36		-		-		-		-
450,000		4.96	$	2.92		-		-		-		-
1,260,000			$	2.47				-		-		-

During the year ended July 31, 2010, the Company granted an aggregate of 635,000 stock options with an exercise price from $2.02 to $2.38 expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:	-0- %
Volatility		100.0%
Risk free rate:		2.61% to 2.89 %

During the five months ended December 31, 2010, the Company granted an aggregate of 625,000 stock options with an exercise price from $1.40 to $2.92 expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:	-0- %
Volatility		100.0%
Risk free rate:		1.94% to 2.56 %

F-19

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

9. STOCK OPTIONS AND WARRANTS (continued)

Cougar Energy, Inc. Stock Option Plan

Cougar Energy, Inc. (a wholly owned subsidiary of 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 1/3 per year over the first three years of the term of the option.

Transactions involving options issued to employees are summarized as follows:

	Number of Shares		Weighted Average Price Per Share
Outstanding at November 21, 2008		-	$	-
Granted		-		-
Exercised		-		-
Canceled or expired		-		-
Outstanding at December 31, 2008		-	$	-
Granted		985,000		0.82
Exercised		-		-
Canceled or expired		-
Outstanding at December 31, 2009		985,000	$	0.82
Granted		60.000		-
Exercised		-		-
Canceled or expired		(55,000)		-
Outstanding at December 31, 2010		990,000	$	0.82

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

December 31, 2010
Weighted average Exercise
Price			Shares
$ 0.65			725,000
$ 1.30			265,000
$ 0.82			990,000

Outstanding							Exercisable
Number outstanding at December 31, 2010	Weighted Average remaining Contractual life		Weighted average Exercises Price		Aggregate intrinsic value		Number outstanding at December 31, 2010		Weighted average Exercise price		Aggregate Intrinsic Value
725,000		3.04	$	0.65		-		310,004	$	0.65		-
265,000		3.84	$	1.30		-		-		-		-
990,000			$	0.82				310,004	$	0.65		-

During the year ended July 31, 2010, the Company granted an aggregate of 295,000 stock options (30,000 options cancelled during the five months ended December 31, 2010) with an exercise price of $1.30 expiring five years from issuance. The fair values were determined using the Black Scholes option pricing model with the following assumptions:

Dividend yield:	-0- %
Volatility		100%
Risk free rate:		2.51% to 2.75 %

During the five months ended December 31, 2010, the Company did not grant any additional options.

The fair value of all employee options vesting in the five month periods ended December 31, 2010 and December 31, 2009 of $301,311 and $58,931, respectively, was charged to current period operations.

Subsequent to the period end, on January 1, 2011, Cougar Energy, Inc. merged with its parent, Cougar Oil and Gas Canada Inc. Both of the companies are Alberta corporations and were merged in a statutory amalgamation under Alberta corporate law. Upon that merger, and after giving effect to the Cougar Oil and Gas Canada/Cougar Energy Inc. share exchange at 1:1.5 and the subsequent 3:1 split of Cougar Canada Oil and Gas Canada Inc. shares, the 625,000 and 295,000 outstanding Cougar Energy, Inc. stock options exercisable at $.65 and $1.30 per share, respectively shown above became 2,812,500 and 1,327,500 outstanding Cougar Oil and Gas Canada stock options exercisable at $.144 and $.289 respectively.

F-20

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

9. STOCK OPTIONS AND WARRANTS (continued)

Warrants

The following table summarizes in warrants outstanding and related prices for the shares of the Company’s common stock issued to shareholders at December 31, 2010:

				Warrants Outstanding Weighted Average						Warrants Exercisable
				Remaining		Weighted				Weighted
		Number		Contractual		Average		Number		Average
Exercise Price		Outstanding		Life (years)		Exercise price		Exercisable		Exercise Price
$	0.288		1,907,655		0.57	$	0.288		1,907,655	$	0.288
$	0.577		2,301,003		0.62	$	0.577		2,301,003	$	0.577
Total			4,208,658		0.60				4,208,658

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

	Number of Shares		Weighted Average Price Per Share

Outstanding at July 31 and December 31, 2009		-	$	-
Issued		6,223,506		0.98
Exercised		(6,930)		0.577
Canceled or expired
Outstanding at July 31, 2010		6,216,576		0.40
Issued		-		-
Exercised		(2,007,918)		0.29
Canceled or expired		-		-
Outstanding at December 31, 2010		4,208,658	$	0.35

10. RELATED PARTY TRANSACTIONS

From time to time, the Company’s majority shareholder, Kodiak Energy, Inc. has provided working capital to the Company. There are no formal repayment terms and the loan is interest free. As of December 31, 2010 and 2009, the balance due was $458,008 and $1,104,252, respectively and as of July 31, 2010 and 2009, the balance due was $674,519 and $180,668, respectively.

During the year ended July 31, 2009, the Company issued 38,076,933 of the Company’s common stock in exchange for oil and gas properties held by Kodiak Energy, Inc.; the Company’s parent. The valuation was recorded at the underlying cost of Kodiak and the deemed value of the land.

F-21

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS)

10. RELATED PARTY TRANSACTIONS (continued)

During the year ended December 31, 2010, the Company issued 185,840 common shares at fair value, in payment of debt totaling $482,768 held by Kodiak Energy, Inc. the Company’s parent.

The Company paid $25,000 to a company owned and controlled by the chairman of the Company for management consulting services during the five months ended December 31, 2010 ($35,000 during the year ended July 31, 2010). Of this amount, $21,000 was payable on December 31, 2010 ($10,500-July 31, 2010). The Company paid the wife of the chairman of the Company $13,560 for administration consulting services during the five months ended December 31, 2010 ($11,340 for the year ended July 31, 2010). Of this amount, $5,292 was outstanding on December 31, 2010 ($4,032 - July 31, 2010). These amounts were charged to General and Administrative Expense.

Cougar Energy Inc. paid management fees to Kodiak Energy, Inc. in the amount of $393,500 for the year ended July 31, 2009 and $190,000 July 31, 2010. Fees paid for the five months ended December 31, 2009 were $190,000 and December 31, 2010 $Nil.

During the five months ended December 31, 2010, the Company exchanged $425,000 and $90,000 debt owed to Zentrum and Menschen for debt owed to Kodiak Energy, Inc. the Company's parent.

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

11. COMMITMENTS AND CONTINGENCIES

Lease Commitments

As of December 31, 2010 and 2009, the Company had lease commitments for office space and equipment as shown below:

	2010		2009
Amounts payable in:
2010	$		$	125,481
2011		208,275		167,307
2012		208,275		167,307
2013		75,394		41,827

As of July 31, 2010 and 2009, the Company had lease commitments for office space and equipment as shown below:

	July 31, 2010		July 31, 2009
Amounts payable in:
2011	$	175,280	$	-
2012		175,280		-
2013		118,182		-

The Company relocated its offices in December 2009 and pays rent of approximately $14,000 per month until the lease expires in February 2013. The rent expense for the five months ended December 31, 2010 and 2009 is $67,732 and $nil, respectively. ($67,732--July 31, 2010 and $nil--July 31, 2009). The remaining lease commitments pertain to two trucks and a number of office computers.

F-22

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

11. COMMITMENTS AND CONTINGENCIES (continued)

Litigation

The Company is subject to other legal proceedings and claims, which arise in the ordinary course of its business. Although occasional adverse decisions or settlements may occur, the Company believes that the final disposition of such matters should not have a material adverse effect on its financial position, results of operations or liquidity. There was no outstanding litigation as of December 31, 2010.

12. FAIR VALUE OF FINANCIAL ASSETS AND FINANCIAL LIABILITIES

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

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

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

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

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

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

F-23

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

13. INCOME TAXES

For the five months ended December 31, 2010 and 2009:

For the five-month periods ended December 31, 2010 and 2009, a reconciliation of the income tax benefit at the combined Canadian federal and Alberta provincial statutory rate to the income tax benefit at the Company's effective tax rate is as follows.

	2010			2009
Combined statutory rate	28%			29%

Income tax benefit at combined statutory rate	$	315,658		$	693,586
Stock compensation expense		(119,835	)		(37,181	)
Impact of rate change		(32,581	)		(16,825	)
Other		(4,307	)		(9,765	)
Change in valuation allowance	$	158,935		$	629,815

The provision for income taxes differs from the amount of income tax determined by applying the applicable Canadian statutory rate to losses before income tax expense for the five month periods ended December 31, 2010 and 2009 as follows:

	December 31,
	2010			2009
Statutory federal income tax rate		18.00	%		19.21	%
Statutory provincial income tax rate		10.00	%		10.00	%
Stock compensation expense		(10.63	%)		(1.56	%)
Impact of rate change		(2.89	%)		(0.70	%)
Other		0.38	%		0.41	%
Net operating losses and other tax benefits for which no current benefit is being realized		(14.86	%)		(26.545	%)
Effective tax rate		0.00	%		0.00	%

F-24

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

13. INCOME TAXES (continued)

Deferred tax assets (liabilities) at December 31, 2010 and 2009 are comprised of the following:

	2010			2009
Deferred tax assets
Excess of capital assets tax deductions over book value	$	1,238,587		$	946,774
Non-capital operating losses		422,959			337,482
Asset retirement obligations		373,169			354,320
Total deferred tax assets		2,034,715			1,638,576

Deferred tax liabilities		-			-
Net deferred tax asset before valuation allowance		2,034,715			1,638,576
Less valuation allowance		(2,034,715	)		(1,638,576	)
Net deferred tax asset	$	-		$	-

As at December 31, 2010 and 2009, the Company's deferred tax asset attributable to its non-capital operating losses carried forward are $422,959 and $337,482 respectively and will expire in the years 2016 and 2017, if not utilized. Undeducted capital costs can be carried forward indefinitely. As reflected above, the calculated tax 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. We do not have any unrecognized tax benefits or loss contingencies.

For the year ended July 31, 2010 and from November 21, 2008 (date of inception) through July 31, 2009:

For the years ended July 31, 2010 and 2009, a reconciliation of the income tax benefit at the combined Canadian federal and Alberta provincial statutory rate to the income tax benefit at the Company's effective tax rate is as follows.

	July 31, 2010			July 31, 2009
Combined statutory rate	28.42%			29.21%

Income tax benefit at combined statutory rate	$	904,937		$	148,883
Difference arising from additional tax deductible property cost		-			782,115
Impact of rate change		(26,755	)		-
Other		(247	)		2,388
Change in valuation allowance	$	877,935		$	933,386

The provision for income taxes differ from the amount of income tax determined by applying the applicable Canadian statutory rate to losses before income tax expense for the year ended July 31, 2010 and the period from November 21, 2008 (date of inception) through July 31, 2009 as follows:

F-25

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

13. INCOME TAXES (continued)

	July 31,
	2010			2009
Statutory federal income tax rate		18.42	%		19.21	%
Statutory provincial income tax rate		10.00	%		10.00	%
Difference arising from additional tax deductible property cost		.00	%		153.44	%
Other		(.76	%)		.46	%
Net operating losses and other tax benefits for which no current benefit is being realized		(27.66	%)		(183.11	%)
Effective tax rate		0.00	%		0.00	%

Deferred tax assets (liabilities) at July 31, 2010 and 2009 are comprised of the following:

	July 31, 2010			July 31, 2009
Deferred tax assets
Excess of capital assets tax deductions over book value	$	1,144,563		$	754,373
Non-capital operating losses		350,002			147,565
Asset retirement obligations		372,601			31,448
Total deferred tax assets		1,867,166			933,386

Deferred tax liabilities		-			-
Net deferred tax asset before valuation allowance		1,867,166			933,386
Less valuation allowance		(1,867,166	)		(933,386	)
Net deferred tax asset	$	-		$	-

As at July 31, 2010 and 2009, the Company's deferred tax asset attributable to its non-capital operating losses carried forward are $350,002 and $147,565 respectively and will expire in the years 2016 and 2017, if not utilized. Capital costs not deducted can be carried forward indefinitely. As reflected above, the calculated tax 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. We do not have any unrecognized tax benefits or loss contingencies.

14. SUBSEQUENT EVENTS

On January 1, 2011, Cougar Oil and Gas Canada, Inc. was amalgamated with its wholly owned subsidiary, Cougar Energy, Inc. As a result of the amalgamation, the Company, which will continue under the name Cougar Oil and Gas Canada, Inc., has changed its financial reporting year end to December 31st.

Subsequent to December 31, 2010, the Company has issued a total of 3,823,170 common shares pursuant to the exercise of warrants with proceeds totaling $1,255,842.

F-26

COUGAR OIL AND GAS CANADA, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(REPORTED IN CANADIAN DOLLARS

14. SUBSEQUENT EVENTS (continued)

The Company received $900,000 from Kodiak Energy Inc. and issued an 18 months unsecured convertible note to Kodiak on January 31, 2011 in the same amount with an interest rate of prime plus 3% per annum. Kodiak will also receive a 1% gross over-riding royalty on two wells that the funds are intended to finance. The note is convertible into common shares of the Company at a price of $3.52 per share.

During February 2011, the Company received the initial draw down of 950,000 Swiss Francs ($985,388 CAN) on an unsecured note agreement with a maximum issuance of 4,700,000 Swiss Francs (approximately $5,000,000 CAN), subject to certain conditions. The note has a term of 18 months and accrues interest at the rate of Bank of Canada prime plus 3% per annum.The holder of the note, Zentrum Energie Trust SA, has the option to convert the balance of the note plus accrued interest into common shares of Cougar at the rate of $3.00 per common share along with a warrant to purchase additional common shares on a 1:1 basis for a period of 4 years at a price of $3.90 per common share.

On March 4, 2011, Mr. David Wilson resigned as Chief Financial Officer due to health reasons. On the same date, Mr. Richard Carmichael was appointed as Mr. Wilson’s replacement. Mr. Carmichael is a Chartered Accountant who has held senior financial positions within the oil and gas exploration and production, and oil and gas service industries over the past 20 years.

F-27

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING

ACTIVITIES (UNAUDITED)

(All currency amounts in Canadian dollars))

In accordance with the Accounting Standards Update 2010-03, Extractive Activities - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, ("ASU 2010-03"), issued by the Financial Accounting Standards Board of the United States, this section provides supplemental information on oil and gas exploration and producing activities of the Company as of December 31, 2010 in the following tables. Since there were no reserves or revenue for the preceding year of 2008 there is no comparison tables provided for those years. Tables I through III provide historical cost information under US GAAP pertaining to capitalized costs related to oil and gas producing activities; costs incurred in oil and gas exploration and development; and results of operations related to oil and gas producing activities. Tables IV through XI present information on the Company’s estimated net proved reserve quantities; standardized measure of discounted future net cash flows;

This statement of reserves data and other information (the “Statement”) is dated March 8, 2011 and is effective December 31, 2010. The preparation date of the information in this Statement was March 8, 2011.

Table I: Capitalized costs related to oil and gas producing activities

	5 months ended December 31
	2010				2009	*

Property cost – land and acquisitions	$	10,080,381		$	9,911,760
Drilling and Completions		1,403,577			7,326
Facilities		263,721			(0	)
Long lived asset in regards to asset retirement obligation		1,207,371			1,185,439
Seismic		194,174			(0	)
Total capitalized costs		13,149,224			11,104,525
Accumulated depreciation, depletion, amortization and impairment losses		(3,466,639	)		(2,276,463	)
Net capitalized costs	$	9,682,585		$	8,828,062

*Note – only includes 3 months of costs for 2009 – October to December 2009.

Table II: Cost incurred in oil and gas exploration and development

For the 5 months ended December 31, 2010, the Company incurred the following costs on properties in Canada:

Property cost
Proved Properties	$	(206,609)
Unproved Properties		2,745
Exploration Costs		227,627
Development costs		619,088
Total capitalized costs	$	642,851

	5 months ended December 31,
Table III: Results of operations for oil and gas producing activities	2010				2009	*

Sales	$	1,380,540		$	748,270
Royalties		(202,238	)		(118,278	)
Operating expenses		(689,282	)		(422,587	)
Depreciation, depletion, amortization and impairment losses		(379,586	)		(2,237,152	)
Taxes other than income tax		(0	)		(0	)
Income before income tax		109,434			(2,029,747	)
Income tax expense		(0	)		(0	)
Results of operation from producing activities	$	109,434		$	(2,029,747	)

* Note – only includes 3 months of revenue for 2009 – October to December 2009.

COUGAR Oil and Gas Canada, Inc.

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING

ACTIVITIES (UNAUDITED)

(All currency amounts in millions Cnd.)

The results of operations for producing activities for the 5 months ended December 31, 2009 and 2010 are shown above. Revenues include sales to unaffiliated parties. All revenues reported in this table include royalties where applicable. Income taxes are based on statutory tax rates, reflecting allowable deductions and tax credits. General corporate overhead and interest income and expense are excluded from the results of operations.

Reserves Categories

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although probable and possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are, by their nature, more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized by us. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Due to the inherent uncertainties and the limited nature of reservoir data, estimates of underground reserves are subject to change as additional information becomes available.

“Net” reserves exclude royalties and interests owned by others and reflect contractual arrangements in effect at the time of the estimate.

Estimated Reserves

The following tables presents our estimated net proved, probable and possible oil and gas reserves relating to our oil and natural gas properties as of December 31, 2010, based on our reserve reports as of such date. The data was prepared by the independent petroleum-engineering firm GLJ Petroleum Consultants Ltd. (GLJ). Reserves at December 31, 2010 were determined using the unweighted arithmetic average of the first day of the month price for each month from January 2010 through December 2010, which we refer to as the 12-month average price as of December 31, 2010, of $73.93 per barrel of oil.

Reserves

Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity, and continual reassessment of the viability of production under various economic and political conditions.

Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir.

The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.

For the United States, the primary impacts of the SEC’s final rule on our reserve estimates include: The use of the unweighted 12-month average of the first-day-of-the-month reference price of $69.87 per barrel for oil compared to average consolidated revenue of $74.64 (net of transportation) per barrel received for the months of October 1, 2009 to July 31, 2010 when we had sales. A reference price of $73.93 for December 31, 2010 was used in the most recent reserve evaluation – where the Company received 79.81 USD at December 31, 2010. – thus our comments as to subjective price points and that effect on estimates and ceiling tests and resultant write downs.

The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Science Degree in Geology and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG). He has more than 25 years of experience in reservoir geology.

All reserve information in this report is based on estimates prepared by GLJ, independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at GLJ meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas by the Society of Petroleum Engineers. GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Internal Controls for Reserves Reporting

A significant component of our internal controls in our reserve estimation effort is our practice of using an independent third-party reserve engineering firm to prepare 100% of our year-end proved reserves and, for 2010, our probable and possible reserves. The qualifications of this firm are discussed below under “Independence and Qualifications of Reserve Preparer.” The Board of Directors of the Company has reviewed the reserves estimates and procedures prior to acceptance of the report. The Board of Directors has sufficient technical training and experience to review and approve the report

Our internal geologist is our Vice President, Exploration and reports to our President, Operations, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to our independent third party reserve engineers to estimate our year-end reserves. Our internal geologist staff consists of one degreed geologist, with over 25 years of diversified geological experience in the Canadian oil and gas industry, including in the Western Canadian Sedimentary Basin. He is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG).

Independence and Qualifications of Reserve Preparer

We engaged GLJ Petroleum Consultants Ltd. (GLJ), third-party reserve engineers, to prepare our reserves as of December 31, 2010 in accordance with reserves definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (COGE), the Canadian Securities Administrators National Instrument 51-101 (NI 51-101) using Forecast Pricing Assumptions and, for the SEC, using Constant Pricing Assumptions. The technical person responsible for our reserve estimates at GLJ meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth by The Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA). GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own any interest in our properties and are not employed on a contingent fee basis.

Year-end reserves quantities for the year ended December 31, 2010 shown in the following tables were calculated using the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period covered by the report. The estimated impact of changing to the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period was not significant as the Company had no reserves prior to September 30, 2009. – There were no reserves as of July 31, 2009 or 2008 and thus a comparison table is not provided.

Table IV: Reserve quantities information

The Group’s estimated net proved underground oil and gas reserves and changes thereto for the years ended December 31, 2010 are shown in the following table

OIL AND GAS RESERVES SUMMARY December 31, 2010 (Mbbl)
	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total Oil Equivalent
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
PROVED – Developed Producing	201	180	23	20	-	-	-	-	223	200
PROVED – Developed Non Producing	82	75	-	-	-	-	-	-	82	75
PROVED – Undeveloped	118	97	-	-	-	-	-	-	118	97
TOTAL PROVED	401	352	23	20	-	-	-	-	424	372
PROBABLE	283	237	7	5	-	-	-	-	290	242
TOTAL PROVED Plus PROBABLE	684	589	30	25	-	-	-	-	713	613

Table V: Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of ASU 2010-03. Estimated future cash inflows from production are computed by the average, first-day-of-the-month price for oil and gas during the twelve-month period before the ending date of the period covered by the report for the year ended July 31, 2010 to year-end quantities of estimated net proved reserves. Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of year-end economic conditions. Estimated future income taxes are calculated by applying appropriate year-end statutory tax rates to estimated future pre-tax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditure will be incurred and when the reserves will be produced.

The information provided does not represent management’s estimate of the Company’s expected future cash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded from the calculations. The arbitrary valuation requires assumptions as to the timing and amount of future development and production costs. The calculations are made for the year ended December 31, 2010 and should not be relied upon as an indication of the Company’s future cash flows or value of its oil and gas reserves. As there was no reserves or revenue as of July 31, 2009 or 2008 - no comparison tables are provided.

NET PRESENT VALUE OF FUTURE NET REVENUE Based on Constant Prices and Costs December 31, 2010
Reserves	Before Income Taxes Discounted at (% Per Year)
Category			$M Cdn		July 31, 2010
	0%	8%	10%	12%	10%
PROVED – Developed producing	4,040	3,629	3,536	3,447	4,731
PROVED – Developed Non-producing	1,296	1,133	1,097	1,064	426
PROVED – Undeveloped	3,620	2,923	2,788	2,665	0
TOTAL PROVED	8,956	7,685	7,421	7,175	5,157
PROBABLE	8,747	6,730	6,362	6,032	2,753
TOTAL PROVED PLUS PROBABLE	17,703	14,415	13,783	13,208	7,910

Notes:

Numbers may not add exactly due to rounding.

Numbers are M $ Cdn as reserve reports were calculated on that basis.

Table VI: Production Volumes, Sales Prices and Production Costs

The following table sets forth information regarding our oil and natural gas properties. The oil and gas production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells.

SUMMARY OF NET REVENUE

December 31, 2010 (Undiscounted)



				Capital	Well Abandonment	Future Net
			Operating	Development	and Reclamation	Revenue Before
Reserves Category	Revenue	Royalties	Costs	Costs	Costs	Future Income Tax
Proved Reserves	31,833	3,808	15,833	2,732	503	8,956
Probable Reserves	21,802	3,569	7,693	1,731	62	8,747
Proved Plus Probable Reserves	53,635	7,377	23,526	4,463	566	17,703

Notes:

Numbers may not add exactly due to rounding.

Numbers are MM $ Cdn.

Table VII: RECONCILATION OF Company Gross Reserves by Principal Product Type - Mbbl

December 31, 2010 (Mbbl)
Factors	Total Oil				Light and Medium Oil				Heavy Oil
	Proved	Probable	Proved +Probable	Proved	Probable	Proved + Probable	Proved	Probable	Proved + Probable
Acquisitions	326	151	477	298	144	442	28	7	35
Production	0	-	0	0	-	0	0	-	0
July 31, 2010	326	151	477	298	-	442	28	7	35
Production	(19)	-	(19)	(17)	-	(17)	(2)	-	(2)
Dispositions	(6)	(2)	(8)	-	-	-	(6)	(2)	(8)
Technical Revisions	13	(14)	0	17	(14)	3	(3)	0	(3)
Infill Drilling	115	155	270	115	155	270	-	-	-
December 31, 2010	430	290	720	407	283	690	23	7	30

Numbers may not add exactly due to rounding

Table VIII: Land Holdings Without Attributed Reserves as at December 31, 2010

The following table summarizes information with respect to the Company’s properties to which no reserves have been specifically attributed:

Total Unproved Properties (Hectares) – Gross 3,200 and Net 3,079

There are no material work commitments on the above undeveloped land holdings.

Additional information regarding wells, costs and associated activities

Table IX: The following table summarizes the Company’s working interests, as at December 31, 2010, in oil and gas wells located in Canada:

SUMMARY Oil and Gas Wells December 31, 2010
	Oil Wells Gross	Oil Wells Net	Natural Gas Wells Gross	Natural Gas Wells Net	Service Wells Gross	ServiceWells Net	Total Gross	Total Net
Total Canada Producing (1)	15.0	10.83	0	0	0	0	15	10.83
Total Canada Non Producing (2)	36.0	29.47	2.0	.0875	4	3.63	42	33.975

Notes:

1. Includes wells that are temporarily shut-in but which are capable of production.

2. Includes wells that are not capable of production but that are not yet abandoned

Additional Information Concerning Abandonment and Reclamation Costs –

The Company bases its estimates for the costs of abandonment and reclamation of surface leases, wells, facilities and pipelines on previous experience of management with similar well sites and facility locations in the area. Costs for abandonment of reserve wells are included in the GLJ Report as a deduction in arriving at future net revenue. As at December 31, 2010, management expected to incur such future costs on 47.915 net wells. Within the next five financial years, it is expected such costs will total $212, 000 in respect of abandonment and reclamation costs for surface leases, wells, facilities and pipelines. The costs used by GLJ for abandonment of reserve wells based on industry averages in the area and regulatory published estimates. Surface lease reclamation is not considered and facilities costs were deemed recoverable with salvage of the equipment.

Table X: Company Annual Abandonment Costs (M$ CAD)

December 31, 2010
	2011	2012	2013	2014	2015	12yr Total	Total to 2021 10% discount
Proved Producing	0	0	21	24	17	233	126
Total Proved	0	0	113	74	106	503	307
Total Proved Plus Probable	0	0	50	112	50	566	301

Table XI: Exploration and Development Activities

For the year ended December 31, 2010, the Company completed the following exploratory and development wells:

	Exploratory wells Gross	Exploratory Wells Net	Development Wells Gross	Development Wells Net
Oil	0	0	0	0
Gas	0	0	0	0
Service	0	0	0	0
Dry	0	0	0	0
Total	0	0	0	0

ITEM 19. EXHIBITS

Number	Description
3.1	Articles of Incorporation	Filed by reference to Exhibit 3.1 filed with Form F-1filed with the SEC on February 20, 2008
3.2	Articles of Amendment	Incorporated by reference to the Exhibits 3.2 filed with the Form F-1 filed with the SEC on February 20, 2008
3.3	Bylaws	Incorporated by reference to the Exhibits 3.3 filed with the Form F-1 filed with the SEC on February 20, 2008
3.4	Articles of Amendment (Name Change)	Filed by reference to Exhibit 1.1filed with Form F-6 dated February 2010
4.1	Form of Share Certificate	Incorporated by reference to the Exhibits 4.1 filed with the Form F-1 filed with the SEC on February 20, 2008
10.2	Purchase Agreement with Sword and loan agreements –	Filed by reference to 10.5 with Form K-8 filed by Kodiak Energy on October 6, 2009
10.3	Purchase Agreement with Mistahiya	filed by reference to 10.6 with Form K-8 filed by Kodiak Energy on October 6, 2009
10.4	Share purchase agreement between Registrant and Kodiak Energy, Inc	incorporated by reference to Exhibits
10.5	Code of Conduct Policy	filed by reference to 10.5 with Form 20-f filed November 24, 2010
10.6	Cougar Oil and Gas Canada, Inc Stock Option Plan	filed by reference to 10.6 with Form 20 F filed November 24, 2010
10.7	Credit line agreement with Canadian Western	filed by reference to 10.7 with Form 20-F filed November 24, 2010
12.1	Certification required by Rule 13a-14(a) or Rule 15d-14(a) – Principal Executive Officer and Principal Financial Officer	Filed herewith
13.1	Certification required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350) – Principal Executive Officer and Principal Financial Officer	Filed herewith

SIGNATURES

The issuer hereby certifies that it meets all the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	COUGAR OIL AND GAS CANADA,INC.

Date: March 31, 2011	By:	/s/ William S Tighe
		Name: William S. Tighe
		Title: Chairman of the Board (Principal Executive Officer and Principal Financial Officer)

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Cougar Oil & Gas Canada (COUGF) Inactive 20-F2010 FY Annual report (foreign)

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