Cougar Oil & Gas Canada (COUGF) 6-K Cougar Oil and Gas Canada Inc. Form 6-K March 31, 2011

Exhibit 99.1

Cougar Oil and Gas Canada, Inc

December 31, 2010

FORM 51-101F1

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

TABLE OF CONTENTS

PART 1 DATE OF STATEMENT

Item 1.1 Relevant Dates

PART 2 DISCLOSURE OF RESERVES DATA

Item 2.1 Reserves Data (Forecast Prices and Costs)

Item 2.2 Supplemental Disclosure of Reserves Data (Constant Prices and Costs)

Item 2.3 Reserves Disclosure Varies with Accounting

Item 2.4 Future Net Revenue Disclosure Varies with Accounting

PART 3 PRICING ASSUMPTIONS

Item 3.2 Forecast Prices Used in Estimates

PART 4 RECONCILIATION OF CHANGES IN RESERVES

Item 4.1 Reserves Reconciliation

PART 5 ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Item 5.1 Undeveloped Reserves

Item 5.2 Significant Factors or Uncertainties

Item 5.3 Future Development Costs

PART 6 OTHER OIL AND GAS INFORMATION

Item 6.1 Oil and Gas Properties and Wells

Item 6.2 Properties with No Attributed Reserves

Item 6.3 Forward Contracts

Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs

Item 6.5 Tax Horizon

Item 6.6 Costs Incurred

Item 6.7 Exploration and Development Activities

Item 6.8 Production Estimates

Item 6.9 Production History

Cougar Oil and Gas Canada, Inc

December 31, 2010

Forecast Pricing

.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

The Canadian Securities Administrators (CSA) have set out disclosure standards for Canadian Reporting Issuers and publically traded oil and gas companies in National Instrument 51-101

This form presents reserves data following the item numbering and formatting in SCSA Form 51-101F1 and associated tables.

The Report on reserves Data Form 51-101F2 and F3 are provided separately

Note Regarding Nomenclature:

Throughout this report “Company Interest” reserves refers to the sum of royalty interest and working interest reserves before deduction of royalty burdens payable.  “Working Interest” reserves equate to those reserves that are referred to as “company Gross” reserves by CSA in NI-51-101.

In this securities reporting section, Company Gross (or working interest volumes are presented in tables to correspond to NI-51-101 disclosure requirements

royalty interest reserves include royalty volumes derived only from other working interest owners.

PART 1 DATE OF STATEMENT

Item 1.1 Relevant Dates

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.

Terms used and not otherwise defined herein shall have the meanings ascribed thereto in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities, of the CSA.

PART 2 - DISCLOSURE OF RESERVES DATA

Item 2.1.1 Reserves Data (Forecast Prices and Costs)

The estimation of reserves requires significant judgment and decisions based on available geological, geophysical, engineering, and economic data. These estimates can change substantially as additional information from ongoing development activities and production performance becomes available and as economic and political conditions impact oil and gas prices and costs change. The Corporation’s estimates are based on current production forecasts, prices and economic conditions. All of the Corporation’s reserves are evaluated by an independent engineering firm. GLJ Petroleum Consultants Ltd evaluated the Corporation’s producing oil assets at Trout, Crossfield and Alexander Alberta

As circumstances change and additional data becomes available, reserve estimates also change.

Based on new information, reserve estimates are reviewed and revised, either upward or downward, as warranted. Although every reasonable effort has been made by Cougar Oil and Gas Canada, Inc. to ensure that reserve estimates are accurate, revisions arise as new information becomes available. As new geological, production and economic information is incorporated into the process of estimating reserves the accuracy of the reserve estimates improves

OIL RESERVES AND NET PRESENT VALUE OF FUTURE NET REVENUE

In accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas

Activities, GLJ Petroleum Consultants Ltd (“GLJ”) prepared a report (the “GLJ Report”) dated March 8, 2011. The GLJ Report evaluated, as at December31, 2010, Cougar Oil and Gas Canada, Inc., - oil reserves.

The tables below are a summary of the oil reserves of the Corporation and the net present value of future net revenue attributable to such reserves as evaluated in the GLJ Report based on “forecast price and cost assumptions”. The tables summarize the data contained in the GLJ Report and as a result may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to the Corporation’s reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, production costs, development costs, other income, future capital expenditures, and well abandonment costs for only those wells assigned reserves by GLJ. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the Corporation’s reserves estimated by GLJ represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of the Corporation’s oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

The GLJ Report is based on certain factual data supplied by the Corporation and GLJ’s opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Corporation’s petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and accepted without any further investigation. GLJ accepted this data as presented and neither title searches nor field inspections were conducted.

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	171	23	19		0		0	223	190
PROVED – Developed Non Producing	83	73		0		0		0	83	73
PROVED – Undeveloped	124	99		0		0		0	124	99
TOTAL PROVED	407	343	23	19		0		0	430	362
PROBABLE	283	225	7	5		0		0	290	230
TOTAL PROVED Plus PROBABLE	690	568	30	24		0		0	720	592

Notes:

1. Company Gross Reserves – these are working interest owner’s share of gross reserves before the deduction of royalties. Royalty interest share of reserves is included. Gross reserves were not estimated by the independent evaluator.

2. Company Net Reserves:  These are the working interest owners’ share of gross reserves after the deduction of royalties’ - royalty interest share of reserves is not included in this category.

2.1.2 - Net Present Value of Future Net Revenue (Forecast Case)

NET PRESENT VALUES OF FUTURE NET REVENUE BASED ON FORECAST PRICES AND COSTS – December 31, 2010

NPV OF FUTURE NET REVENUE
RESERVES CATAGORY	BEFORE INCOME TAXES DISCOUNTED AT (% PER YEAR)  $M CDN					UNIT VALUE BEFORE INCOME TAX UNDISCOUNTED @ 10% -  $/BOE
	0%	5%	10%	15%	20%
PROVED – Developed producing	5,251	4,813	4,439	4,119	3,842	23.34
PROVED – Developed Non-producing	1,807	1,652	1,519	1,404	1,304	20.81
PROVED – Undeveloped	4,582	3,975	3,510	3,146	2,854	35.53
TOTAL PROVED	11,640	10,440	9,469	8,669	8,001	26.16
PROBABLE	11,058	9,161	7,818	6,829	6,073	34.01
TOTAL PROVED PLUS PROBABLE	22,698	19,601	17,287	15,498	14,073	29.21

Notes:

1. Numbers may not add exactly due to rounding

2. Numbers are M $ Cdn

2.1.3 Additional Information Concerning Future Net Revenue (Forecast Case)

SUMMARY OF NET REVENUE – December31, 2010 (Undiscounted)

Reserves Category	REVENUE	ROYALTIES	OPERATING COSTS	CAPITAL DEVELOPMENT COSTS	WELL ABANDONMENT AND RECLAMATION COSTS	FUTURE NET REVENUE BEFORE FUTURE INCOME TAX
PROVED RESERVES	38,180	5,869	17,354	2,758	559	11,640
PROBABLE RESERVES	27,262	5,466	8,870	1,773	95	11,058
PROVED PLUS PROBABLE RESERVES	65,442	11,335	26,224	4,531	655	22,698

Notes:

1. Numbers may not add exactly due to rounding

2. Numbers are M $ Cdn

3. Disclosure is required for Total Proved and Proved plus Probable reserves.

FUTURE NET REVENUE BY PRODUCTION GROUP

	Future Net Revenue by Production Group – before Income Taxes Discounted at 10% per year.
Proved Producing	M$	$/Boe	$/Mcfe
Light & Medium Oil	4,310	25.24	4.21
Heavy Oil	129	6.66	1.11
Total Proved Producing	4,439	23.34	3.89

Total Proved
Light & Medium Oil	9,337	27.26	4.54
Heavy Oil	132	6.77	1.13
Total Proved	9,469	26.16	4.36
Total Proved plus Probable
Light & Medium Oil	17,023	29.98	5.00
Heavy Oil	265	11.01	1.83
Total Proved plus Probable	17,287	29.21	4.87

Item 2.2 Supplemental Disclosure of Reserves Data (Constant Prices and Costs)

In addition 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 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 $73.43 per barrel for oil compared to average consolidated revenue of $78.63 (net of transportation) per barrel received for the production year. Thus a price point was used for calculations of reserves and impact on long term liabilities which was 93% of actual for this evaluation period – thus our comments as to subjective price points and that effect on estimates.

Item 2.3 Reserves Disclosure Varies with Accounting –

In determining reserves to be disclosed: Cougar files consolidated financial disclosure and has reported 100% of reserves.

Item 2.4 Future Net Revenue Disclosure Varies with Accounting

n/a

PART 3 PRICING ASSUMPTIONS

Item 3.1 Constant Prices Used in Supplemental Estimates

See section 2.2

Item 3.2 Forecast Prices Used in Estimates

The following pricing and inflation rate assumptions as of December 31, 2010 – were used by the independent evaluator -  GLJ Petroleum Consultant Ltd.

Year	Inflation	Bank of Canada average noon exchange rate $US/$Cdn	Light Sweet Crude Oil (40 api, .3%S) at Edmonton then Current $Cdn / bbl	Consolidated Weighted Average price received by Corporation
2009	.4	.880	66.32	$74.20 USD (1) – Oct – Dec/09
2010	1.8%	.971	78.02	78.63
2011 Q1	2%	.980	85.71
2011 Q2	2%	.980	85.71
2011 Q3	2%	.980	86.73
2011 Q4	2%	.980	86.73
2012	2%	.980	89.29
2013	2%	.980	90.92
2014	2%	.980	92.96
2015	2%	.980	96.19
2016	2%	.980	98.62
2017	2%	.980	101.39
2018	2%	.980	103.92
2019	2%	.980	106.68
2020	2%	.980	108.84
2021+	2%	.980	+2%/yr

Note

(1) Includes consolidated prices received by Corporation –

PART 4  RECONCILIATION OF CHANGES IN RESERVES

Item 4.1 Reserves Reconciliation

For previous reporting years, the Corporation was deemed an exploration company with no proven reserves.

We were originally a company solely engaged in the exploration of mineral properties, however subsequent to the 2009 July 31 fiscal year end, we decided broaden the scope of business to include the natural resource sector, being heavy oil, conventional oil and gas.   

As of September 30, 2009 the Cougar Energy, Inc acquired oil and gas reserves in a series of acquisitions – the following tables identify the reserves acquired and the December 31, 2010 reserves value. There were no attributed reserves prior to these acquisitions.

Cougar Oil and Gas Canada, Inc acquired 100% of the outstanding shares of Cougar Energy, Inc. in a series of transactions between January and April 2010.

The following table provides comparison between the July 31, 2010 report and the December 31, 2010 report.  – the increase in Proved and Probable Light and Medium Oil is due to seismic and drilling activities of the Company. The decrease in Proved and Probably Heavy Oil is due to a disposition of the Crossfield property.

RECONCILATION OF Company Gross Reserves by Principal Product Type – Mbbl – net after royalty

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
July 31, 2010	326	151	477	298	144	442	28	7	35
Infill Drilling	115	155	270	115	155	270	0	0	0
Technical Revisions	13	(14)	0	17	(14)	3	(3)	0	(3)
Dispositions	(6)	(2)	(8)	(6)	(2)	(8)
Production	(19)	0	(19)	(17)		(17)	(2)	0	(2)
December 31, 2010	430	290	720	407	283	690	23	7	30

PART 5 ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Item 5.1 Undeveloped Reserves

1. proved undeveloped reserves:

For previous reporting years, the Corporation was deemed an exploration company with no proven reserves.  Cougar Oil and Gas Canada, Inc acquired 100% of the shares of Cougar Energy, Inc. in a series of transactions between January and April 2010.  As of September 30, 2009 Cougar Energy, Inc acquired reserves in a series of acquisitions – the above tables identifies the reserves acquired and the December 31, 2010 reserves value. There were no attributed reserves prior to these acquisitions.

a. The Corporation has Proved non developed reserves

With the use of 3D seismic acquired in September 2010 – the company has identified 2 drill targets which has resulted in new Proved non developed reserves of 124 mbbls (net after royalty 99 mbbls)

2. probable undeveloped reserves:

For previous reporting years, the Corporation was  deemed an exploration company with no proven reserves.  Cougar Oil and Gas Canada, Inc. acquired 100% of the shares of Cougar Energy, Inc. in a series of transactions between January 2010 and April 2010. As of September 30, 2009 the Cougar Energy, Inc. acquired reserves in a series of acquisitions – the above tables identifies the reserves acquired and the December 31, 2010 reserves value. There were no attributed reserves prior to these acquisitions.

See Other Oil and Gas Information section for plans

Our probable heavy oil reserves will be assessed in a future time, as the light sweet production has a better net back at the current commodity prices.

Item 5.2 Significant Factors or Uncertainties

Refer to the Corporations Financial Filings – filled concurrently with this report.

Item 5.3 Future Development Costs –

Company Annual Capital Expenditures (M$)

Description	2011	2012	2013	2014	2015	2016	2017	2018	2019	2020	2021	2022	total	10% Discounted
Proved Producing	0	0	0	0	0	314			190				503	270
Total Proved	2209					336			214				2,758	2,400
Total Proved Plus Probable	3,759					358				239			4,531	3,946

5.3.2 The Corporation has used in past and expects to use a variety of sources of funding to finance its acquisitions and capital development and exploration programs for 2010.

· Internally generated cash flow from operations

· Debt financing – both revolving line of credit and specific debt instruments for specific projects – normally lower risk projects or smaller acquisitions.  Also – 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 – for higher risk projects or larger acquisitions.

 The costs associated with debt are reflected in the cost of the acquisition, the costs of equity raises are reflected in share issue costs.

PART 6 OTHER OIL AND GAS INFORMATION

Item 6.1 Oil and Gas Properties and Wells

Trout Core Properties

Over a period of 6 months in 2009 Cougar Energy, Inc  negotiated commercial terms for properties that have the greatest upside through normal maintenance and enhanced recovery programs as well as future potential with additional drilling.

These negotiations culminated at the end of September and beginning of October 2009 with Cougar Energy, Inc successfully acquiring the Trout Core Area properties from two private oil and gas companies.

The Cougar team had already high graded many of the properties within these acquisitions and could foresee considerable potential to increase existing production in the first round of development - the proverbial “low hanging fruit”.

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 4 wells that were previously suspended..  By December 31, 2010 we had optimized the surface and bottom hole equipment on 10 wells and had 15 wells in production, acquired additional working interest, acquired trade 3D seismic over the primary production area and completed a substantial geological evaluation on the properties.

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

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

· 2560 gross acres of land

· 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

B. Private Company Production and Property Acquisition(completed Sept. 30, 2009) 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 is currently selling at $75+/bbl.

· 7,100 gross acres of mineral rights with an average 85% working interest (all continued through production, no expiries)

· As of December 31, 2010 approximately 200 barrels per day (bbl/d) net production (275 bbl/d gross) – 85 bbl/d at time of acquisition

· 15 pumping wellbores – 8 at time of acquisition1 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- 12 km2 3D acquired in subsequent transactions.

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 and subsequent guarantees by Kodiak and Cougar.

The majority of this acquisition is outside the boundary of the Peerless Trout Lake First Nations lands.  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 costs to date including wells, facilities, pipelines, roads and power lines.

Kodiak was able to borrow sufficient funds for the acquisition on behalf of Cougar by way of a bridge loan.  Those funds were then provided to Cougar who then closed the acquisitions September 30 and October 1/2009.

This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs, lower development costs and giving our schedule an enormous leap forward to achieve our goals of creating a 3- 5,000 bbl/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 now be able to be spent on the drilling and development work – allowing for a more aggressive growth plan.

Additional details include:

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

· 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 2 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.

· There are 37 wells, which 15 were producing as of December 31, 2010 – the 21 suspended wells have potential upside, as discussed below.

· The produced water can be used for future water floods – which regularly have been shown in the area to add substantial incremental production.

· The Company acquired 12 km2 of 3D seismic over existing lands, reprocessed and identified 5 drill locations, and by December 31, 2010 had started licence process for 2 locations – one a horizontal and one a directional.  Expected Q1 2011 spud

· For December 31, 2010 the Company started permitting process for a 28.8 Km2 3D seismic program targeting Q1 2011 for completion.

· As of December 31, 2010 year end - production is averaging 200 bbl/d net of light sweet crude oil from the Trout field at an average operating cost of  Cdn$30.00/bbl.  (including all the maintenance/work over programs)  These acquisitions, provides a solid foundation for us to further enhance the Trout area properties, to give substantial momentum to our plans.    There is great potential upside we see on these properties, with additional capital commitments winter 2010/11 on maintenance programs  as well as planned exploration programs including seismic and drilling

Subsequent Maintenance Programs

Prior to the acquisition, we conducted a detailed review of the of the acquired properties in public domain petroleum records over last 5 to 7 years and with a comparison to other operators in the area.  Our operations and geological teams foresaw a considerable potential to increase production through normal maintenance activities.  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.

Some of these normal maintenance activities include and are not limited to:

· Acid wash of perforations – ongoing

· Setting of bridge plugs to seal off water – ongoing

· Cleanouts – ongoing

· Re perforating –

· Drill out plugs and open up previously unproduced zones – ongoing

· Repairs to wells with separated rods – ongoing

· Plug off water sources with no resulting loss of production - ongoing

· Pump  and well site equipment optimization,  - ongoing

· Waterflood programs - future

Since these existing technologies have proven to be successful in other similar maintenance programs in the area, we saw a high potential to enhance the current production levels within this property.

GLJ Reserve evaluations and Operations Update.   Cougar Energy, Inc - October 1, 2009 ,December 31, 2009, July 31, 2010 and December 31, 2010 –  as filed on SEDAR and EDGAR by Kodiak Energy, Inc. as part of it’s consolidated filings.

These reports were prepared based on the acquisitions of September 30 and October1.  These reports are updates to the look forward reports which were prepared as part of the negotiations for the acquisitions.     Due to the timing of the 3rd  quarter financials September 30, 2009 cut off, only parts of the Oct 1 report were included in the 3rd  quarter financials due to US GAPP rules.

The October1/2009 report gave the first look at the consolidated properties in the “Trout Field” plus the 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 yearend report (5 month stub period due to change of yearend) provides additional analysis after a total of 15 months of operations and work programs.

Thus we continue to demonstrate our ability to increase reserve value with limited capital infusion and our expectations of the opportunities these properties presented were supported by the reports and the results of the field work.

C. Private Company Production and Property Acquisition (completed October 1, 2009)

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

100% working interest in the Crossfield property – 1 producing well with single well battery with approximately 5 barrels per day (bbl/d) net production.  The Crossfield well was sold for P1 reserve value on October 1, 2010 – proceeds were used for working capital .

90% BPO & 55% APO working interest in the Alexander property- 1 producing Wabamun oil with a single well battery, 1 suspended well. The Alexander property had some minor repairs completed in June 2010 and was put back on production. Production is currently approximately 15 barrels per day net production.

We acquired these properties as part of the default on the previous Lucy farm out.

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.

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

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 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).

6.2 -Producing and Non-Producing Wells

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

	Oil wells		Natural gas wells		Service Wells		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	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	0.875	4.0	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

Item 6.2 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

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

Cougar Oil and Gas Canada, Inc. is a petroleum and natural gas exploration and development company whose primary objective is to identify, acquire and develop working interests in undeveloped or underdeveloped petroleum and natural gas prospects. We are focused on prospects located in Canada . The prospects we hold are generally under leases and include partial and full working interests. In all of our core properties, Cougar Oil and Gas, Canada is the operator via Cougar Energy, Inc and majority interest owner.. The prospects are subject to varying royalties due to the state, province or federal governments and, in some instances, to other royalty owners in the prospect.

The Company as Oremore Resources was an exploration stage  company that devoted most of its efforts in exploring for gold mineral resources from June 2007 until early 2010.

Then it progressively acquired the shares in Cougar Energy, Inc – a majority controlled subsidiary of Kodiak Energy, Inc.- from Kodiak Energy, Inc and private shareholders. At that time Oremore Resources changed it’s name to Cougar Oil and Gas Canada, Inc.

Since that time Cougar Canada has been active in Canada acquiring properties that are prospective for petroleum and natural gas and related hydrocarbons. Through it’s subsidiary Cougar Energy, Inc and that company’s acquisition of producing properties effective October 1, 2009,  the Company has become a development company which has oil  reserves and production.

As at December 31, 2010, the Company had one wholly-owned subsidiary – Cougar Energy, Inc.

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. Cougar Energy, Inc. acquired the Lucy property from Kodiak Energy, Inc. and is mentioned in the following description as the previous operator of the property. The Corporation believes the lease is situated on the southeast edge of the Horn River Basin and the Muskwa Shale gas prospect. Industry continues to show increased interest in this shale gas play with several comparisons of the Muskwa Shale gas potential as an analogue of the Barnett Shale gas potential.

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

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

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

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

The Corporation 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. The Corporation has 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.

Cougar contracted an industry-recognized shale gas assessment laboratory to prepare and analyze the drill cuttings from the 2008 well in order to evaluate the Muskwa Shale interval for gas potential. The shale gas assessment is conducted by performing various tests on the rock cuttings that were obtained while drilling the well in order to determine the type, quality and amount of 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 Cougar’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 Cougar lease, drilled deep enough to penetrate the Muskwa Shale, had elevated gas detector readings while penetrating the shales.

The prospect is still in the early stages of delineation 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.

Depending upon commodity prices – the severe turn down in gas prices over the past year  have made natural gas projects difficult to show returns on investment – especially high capital cost project such as the Horn River Basin – despite the very large reserves and recovery rates attributed to the Muskwa shales.   The current $4-$5 gas prices limit the return this project in the short term and thus the financing availability.

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 JV 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.

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

In April, 2009,  Cougar Energy, Inc, entered into a standard farmout and participation agreement with one of its partners.

The partner did not complete its financing commitment and this farmout 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 – the Alexander well and associated equipment was returned to production after a 2 year shut in and the well has been averaging 14 bbl/d of crude oil.  The Crossfield well was sold for P1 reserve value in September 2010 and proceeds applied to trout area operations.

Manning Heavy Oil Project

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.

Item 6.3 Forward Contracts

The Corporation is not a party to any forward contracts (incl. transportation agreements) under which it may be precluded from fully realizing, or may be protected from future market prices for oil and gas.

Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs –

The Corporation 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. 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.

Company Annual Abandonment Costs (M$)

Description	2011	2012	2013	2014	2015	2016	2017	2018	2019	2020	2021	2022	Total	10% Discounted
Proved Producing	0	0	22	25	18		18	91	89				263	141
Total Proved			74	122	115		18	112		30	88		559	330
Total Proved Plus Probable			26	101	72	163		21	19		97		655	329

Item 6.5 Tax Horizon

The Corporation’s current resource tax pools of $14,111,000 and estimated non-capital tax loss carry-forward balance of $1,510,000 have sheltered it from paying cash taxes.  Based on current operations, it is anticipated that the Corporation’s resource tax pools and non-capital tax loss carry-forward balance will shelter it from paying cash taxes until approximately 2014.

Item 6.6 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, 2009
(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

Item 6.7 Exploration and Development Activities

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

Exploration and Development Activities Year ended December 31, 2010
	Exploratory wells		Development wells
	Gross	Net	Gross	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

The Corporation’s most important current and likely exploration and development activities are described under “Oil and Gas Properties”.

Item 6.8 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 plus probable 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:

1. Numbers may not add exactly due to rounding

Item 6.9 Production History

The following table sets forth certain information in respect of production, product prices received, royalties, production costs and netbacks received by Cougar Oil and Gas Canada, Inc for each quarter of its most recently completed financial period:

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

1. Notes: Numbers may not add exactly due to rounding

Prices Received, Royalties Paid, Production Costs and netbacks – light and medium Oil.

1. Notes: Numbers may not add exactly due to rounding

	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, 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

2.

FORM 51-101F3

Report of Management and Directorson Reserves Data and Other Information

Management of Cougar Oil and Gas Canada, Inc (the "Company") are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2010, estimated using forecast prices and costs.

An independent qualified reserves evaluator or qualified reserves auditor has evaluated and reviewed the Company’s reserves data. The report of the independent qualified reserves evaluator or qualified reserves auditor is presented below and will be filed with securities regulatory authorities concurrently with this report.

The board of directors of the Company has (a) reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator or qualified reserves auditor;

(b) met with the independent qualified reserves evaluator or qualified reserves auditor to determine whether any restrictions affected the ability of the independent qualified reserves evaluator or qualified reserves auditor to report without reservation, to inquire whether there had been disputes between the independent qualified reserves evaluator or qualified reserves auditor and management]; and

(c) reviewed the reserves data with management and the independent qualified reserves evaluator or qualified reserves auditor.
 

The board of directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has approved (a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; (b) the filing of Form 51-101F2 which is the report of the independent [qualified reserves evaluator or qualified reserves auditor on the reserves data; and (c) the content and filing of this report. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

___________________________

William S Tighe CEO - Director

__________________________

Glenn Watt President, COO, Director

__________________________

William Brimacombe – Director

March 31, 2011