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Exhibit A to letter of November 28, 2011.

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.

The information was developed for purposes of NI-51 – 101 and Canadian reporting and it may not comply or be deficient in certain areas which have been noted

The Third Party report on Reserves by GLJ Petroleum Consultants was prepared in accordance with requirements contained in Item 1202 (a) (8) of US Securities and exchange Commission Regulations S-K – the certificate is filed as Exhibit 10.8 herein. The report as filed does not satisfy the SEC reporting requirements in certain respects. We specifically make note that this Report is not in compliance with Regulation S-K Subpart 1202.

Description of Properties and Plan of Operations

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.

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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.

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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.

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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.

4. 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.

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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:

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(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.

Northern Alberta – First Nations 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.

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.

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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.

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.

	•	Approximately 75,000 gross acres for accessand 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).

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Lucy, British Columbia

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

The current intention is to perform the previously planned vertical and horizontal work programs for the license). In lieu of obtaining our own financing, we are actively enlisting joint venture partners to move the project forward by way of divesting part of our interest. Monthly the Company reviews the opportunity and balances the risk versus reward, which can be adjusted depending on cash flow, commodity prices and financing. When 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.

Oil and Gas Leases and Development Rights

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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.

Table I: Properties with No Attributed Reserves

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

Table I: Properties with No Attributed Reserves

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

Land Holdings Without Attributed Reserves as at December 31, 2010
	Unproved Properties (Hectares)
	Gross	Net
Total Canada	3,200	3,079
Total Other Countries	0	0

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

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Table II: 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 III: 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 IV: 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.

(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.

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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.

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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.

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Reserve quantities information

As required under SEC Regulation S-K, reserves are those quantities of oil and gas that are estimated to be economically producible under existing economic conditions. As specified, in determining economic production, constant produt reference prices have been based on a 12 month average price, calculated as the unweighted arithmetic average of the first-day-of –the-month price for each month within the 12-month period prior to the effective date of this report. In the economic analysis, operating and capital costs are thos costs estimated as applicable at the effective date of the report, with no future escalation. Where deemed appropriate, the capital costs and revised operating costs associated with the implementation of committed projects designed to modify specific field operations in the future may be included in economic projections.

Table V: The estimated net proved underground oil and gas reserves and changes thereto for the year ended December 31, 2010 are shown in the following table

Company had no reserves prior to September 30, 2009. –thus a comparison table is not provided.

Company Net Proved Reserves

(Mbbl)
Location of Reserves	Crude Oil Mbbl		Natural Gas MMcf		Natural Gas Liquids Mbbl		Oil Equivalent Mbbl		Proportion Oil Eq. Reserves
Country Region	July 31, 2010	December 31, 2010	July 31, 2010	December 31, 2010	July 31, 2010	December 31, 2010	July 31, 2010	December 31, 2010	July 31, 2010	December 31, 2010
Canada Alberta	294	372	0	0	0	0	294	372	100%	100%


TOTAL Company	294	372	0	0	0	0	294	372	100%	100%

Table VIa. The estimated net proved underground oil and gas reserves by product for the year ended July 31, 2010 are shown in the following table.

OIL AND GAS RESERVES SUMMARY July 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	231	202	28	25	-	-	-	-	259	227
PROVED – Developed Non Producing	63	58	-	-	-	-	-	-	63	58
PROVED – Undeveloped			-	-	-	-	-	-
TOTAL PROVED	294	261	28	25	-	-	-	-	322	285
TOTAL PROBABLE	132	120	7	6	-	-	-	-	139	125

Table VIb. The estimated net proved underground oil and gas reserves by product for the transition period ended December 31, 2010 are shown in the following table.

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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
TOTAL PROBABLE	283	237	7	5	-	-	-	-	290	242

Table VII: 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.

Table VII(a) NET PRESENT VALUE OF FUTURE NET REVENUE Based on Constant Prices and Costs December 31, 2010
Reserves	Before Income Taxes Discounted at (% Per Year) $M Cdn
Category	December 31, 2010	July 31, 2010
	10%	10%
PROVED – Developed producing	3,536	4,731
PROVED – Developed Non-producing	1,097	426
PROVED – Undeveloped	2,788	0
TOTAL PROVED	7,421	5,157
TOTAL PROBABLE	6,362	2,753

Notes:

Numbers may not add exactly due to rounding.

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

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Table VII (b) STANDARDIZED MEASURE OF DISCOUNTED FURTURE NET CASH FLOWS AND CHANGES RELATED TO PROVED OIL AND GAS RESERVES

Based on Constant Prices and Costs

At December 31, 2010

	Total			Canada
Future Cash Inflows	$	31,223		$	37,559
Future Production and development costs	$	(22,267	)	$	(25,919	)
Future income tax expenses		-			-
Future net cash flows	$	8,956		$	8,956
10% annual discount for estimating timing of cash flows	$	(1,535	)	$	(1,535	)

Standardized measure of discounted future net cash flows		$	7,421			$	7,421
Entity’s share equity method investees standardized measure of discounted future net cash flows		$	7,421			$	7,421

Notes:1) Constant $ Case

2) Tax not calculated on Constant $ case; Operating revenue on constant $ case lower than on market forecast case by more than taxable income in years where taxes were incurred, therefore Constant $ case would likely incur no income taxes.

Table VII (c) CHANGES IN THE STANDARDIZED MEASURE FOR DISCOUNTED CASH FLOWS FOR THE AT DECEMBER 31, 2010.

Net change in sales and transfer prices and in production(lifting) costs related to future production	n/a
Changes in estimated future development costs	n/a
Sales and transfers of oil and gas produced during the period	n/a
Net change due to extensions, discoveries, and improved recovery	n/a
Net change due to purchases and sales of minerals in place	n/a
Net change due to revisions in quantity estimates	n/a
Previously estimated development costs incurred during the period	n/a
Accretion of discount	n/a
Other - unspecified	n/a
Net change in income taxes	n/a
Aggregate change in the standardized measure of discounted future net cash flows for the year	$ -

Note: information is not available from third party engineering report as filed.

Table VIII: Production Volumes, Sales Prices and Production Costs

The following table sets forth information regarding our Canadian 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.

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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

Notes:

Numbers may not add exactly due to rounding.

Numbers are M $ Cdn.

Table IX: Reconciliation 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

July 31, 2010	322	139		294	132	28	7
Production	(19)	0		(17)	0	(2)	0
Dispositions	(6)	(2)		(6)	(2)	0	0
Technical Revisions	13*	(14)*		17*	(14)*	(3)*	0*
Infill Drilling	118*	167*		115*	167*	0*	0*
December 31, 2010	424	290		401	283	23	7

Note: * Numbers not available for Constant Pricing Tables - numbers presented are company estimates based on Forecast Pricing Tables.

Numbers may not add exactly due to rounding

Table X: 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	Service Wells 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

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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 XI: Company Annual Abandonment Costs (M$ CAD) – Canada Operations

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

Table XII: Exploration and Development Activities – Canada Operations

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

Table XII: Production Estimates

The following table discloses the total volume of production estimated by GLJ for 2011 in the estimates of future net revenue from proved reserves disclosed about under the heading “Oil Reserves and net Present Value of Future net Revenue”

	Light and Medium Oil Bbl/d	Heavy Oil Bbl/d	Natural Gas Mmf/d	Natural Gas liquids Bbl/d	BOE	Property Allocation%
Trout	414	0	0	0	690,000	95.8%
Alexander		26	0	0	30,000	4.2%

Notes: Numbers may not add exactly due to rounding

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Table XIII: Costs Incurred

For the financial year ended December 31, 2010, the Corporation incurred the following costs on properties in Canada:

Costs Incurred Year Ended December 31, 2010
(Canadian Dollars)
Property Acquisition costs:
Proved Properties	151,967.66
Unproved Properties	16,735.08
Exploration costs	277,627.77
Development costs	1,626,434.93
Total	2,022,765.44

Production History

The following tables sets forth certain information in respect of production, revenue, royalties paid by Cougar Oil and Gas Canada, Inc for each quarter of its most recently completed financial period:

Table XIV: Average Daily Production and Cumulative

Light and Medium Oil	Fiscal Q1 2010		Fiscal Q2 2010		Fiscal Q3 2010		Fiscal Q4 2010		Total for Fiscal Year ended December 31, 2010
	Daily Ave Bbl/d	Total Bbl	Daily Ave Bbl/d	Total Bbl	Daily Ave Bbl/d	Total Bbl	Daily Ave Bbl/d	Total Bbl	Total Bbl
Trout Core Area	127.5	11,475.8	182.1	16,574.7	135.0	12,424.0	111.3	10,243.3	50,717.8
Crossfield	3.1	283.3	2.2	201.4	1.3	119.0	0	0	603.7
Alexander	0	0	.5	44.1	9.3	852.8	6.5	597.3	1,494.2

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Table XV: Prices Received, Royalties Paid, Production Costs and netbacks – All amounts expressed in Canadian Dollars

Notes: Numbers may not add exactly due to rounding

Light and Medium Oil	Fiscal Q1, 2010	Avg. Price per barrel	Fiscal Q2, 2010	Avg. Price per barrel	Fiscal Q3, 2010	Avg. Price per barrel	Fiscal Q4, 2010	Avg. Price per barrel	Total for Fiscal Year ended December 31, 2010
Revenue received	901,662	76.68	1,199,747	71.33	956,832	71.43	802,504	74.03	3,860,745
Royalties Paid	146,332	12.44	231,485	13.76	155,096	11.58	121,802	11.24	654,715
Production costs	316,361	26.90	478,686	28.46	364,435	27.21	434,589	40.29	1,594,071
Net back	$438970	37.33	489,576	29.11	437,301	32.64	246,113	22.70	1,611,959

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
10.8	Certificate of GLJ reserve evaluation	filed herewith
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

Re:	Cougar Oil and Gas Canada Inc.
	Form 20-F for the Transition Period Ended December 31, 2010
	Filed March 31, 2011
	Response Letter Dated November 4, 2011
	File No. 0-53879