Alberta Star Development 20-F 2010 FY Annual report (foreign)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 Washington, D.C. 20549

FORM 20-F

o	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For fiscal year ended November 30, 2010
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____ to ______
OR
o	SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Date of event requiring this shell company report:

Commission file number: 0-31172

ALBERTA STAR DEVELOPMENT CORP.

 (Exact name of Registrant as specified in its charter)

Province of Alberta, Canada

(Jurisdiction of incorporation or organization)

506 – 675 West Hastings Street, Vancouver, British Columbia V6B 1N2 Canada

(Address of principal executive offices)

Tim Coupland, President and CEO
Alberta Star Development Corp.
506 – 675 West Hastings Street

Vancouver, British Columbia V6B 1N2 Canada

Tel: (604) 681-3131

Facsimile: (604) 408-3884

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:  Common Shares, no par value

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:None

Indicate the number of outstanding shares of each of the Registrant’s classes of capital or common stock as of the close of the period covered by the annual report:  21,403,979 common shares as at November 30, 2010

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

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

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YesxNoo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every  Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the

preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes oNo o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one)

Large accelerated filer  o  Accelerated filer  oNon-accelerated filer  x

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

U.S. GAAP  o

International Reporting Standards as issued  

o

Other  x

by the International Accounting Standards Board

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

Item 17  x  Item 18  o

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

TABLE OF CONTENTS

ITEM 4 – INFORMATION ON THE COMPANY

2

CAUTIONARY NOTE TO U.S. INVESTORS REGARDING RESOURCE AND RESERVE ESTIMATES – MINING PROPERTIES

This Annual Report on Form 20-F has been prepared in accordance with the requirements of the securities laws in effect in Canada, which differ from the requirements of United States securities laws.  The terms “mineral reserve”, “proven mineral reserve” and “probable mineral reserve” are Canadian mining terms as defined in accordance with Canadian National Instrument 43-101 – Standards of Disclosure for Mineral Projects (“NI 43-101”) and the Canadian Institute of Mining, Metallurgy and Petroleum (the “CIM”) -CIM Definition Standards on Mineral Resources and Mineral Reserves, adopted by the CIM Council, as amended. These definitions differ from the definitions in United States Securities and Exchange Commission (“SEC”) Industry Guide 7 under the United States Securities Act of 1993, as amended (the “Securities Act”).  Under SEC Industry Guide 7 standards, a “final” or “bankable” feasibility study is required to report reserves, the three-year historical average price is used in any reserve or cash flow analysis to designate reserves and the primary environmental analysis or report must be filed with the appropriate governmental authority.

In addition, the terms “mineral resource”, “measured mineral resource”, “indicated mineral resource” and “inferred mineral resource” are defined in and required to be disclosed by NI 43-101; however, these terms are not defined terms under SEC Industry Guide 7 and are normally not permitted to be used in reports and registration statements filed with the SEC.  Investors are cautioned not to assume that any part or all of mineral deposits in these categories will ever be converted into reserves.  “Inferred mineral resources” have a great amount of uncertainty as to their existence, and great uncertainty as to their economic and legal feasibility.  It cannot be assumed that all or any part of an inferred mineral resource will ever be upgraded to a higher category. Under Canadian rules, estimates of inferred mineral resources may not form the basis of feasibility or pre-feasibility studies, except in rare cases. Investors are cautioned not to assume that all or any part of an inferred mineral resource exists or is economically or legally mineable.  Disclosure of “contained ounces” in a resource is permitted disclosure under Canadian regulations; however, the SEC normally only permits issuers to report mineralization that does not constitute “reserves” by SEC Industry Guide 7 standards as in place tonnage and grade without reference to unit measures.

Accordingly, information contained in this Annual Report on Form 20-F and the documents incorporated by reference herein contain descriptions of our mineral deposits that may not be comparable to similar information made public by U.S. companies subject to the reporting and disclosure requirements under the United States federal securities laws and the rules and regulations thereunder.

GLOSSARY OF MINING TERMS

The following are abbreviations and definitions of terms commonly used in the mining  industry and this Annual Report on Form 20-F:

Aeromagnetic survey	A geophysical survey using a magnetometer aboard, or towed behind, an aircraft.
Ag	The chemical symbol for silver.
Au	The chemical symbol for gold.
Andesite	Fine-grain generally volcanic rock composed of feldspar, hornblende and other minor minerals.
Anomaly	Any departure from the norm which may indicate the presence of mineralization in the underlying bedrock.
Anorthosite	Light grey to almost black rock, composed chiefly of calcium feldspar.
Aphebian	Period of time in the Earth’s history between 2.5 and 1.8 billion years ago.
Archean	Period of time in the Earth’s history between 3.8 and 2.5 billion years ago.
Assay	A chemical test performed on a sample of ores or core to determine the amount of valuable metals contained.
Assessment Work	The amount of work, specified by mining law, that must be performed each year in order to retain legal control of mining claims.
Audio-Magnetotellurics (AMT)	A geophysical method that measures the Earth’s varying electric and magnetic fields.
Basin	A round or oval depression in the Earth's surface, containing the youngest section of rock in its lowest, central part.
Batholith	A large mass of igneous rock extending to great depth with its upper portion dome-like in shape. Similar, smaller masses of igneous rocks are known as bosses or plugs.
Breccia	A rock in which angular fragments are surrounded by a mass of fine-grained minerals.
Chalcopyrite	A sulphide mineral of copper and iron; the most important ore mineral of copper.
Channel Sample	A sample composed of pieces of vein or mineral deposit that have been cut out of a small trench or channel, usually about 10 cm wide and 2 cm deep.
Chip Sample	A method of sampling a rock exposure whereby a regular series of small chips of rock is broken off along a line across the face.
Claim	Holder usually has the right to carry out mineral exploration and apply to mine on the located area.
Cretaceous	The third and latest of the periods in the Mesozoic Era.
Diamond Drill	A rotary type of rock drill that cuts a core of rock that is recovered in long cylindrical sections, 2 cm or more in diameter.
Dickite	Dickite is a polymorphic alumino-silicate clay that is formed from hydrothermal environments.
Diorite	An intrusive igneous rock composed chiefly of plagioclase, hornblende, biotite or pyroxene.
EM Survey	A geophysical survey method which measures the electromagnetic properties of rocks.
Exploration	Prospecting, sampling, mapping, diamond drilling and other work involved in searching for ore.
Fault	Fracture in the Earth’s crust, along which there has been displacement of the sides relative to one another parallel to the fracture.
Gabbro	A dark, coarse-grained intrusive igneous rock composed chiefly of feldspar and pyroxene.
Geophysical Surveys	The use of one or more geophysical techniques in geophysical exploration.
Grab Samples	A sample of rock or sediment taken more or less indiscriminately at any place.
Gravity Gradient Survey	A geophysical method used to map and mathematically model underground fault structures based on measurements of the gravity of rocks.
Gneiss	Layered granite-like rock.
Gossan	An iron-oxide rich weathered product overlying a sulphide deposit.
Granite	A coarse-grained intrusive igneous rock consisting of quartz, feldspar and mica.
g/t	Grams per tonne.
Hydrothermal Alteration	Rock alteration simply means changing the mineralogy of the rock.  The old minerals are replaced by new ones because there has been a change in the conditions.  These changes could be changes in temperature, pressure, or chemical conditions or any combination of these.  Hydrothermal alteration is a change in the mineralogy as a result of interaction of the rock with hot water fluids, called “hydrothermal fluids”.
Hydrothermal Fluids	Hydrothermal fluids cause hydrothermal alteration of rocks by passing hot water fluids through the rocks and changing their composition by adding or removing or redistributing components.  Temperatures can range from weakly elevated to boiling.  Fluid composition is extremely variable.  They may contain various types of gases, salts (briney fluids), water, and metals.
Illite	Illite is a layered alumino-silicate clay that is formed from hydrothermal environments.
Induced Polarization (IP)	A geophysical survey method which measures the electrochemical properties of rocks.  Time domain IP methods measure the voltage decay or chargeability over a specified time interval after the induced voltage is removed.  Frequency domain IP methods use alternating currents (AC) to induce electric charges in the subsurface, and the apparent resistivity is measured at different AC frequencies.
IOCG	Iron-Oxide Copper Gold style mineralization.
Km	A measure of distance known as a kilometre.
Leach	To dissolve from a rock. For example, when acidic water passes through fractured rocks, soluble minerals leach or dissolve from the rocks.
Lode	Zone of  mineralization (or ore) in rock, as opposed to placer.
Mo	The chemical symbol for molybdenum.
Mg	The chemical symbol for magnesium.
Mafic	Igneous rocks with dark minerals.
Mesozoic Era	One of the eras of geologic time, follows the Paleaozoic and succeeded by the Cenozoic.
Metallurgy	The study of extracting metals from their ores.
Mineralization	The concentration of metals and their chemical compounds within a body of rock.
Monzonite	Coarse grain igneous rock composed of feldspar, hornblende, biotite and often quartz.
Ni	The chemical symbol for nickel.
NSR	Net Smelter Returns.  A royalty paid from the sale of mined minerals.
NT	Northwest Territories, Canada.
Opt	Ounce per short ton.
Ore	A natural aggregate of one or more minerals, which at a specified time and place, may be mined and sold at a profit, or which from some part may be profitably separated.
Oz	A measure of weight known as an ounce.  Precious metals are generally reported in ounces troy weight.  One troy ounce equals about 31.1 grams.
Paleozoic	Era of geologic time  between Proterozoic and Mesozoic.
Phanerozoic	Period of time in Earth’s history between 544 million year ago and present.
Placer	A deposit of sand and gravel containing valuable metals such as gold, tin or diamonds.
Proterozoic	Period of time in Earth’s history between 2.5 billion years ago and 544 million years ago.
Ppm	Parts per million. Most often reported by weight which is then equivalent to grams per metric ton.
Pyrite	A yellow iron sulphide mineral, normally of little value. It is sometimes referred to as "fool's gold".
Radiometric dating	The calculation of an age in years of geologic materials by any one of several age determination methods based on nuclear decay of natural radioactive elements contained in the material.
Sample	A small portion of rock or a mineral deposit taken so that the metal content can be determined by assaying.
Sampling	Selecting a fractional but representative part of a mineral deposit for analysis.
Shear or shearing	The deformation of rocks by lateral movement along innumerable parallel planes, generally resulting from pressure and producing such metamorphic structures as cleavage and schistosity.
Strike	The coarse or bearing of a bed or layer of rock.
Tailings	Material rejected from a mill after most of the recoverable valuable minerals have been extracted.
Th	The chemical symbol for thorium.
Tonne	Metric ton equals 1,000 kilograms or approximately 2,204 pounds.
Ton	Short ton (or standard ton) equals 2,000 pounds.
U	The chemical symbol for uranium.
U3O8	Uranium oxide. The mixture of uranium oxides produced after milling uranium ore from a mine.  Sometimes loosely called “yellowcake”.  It is yellow in colour and is usually represented by the empirical formula U3O8. Uranium is sold in this form.
Unconformity	A boundary separating two or more rocks of markedly different ages, marking a gap in the geologic record.
Uraninite	A mineral consisting of uranium oxide and trace amounts of radium and thorium and polonium and lead and helium; uraninite in massive form is called pitchblende which is the chief uranium ore.
V2O5	Vanadium oxide. It is usually represented by the empirical formula V2O5.
Vein	A fissure, fault or crack in a rock filled by minerals that have travelled upwards from some deep source.
Volcanic rocks	Igneous rocks formed from magma that has flowed out or has been violently ejected from a volcano.

VTEM Variable time-domain electro-magnetics.  A geophysical survey method.

CAUTIONARY NOTE TO U.S. INVESTORS REGARDING OIL AND GAS PRODUCTION AND RESERVES

The Corporation incorporates additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States.  The Corporation follows the Canadian practice of reporting gross production and reserve volumes; however, it also follows the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments).  The Corporation also follows the Canadian practice of using forecast prices and costs when it estimates its reserves.  However, the Corporation separately estimates its reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements.  These latter requirements are similar to the average constant pricing reserve methodology utilized in the United States.

The Corporation has included estimates of proved and proved plus probable reserves, as well as contingent resources in filings made with it by United States oil and gas companies.  However, the SEC has adopted revisions to its oil and gas reporting rules that, effective as of January 1, 2010, among other things, modified the standards to establish proved reserves and permit disclosure of probable and possible reserves under certain circumstances.  However, it is likely that significant differences will remain between the reserve categories and reserve reporting generally under Canadian and U.S. securities laws and rules.

The primary differences between the Canadian requirements and the US standards are that:

(a)

NI 51-101 requires disclosure of gross and net reserves using forecast prices, whereas the SEC rules require the disclosure of net reserves estimated using a historical 12-month average price;

(b)

NI 51-101 requires the disclosure of the net present value of future net revenue attributable to all of the disclosed reserves categories, estimated using forecast prices and costs, before and after deducting future income tax expenses, calculated without discount and using discount rates of 5%, 10%, 15% and 20%, whereas the SEC rules require disclosure of the present value of future net cash flows attributable to proved reserves only, estimated using a constant price (the historical 12-month average price) and a 10% discount rate;

(c)

NI 51-101 requires a one year reconciliation of gross proved reserves, gross probable reserves and gross proved plus probable reserves, based on forecast prices and costs, for various product types, whereas the SEC rules require a three-year reconciliation of net proved reserves, based on constant prices and costs, for less specific product types; and

(d)

NI 51-101 requires reserves to show a hurdle rate of return, whereas the SEC rules require reserves to be cash flow positive on an undiscounted basis.

We believe that the standards for determining proved reserves under NI 51-101 are consistent with those set forth under U.S. law.

GLOSSARY OF OIL AND GAS TERMS

AECO	Intra-Alberta Nova Inventory Transfer Price (NIT net price of natural gas)
AIT	After Income Tax
APO	After Payout
ARTC	Alberta Royalty Tax Credit
APPO	After Project Payout
Bbl	Barrel
Bbls	Barrels
Bbl/d	Barrels per day
BOE *	Barrels of oil equivalent.  A barrel of oil equivalent is determined by converting a volume of natural gas to barrels using the ration of 6Mcf to one barrel.
BCFE	Billion cubic foot equivalent
BIT	Before Income Tax
BOE/D	Barrels of oil equivalent per day *
BOPD	Barrels per day
BPO	Before Payout
Effective Date	The date for which the Present Value of the future cash flows and reserve categories are established
EOR	Enhanced Oil Recovery
FH	Freehold Royalty
GOR (scf/STB)	Gas-Oil Ratio (standard cubic feet of solution gas per stock tank barrel of oil
GORR	Gross overriding royalty
GJ	Gigajoules
GJ/d	Gigajoules per day
GRP	Gas Reference Price
M$	Thousands of dollars
mKB	Metres Kelly Bushing – depth of well in relation to the Kelly Bushing which is located on the floor of the drilling rig.  The Kelly Bushing is the usual reference for all depth measurements during drilling operations.
MBOE	Thousand barrels of oil equivalent
MM$	Millions of dollars
Mbbls	Thousand barrels
Mcf	1,000 cubic feet
Mcf/d	1,000 cubic feet per day
MMcf	1,000,000 cubic feet
Mmbtu	Million British thermal units
MMbtu	One Million British Thermal Units
MSTB	Thousands of Stock Tank Barrels of oil (oil volume at 60F and 14.65psia)
NC	New Crown – crown royalty on petroleum and natural gas discovered after April 30, 1974
NGLs	Natural gas liquids
NYMEX	New York Mercantile Exchange
Payout	The point at which a participant’s original capital investment is recovered from its net revenue
P&NG	Petroleum and Natural Gas
Psia	Pounds per square inch absolute
Raw Gas	Natural gas as it is produced from the reservoir prior to processing.
Rge	Range
Sec	Section
SS 1/150 (5%-15%) Oil	Sliding scale Royalty – a varying gross overriding royalty based on monthly production.  Percentage is calculated as 1-150th of monthly production with a minimum percentage of 5% and a maximum of 15%.
Twp	Township
$US	United States Dollar
WI	Working interest
WTI	West Texas Intermediate, the common reference price paid in US dollars at Cushing Oklahoma for crude oil of standard grade and used for oil price comparisons

*Note: A BOE conversion ratio of six thousand cubic feet per barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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

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

CONVERSION TABLE

In this Annual Report on Form 20-F a combination of Imperial and metric measures are used.  Conversions from Imperial to metric and from metric to Imperial are provided below:

Imperial Measure          =	Metric Unit	Metric Measure       =	Imperial Unit
2.47 acres	1 hectare	0.4047 hectares	1 acre
3.28 feet	1 meter	0.3048 meters	1 foot
0.62 miles	1 kilometer	1.609 kilometers	1 mile
0.032 ounces (troy)	1 gram	31.1 grams	1 ounce (troy)
1.102 tons (short)	1 tonne	0.907 tonnes	1 ton
0.029 ounces (troy)/ton	1 gram/tonne	34.28 grams/tonne	1 ounce (troy/ton)
6.29 Barrrels (Bbl)	1 Cubic meters	0.159 cubic metres	1 barrel (Bbl)
3.281 feet	1 metre	0.3048 metres	1 foot
0.035 Mcf	1 cubic metre	28.2 cubic metres	1 Mcf
0.949 MMbtu	1 GJ	1.054 GJ	1 MMbtu

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 20-F and the exhibits attached hereto contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements concern our anticipated results and developments in our operations in future periods, planned exploration and development of its properties, plans related to its business and other matters that may occur in the future.  These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.  Statements concerning reserves and mineral resource estimates may also be deemed to constitute forward-looking statements to the extent that they involve estimates of the mineralization that will be encountered if the property is developed, and in the case of mineral reserves, such statements reflect the conclusion based on certain assumptions that the mineral deposit can be economically exploited.  Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” (or the negative and grammatical variations of any of these terms and similar expressions) be taken, occur or be achieved,) are not statements of historical fact and may be forward-looking statements.  Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors which could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:

·

risks related to drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells;

·

risks related to drilling, completion and facilities costs;

·

risks related to abandonment and reclamation costs;

·

risks related to the performance and characteristics of our oil and natural gas properties

·

risks related to expected royalty rates, operating and general administrative costs, costs of services and other costs and expenses risks related to our status as a passive foreign investment company for U.S. tax purposes;

·

risks related to our tax horizon;

·

risks related to our oil and natural gas production levels and the quantity of our oil and natural gas reserves;

·

risks related to fluctuations in the price of oil and natural gas, interest and exchange rates;

·

risks related to the oil and gas industry both domestically and internationally, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand;

·

risks related to actions taken by governmental authorities, including increases in taxes and changes in government regulations and incentive programs;

·

risks related to geological, technical, drilling and processing problems;

·

risks and uncertainties involving geology of oil and gas deposits;

·

risks related to ability to locate satisfactory properties for acquisition or participation;

·

risks related to shut-ins of connected wells resulting from extreme weather conditions;

·

risks related to hazards such as fire, explosion, blowouts, cratering and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury;

·

risks related to encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations;

·

risks related to the possibility that government policies or laws, including laws and regulations related to the environment, may change or governmental approvals may be delayed or withheld;

·

risks related to uncertainty in amounts and timing of royalty payments;

·

risks related to uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom;

·

risks related to failure to obtain industry partner and other third party consents and approvals, as and when required;

·

risks related to changes in hydrocarbon or investment policies;

·

risks related to competition for and/or inability to retain drilling rigs and other services;

·

risks related to the need to obtain required approvals from regulatory authorities;

·

risks related to competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

·

risks related to our history of operating losses;

·

risks related to our lack of mineral production history;

·

risks related to our limited financial resources;

·

risks related to our need for additional financing;

·

risks related to competition in the mining industry;

·

risks related to increased costs;

·

risks related to possible shortages in equipment;

·

risks related to mineral exploration activities;

·

risks related to our lack of insurance for certain activities;

·

risks related to all our properties being in the exploration stage;

·

risks related to uncertainty that our properties will ultimately be developed;

·

risks regarding resource estimates;

·

risks related to differences between U.S. and Canadian practices for reporting resources and reserves

·

risks related to our management’s limited experience in mineral and oil and gas exploration;

·

risks related to fluctuations in precious and base metal prices;

·

risks related to the possible loss of key management personnel;

·

risks related to possible conflicts of interest;

·

risks related to our mineral properties being subject to prior unregistered agreements, transfers, or claims and other defects in title;

·

risks related to governmental and environmental regulations;

·

risks related to our ability to obtain necessary permits;

·

risks related to our status as a foreign corporation;

·

risks related to current economic conditions; and

·

other risks related to our securities.

This list is not exhaustive of the factors that may affect our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further in the sections entitled “Risk Factors”, “Information on the Company” and “Operating and Financial Review and Prospects” and in the exhibits attached to this Annual Report on Form 20-F.  Should one or more of these risks and uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those described in the forward-looking statements.  Our forward-looking statements are based on beliefs, expectations and opinions of management on the date the statements are made and the Company does not assume any obligation to update forward-looking statements if circumstances or management’s beliefs, expectations or opinions change, except as required by law. For the reasons set forth above, investors should not place undue reliance on forward-looking statements.

2

PART I

All references in this Annual Report on Form 20-F (“Annual Report”) to the terms “we”, “our”, “us”, “the Company” and “Alberta Star” refer to Alberta Star Development Corp.   

ITEM 1 – IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not Applicable.

ITEM 2 – OFFER STATISTICS AND EXPECTED TIMETABLE

Not Applicable.

ITEM 3 – KEY INFORMATION

A.

Selected Financial Data

The following information has been extracted from our financial statements for the years indicated and is expressed in Canadian dollars.  The information should be read in conjunction with “Item 5.  Operating and Financial Review and Prospects – A. Operating Results and B. Liquidity and Capital Resources” and the audited annual financial statements of the Company filed herewith.

Our financial statements included in this Annual Report have been prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada. There are several material differences between Canadian GAAP and U.S. GAAP that are applicable to the financial information disclosed or summarized herein. The first table presents this financial data in accordance with U.S. GAAP, the second table presents the data in accordance with Canadian GAAP. Reference is also made to Note 17 in the attached financial statements for an explanation of material differences between Canadian GAAP and U.S. GAAP.  The following table summarizes information pertaining to operations of the Company for the last five fiscal years ended November 30.

All amounts within this Annual Report are in Canadian dollars, unless otherwise indicated.

US GAAP		Fiscal Year Ended November 30
	2010		2009	2008	2007	2006
Petroleum Revenue	371,265
Production Costs	$393,338
Net Petroleum Income (US$)	($22,073)
Net operating revenue	Nil		Nil	Nil	Nil	Nil
Loss from operations	($2,006,658)		($3,399,442)	($6,489,209)	($14,784,688)	($13,060,169)
Loss from continuing operations	($2,006,658)		($3,399,442)	($6,489,209)	($14,784,688)	($13,060,169)
Comprehensive loss for the year	($2,006,658)		($3,399,442)	($6,489,209)	($14,870,688)	($13,022,169)
Loss from operations per share	($0.094)		($0.159)	($0.30)	($0.71)	($0.68)
Loss from continuing operations per share	($0. 094)		($0.159)	($0.30)	($0.71)	($0.68)
Total assets	$13,605,905		$15,224,722	$17,880,351	$24,384,800	$30,798,020
Net assets	$11,539,485		$13,505,838	$16,107,618	$22,758,444	$30,332,098
Capital stock	$60,356,806		$60,316,791	$59,518,839	$59,680,456	$52,469,422
Number of shares	21,403,979		21,403,979	20,937,312	20,907,312	19,250,343
Dividends per common share	Nil		Nil	Nil	Nil	Nil
Diluted net (loss) per share	($0.09)		($0.16)	($0.30)	($0.71)	($0.68)

Canadian GAAP	Fiscal Year Ended November 30
	2010	2009	2008	2007	2006
Petroleum Revenue	$371,265
Production Costs	$393,338
Net Petroleum Income (Loss)	($22,073)
Gross operating revenue	371,265	Nil	Nil	Nil	Nil
Loss from operations	($2,006,658)	($3,364,852)	($6,489,209)	($7,916,250)	($11,630,209)
Loss from continuing operations	($2,006,658)	($3,364,852)	($6,489,209)	($7,916,250)	($11,630,209)
Comprehensive loss for the year	($2,006,658)	($3,364,852)	($6,489,209)	($7,916,250)	($11,630,209)
Loss from operations per share	($0.094)	($0.157)	($0.31)	($0.379)	($0.604)
Loss from continuing operations per share	($0.094)	($0.157)	($0.31)	($0.379)	($0.604)
Total assets	$13,605,905	$15,224,722	$17,880,351	$24,384,800	$30,798,020
Net assets	$11,539,485	$13,505,838	$16,107,618	$22,758,444	$30,332,098
Capital stock	$50,760,174	$50,719,869	$49,956,797	$50,118,414	$49,775,818
Number of shares	21,403,979	21,403,979	20,937,312	20,907,312	19,250,343
Dividends per share	Nil	Nil	Nil	Nil	Nil
Diluted net (loss) per share	($0.094)	($0.157)	($0.31)	($0.38)	($0.60)

NON-GAAP MEASURES

We disclose several financial measures in this Annual Information Form that do not have any standardized meaning prescribed by generally accepted accounting principles (referred to as “non-GAAP measures”) in the evaluation of operating and financial performance.  These financial measures include operating netback, corporate netback and net debt.   Operating netback, which is calculated as average unit sales prices less royalties and operating expenses, and corporate netback, which further deducts administrative and interest expense, represent net cash margin calculations for every barrel of oil equivalent sold.  Net debt, which is current assets less current and other financial liabilities (e.g. note payable), is used to assess efficiency and financial strength.  Our method of calculating these measures may differ from other companies and therefore may not be comparable with the calculation of a similar measure for other companies.  We use these terms as an indicator of financial performance because such terms are often utilized by investors to evaluate junior producers in the oil and natural gas sector.

CHANGES IN ACCOUNTING POLICIES

Revenue recognition of petroleum and natural gas properties

Effective July 1, 2010, we adopted the following accounting policy to account for our petroleum resource properties.  

Revenue from the production of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. We assess customer creditworthiness, both before entering into contracts and throughout the revenue recognition process.

Revenue as reported represents our share and is presented before royalty payments to governments and other mineral interest owners.

Related costs of goods sold are comprised of production; transportation and blending; and depletion, depreciation and amortization expenses. These amounts have been separately presented in the statements of loss, comprehensive loss and deficit.

Petroleum and natural gas properties

Effective July 1, 2010, we adopted the following accounting policy to account for our petroleum resource properties.  

We follow the full cost method of accounting for petroleum and natural gas operations whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized.  These costs include land acquisition costs, geological and geophysical expenses, the costs of drilling both productive and non-productive wells, directly related overhead and estimated abandonment costs.  Proceeds from the disposal of properties are deducted from the full cost pool without recognition of a gain or loss unless such a sale would significantly alter the rate of depletion and depreciation.

Depletion and depreciation of petroleum and natural gas properties

Effective July 1, 2010, we adopted the following accounting policy to account for our petroleum resource properties.

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes before royalties in relation to total estimated proved reserves as determined annually by independent engineers and determined in accordance with National Instrument 51-101.  Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion and depreciation of production equipment are based on total capitalized costs plus estimated future development costs of proved undeveloped reserved.  The costs of acquiring and evaluating unproved properties are excluded from depletion calculations.  These properties are assessed periodically to ascertain whether impairment has occurred.  When the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

Ceiling Test

Effective July 1, 2010, we adopted the following accounting policy to account for our petroleum resource properties.

We review the carrying amount of our petroleum and natural gas properties relative to their recoverable amount at each annual balance sheet date or more frequently if circumstances or events indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash flow from the properties using proved reserves and expected future prices and costs. If the carrying amount of the properties exceeds their recoverable amount, an impairment loss is recognized in depletion and depreciation expense equal to the amount by which the carrying amount of the properties exceeds their fair value. Fair value is calculated as the cash flow from those properties using proved and probable reserve and expected future prices and costs, discounted at a risk-free interest rate.

International Financial Reporting Standards (“IFRS”)

In January 2006, the Canadian Accounting Standards Board adopted a strategic plan, which includes the decision to move financial reporting for Canadian publicly accountable enterprises to a single set of globally accepted standards, IFRS, as issued by the International Accounting Standards Board. The effective implementation date of the conversion from Canadian generally accepted accounting principles (“Canadian GAAP”) to IFRS is December 1, 2011, with an effective transition date of December 1, 2010 for financial statements prepared on a comparative basis.  We are engaged in an assessment and conversion process which includes consultation with external consulting firms.  Our approach to the conversion to IFRS includes three phases.

·

Phase one, an initial general diagnostic of our accounting policies and Canadian GAAP relevant to our financial reporting requirements to determine the key differences and options with respect to acceptable accounting standards under IFRS. This phase was completed in late 2009.

·

Phase two, an in-depth analysis of the IFRS impact in those areas identified under phase one. During 2010, we substantially completed assessing and quantifying IFRS transition adjustments.  Our auditors are in the process of completing their review of these adjustments.  A summary of this analysis is provided in Table 2 below.

·

Phase three, the implementation of the conversion process, including the completion of the opening balance sheet as at December 1, 2010 together with related discussion and notes, has commenced.  Preliminary drafts of financial statement disclosures have been prepared in order to ensure systems are in place to collect the necessary data; to date no significant changes to current procedures have been identified.

Our IT accounting and financial reporting systems are not expected to be significantly impacted.

The above comments, including the summary in Table 2, should not be considered as a complete and final list of the changes that will result from the transition to IFRS as we intend to maintain a current and proactive approach based on changes in circumstances and no final determinations have been made. IFRS standards, and the interpretation thereof, are constantly evolving.  As a result, we expect there may be new or revised IFRS accounting standards prior to the issuance of our first IFRS financial statements. We are continuing to monitor IFRS accounting developments and updates and will assess their impact in the course of our transition process to IFRS.

Table 2.  Summary of financial statements impact on transition from Canadian GAAP to IFRS.

Key Area	Canadian GAAP (as currently applied)			IFRS				Analysis and preliminary conclusions
Property, plant and equipment (“PP&E”)	PP&E is recorded at historical cost. Depreciation is based on their useful lives after due estimation of their residual values.			PP&E can be recorded using the cost (on transition to IFRS, the then fair value can be deemed to be the cost) or revaluation models. Depreciation must be based on the useful lives of each significant component within PP&E.				PP&E will continue to be recorded at their historical costs due to the complexity and resources required to determine fair values on an annual basis. Based on an analysis of PP&E and our significant components, we have determined that no change to their useful lives is warranted and, therefore, depreciation expense will continue to be calculated using the same rates under IFRS.
Key Area	Canadian GAAP (as currently applied)		IFRS				Analysis and preliminary conclusions
Mineral properties	Exploration costs and option maintenance payments are expensed as incurred. If proven and probable reserves are established, costs incurred prospectively to develop the property are capitalized as incurred and depreciated using the unit-of-production depreciation method over the estimated life of the ore body.		IFRS 6 provides us with the option of expensing the exploration and evaluation costs as incurred, or deferring these costs until technical feasibility and commercial viability has been determined, at which point they are transferred to the development and production phase and allocated to specific projects.				The existing accounting policy will be maintained.
Asset retirement obligations (“ARO”)	Canadian GAAP limits the definition of ARO to legal obligations.   ARO is calculated using a current credit-adjusted, risk-free rate for upward adjustments, and the original credit-adjusted, risk-free rate for downward revisions.  The original liability is not adjusted for changes in current discount rates.		IFRS defines ARO as legal or constructive obligations. ARO is calculated using a current pre-tax discount rate (which reflects current market assessment of the time value of money and the risk specific to the liability) and is revised every reporting period to reflect changes in assumptions or discount rates. IFRS requires that, on transition, the net book value of the asset related to ARO be adjusted on the basis of the ARO balance existing at inception.				The broadening of this definition will not cause a significant change in our current estimates.   We expect to record a transition adjustment. In accordance with IFRIC 1, the effect of any changes to an existing ARO as a result of changes in market interest rates is added to or deducted from the cost of the related asset.   We will rely on the IFRS 1 exemption which allows a company to use current estimates of future reclamation costs and current amortization rates to determine the net book value on transition to IFRS.
Key Area		Canadian GAAP (as currently applied)			IFRS	Analysis and preliminary conclusions
Stock-based compensation		We recognize stock-based compensation on a straight line method and update the value of the options for forfeitures as they occur.   We included stock-based compensation in contributed surplus and previously recognized compensation cost is not reversed if a vested employee stock option expires unexercised.			Under IFRS, stock-based compensation is amortized under the graded method only.  In addition, we are required to update our value of options for each reporting period for expected forfeitures.   IFRS does not preclude us from recognizing a transfer of compensation costs within equity (i.e. from contributed surplus to deficit) after vesting.	We are in the process of quantifying the difference. We do not intend to transfer stock-based compensation expense included in contributed surplus to another component of equity.
Income taxes		There is no exemption from recognizing a deferred income tax for the initial recognition of an asset or liability in a transaction that is not a business combination.  The carrying amount of the asset or liability acquired is adjusted for the amount of the deferred income tax recognized. All deferred income tax assets are recognized to the extent that it is “more likely than not” that the deferred income tax assets will be realized.			A deferred income tax is not recognized if it arises from the initial recognition of an asset or liability in a transaction that is not a business combination, and at the time of the transaction affects neither accounting profit nor taxable profit. A deferred tax asset is recognized if it is “probable” that it will be realized.	We do not expect the difference in recognition of deferred income tax to have any significant change in the future. “Probable” in this context is not defined and does not necessarily mean “more likely than not”.  However, we do not expect this difference to have any impact in the future.

3

The above assessment and conclusions are based on the analysis completed by us as of the date of this report and may be subject to change.

The quantification of the amounts that resulted from the differences between Canadian GAAP and IFRS relating to the key standards are based on management’s estimates and decisions, and are subject to further internal review and audit by our external auditors.

Currency and Exchange Rates

Since June 1, 1970, the Government of Canada adopted a floating exchange rate to determine the value of the Canadian dollar as compared to the US dollar. On May 13, 2011, the exchange rate in effect for Canadian dollars exchanged for US dollars, expressed in terms of Canadian dollars was $1.0354. This exchange rate is based on the noon buying rates of the Bank of Canada, as obtained from the websitewww.bankofcanada.ca.

For the past five fiscal years ended November 30, 2010, and for the three month period between December 1, 2010, and April 30, 2011, the following exchange rates were in effect for Canadian dollars exchanged for US dollars, calculated in the same manner as above:

Period				Average
Year ended November 30, 2006		$		1.1350
Year ended November 30, 2007		$		1.0865
Year ended November 30, 2008		$		1.0469
Year ended November 30, 2009		$		1.1565
Year ended November 30, 2010		$		1.0345
	Period				Low		High
	Month ended December 31, 2010		$		0.9931	$	1.0216
	Month ended January 31, 2011		$		0.9848	$	1.0060
	Month ended February 28, 2011		$		0.9710	$	0.9984
	Month ended March 31, 2011		$		0.9713		0.9918
	Month ended April 30, 2011		$		0.9486	$	0.9691

B.

Capitalization and Indebtedness

Not Applicable.

C.

Reasons for the Offer and Use of Proceeds

Not Applicable.

D.

Risk Factors

An investment in our common shares is highly speculative and subject to a number of known and unknown risks.  Only those persons who can bear the risk of the entire loss of their investment should purchase our securities.  An investor should carefully consider the risks described below and the other information that we file with the SEC and with Canadian securities regulators before investing in our common shares.  The risks described below are not the only ones faced.  Additional risks that we are not currently aware of or that we currently believe are immaterial may become important factors that affect our business.  If any of these risks occur, operating results and financial conditions could be seriously harmed, the market price of our common shares could decline and the investor may lose all of their investment.  The risk factors set forth below and elsewhere in this Annual Report, and the risks discussed in our other filings with the SEC and Canadian securities regulators may have a significant impact on our business, operating results and financial condition and could cause actual results to differ materially from those projected in any forward-looking statements.  See “Cautionary Note Regarding Forward-Looking Statements”.

In addition to other information in this Annual Report, you should carefully consider the following risk factors in evaluating our business.

Risks Related to the Oil and Gas Business

Prices, Markets and Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by us is and will continue to be affected by numerous factors beyond our control.  Our ability to market our oil and natural gas may depend upon our ability to acquire space on pipelines that deliver natural gas to commercial markets.  We may also be affected by deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

The prices of oil and natural gas prices may be volatile and subject to fluctuation.  Any material decline in prices could result in a reduction of our net production revenue.  The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or gas and a reduction in the volumes of our reserves.  We might also elect not to produce from certain wells at lower prices.  All of these factors could result in a material decrease in our expected net production revenue and a reduction in our oil and gas acquisition, development and exploration activities.  Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control.  These factors include economic conditions, in the United States and Canada, the actions of OPEC, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources.  Any substantial and extended decline in the price of oil and gas would have an adverse effect on our carrying value of our reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on our business, financial condition, results of operations and prospects.

Petroleum prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies, OPEC actions and the ongoing credit and liquidity concerns.  Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value.  Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

In addition, bank borrowings available to us may, in part, be determined by our borrowing base.  A sustained material decline in prices from historical average prices could reduce our borrowing base, therefore reducing the bank credit available to us which could require that a portion, or all, of our bank debt be repaid.

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  The long-term commercial success of us depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves.  Without the continual addition of new reserves, any existing reserves we may have at any particular time, and the production therefrom will decline over time as such existing reserves are exploited.  A future increase in our reserves will depend not only on our ability to explore and develop any properties it may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects.  No assurance can be given that we will be able to continue to locate satisfactory properties for acquisition or participation.  Moreover, if such acquisitions or participations are identified, management of we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.  There is no assurance that further commercial quantities of oil and natural gas will be discovered or acquired by us.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs.  Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.  In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells.  These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.  While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury.  In particular, we may explore for and produce sour natural gas in certain areas.  An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property and may necessitate an evacuation of populated areas, all of which could result in liability to us.  In accordance with industry practice, we are not fully insured against all of these risks, nor are all such risks insurable.  Although we maintain liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs.  Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations.  Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects.

Substantial Capital Requirements

We anticipate making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future.  If our revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs.  In addition, uncertain levels of near term industry activity coupled with the present global credit crisis exposes us to additional access to capital risk.  There can be no assurance that debt or equity financing, or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to us.  Our inability to access sufficient capital for our operations could have a material adverse effect on our business financial condition, results of operations and prospects.

Additional Funding Requirements

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times.  From time to time, we may require additional financing in order to carry out our oil and gas acquisition, exploration and development activities.  Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations.  If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our production.  If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on terms acceptable to us.  Continued uncertainty in domestic and international credit markets could materially affect our ability to access sufficient capital for our capital expenditures and acquisitions, and as a result, may have a material adverse effect on our ability to execute our business strategy and on our business, financial condition, results of operations and prospects.

Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGLs reserves and the future cash flows attributed to such reserves.  The reserve and associated cash flow information set forth herein are estimates only.  In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.  For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary.  Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history.  Recovery factors and drainage areas were estimated by experience and analogy to similar producing pools.  Estimates based on these methods are generally less reliable than those based on actual production history.  Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, our independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flows as summarized herein.  Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and cash flows derived from our oil and gas reserves will vary from the estimates contained in the reserve evaluation, and such variations could be material.  The reserve evaluation is based in part on the assumed success of activities us intends to undertake in future years.  The reserves and estimated cash flows to be derived therefrom contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation.  The reserve evaluation is effective as of a specific effective date and has not been updated and thus does not reflect changes in our reserves since that date.

The Corporation incorporates additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States.  The Corporation follows the Canadian practice of reporting gross production and reserve volumes; however, it also follows the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments).  The Corporation also follows the Canadian practice of using forecast prices and costs when it estimates its reserves.  However, the Corporation separately estimates its reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements.  These latter requirements are similar to the average constant pricing reserve methodology utilized in the United States.

The Corporation has included estimates of proved and proved plus probable reserves, as well as contingent resources in filings made with it by United States oil and gas companies.  However, the SEC has adopted revisions to its oil and gas reporting rules that, effective as of January 1, 2010, among other things, modified the standards to establish proved reserves and permit disclosure of probably and possible reserves under certain circumstances.  However, it is likely that significant differences will remain between the reserve categories and reserve reporting generally under Canadian and U.S. securities laws and rules.

Project Risks

We manage a variety of projects in the conduct of our oil and gas business.  Project delays may delay expected revenues from operations.  Significant project cost over-runs could make a project uneconomic.  Our ability to execute projects and market oil and natural gas depends upon numerous factors beyond our control, including:

• the availability of processing capacity;

• the availability and proximity of pipeline capacity;

• the availability of storage capacity;

• the supply of and demand for oil and natural gas;

• the availability of alternative fuel sources;

• the effects of inclement weather;

• the availability of drilling and related equipment;

• unexpected cost increases;

• accidental events;

• currency fluctuations;

• changes in regulations;

• the availability and productivity of skilled labour; and

• the regulation of the oil and natural gas industry by various levels of government and governmental agencies.

Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.

Hedging

From time to time we may enter into agreements to receive fixed prices on our oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, we will not benefit from such increases and we may nevertheless be obligated to pay royalties on such higher prices, even though not received by us, after giving effect to such agreements.  Similarly, from time to time we may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, we will not benefit from the fluctuating exchange rate.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted.  Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities.

Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time.  See "Industry Conditions".  Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas.  Such regulations may be changed from time to time in response to economic or political conditions.  The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for natural gas and crude oil and increase our costs, any of which may have a material adverse effect on our business, financial condition, results of operations and prospects.  In order to conduct oil and gas operations, we will require licenses from various governmental authorities.  There can be no assurance that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may wish to undertake.

Geo-Political Risks

The marketability and price of oil and natural gas that may be acquired or discovered by us is and will continue to be affected by political events throughout the world that cause disruptions in the supply of oil.  Conflicts, or conversely peaceful developments, arising in the Middle-East, and other areas of the world, have a significant impact on the price of oil and natural gas.  Any particular event could result in a material decline in prices and therefore result in a reduction of our net production revenue.

In addition, our oil and natural gas properties, wells and facilities could be subject to a terrorist attack.  If any of our properties, wells or facilities are the subject of terrorist attack it may have a material adverse effect on our business, financial condition, results of operations and prospects.  We will not have insurance to protect against the risk from terrorism.

Climate Change

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called "greenhouse gases".  Recently, representatives from approximately 170 countries met in Copenhagen, Denmark to attempt to negotiate a successor to the Kyoto Protocol.  Pursuant to the resulting Copenhagen Accord, a non-binding political consensus rather than a binding international treaty such as the Kyoto Protocol, the Government of Canada revised our emissions reduction targets slightly.  There has been much public debate with respect to Canada's ability to meet these targets and the Government's strategy or alternative strategies with respect to climate change and the control of greenhouse gases.  Our exploration and production facilities and other operations and activities emit greenhouse gases and require us to comply with Alberta's greenhouse gas emissions legislation contained in the Climate Change and Emissions Management Amendment Act and the Specified Gas Emitters Regulation.  We may also be required comply with the regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which is now expected to be modified to ensure consistency with the regulatory scheme for greenhouse gas emissions adopted by the United States.  The direct or indirect costs of these regulations may have a material adverse effect on our business, financial condition, results of operations and prospects.  The future implementation or modification of greenhouse gases regulations, whether to meet the limits required by the Kyoto Protocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including ours.  Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on us, our operations and financial condition.  See "Industry Conditions - Climate Change Regulation".

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations.  Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  Compliance with such legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.  The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge.  Although we believe that we will be in material compliance with current applicable environmental regulations, no assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects.

Competition

The petroleum industry is competitive in all its phases.  We compete with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas.  Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than we do.  Our ability to increase our reserves in the future will depend not only on our ability to explore and develop our present properties, but also on our ability to select and acquire other suitable producing properties or prospects for exploratory drilling.  Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.  Competition may also be presented by alternate fuel sources.

Insurance

Our involvement in the exploration for and development of oil and natural gas properties may result in our becoming subject to liability for pollution, blow outs, leaks of sour natural gas, property damage, personal injury or other hazards.  Although we maintain insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities.  In addition, such risks are not, in all circumstances, insurable or, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons.  The payment of any uninsured liabilities would reduce the funds available to us.  The occurrence of a significant event that we are not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on our business, financial condition, results of operations and prospects.

Third Party Credit Risk

We may be exposed to third party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production and other parties.  In the event such entities fail to meet their contractual obligations to us, such failures may have a material adverse effect on our business, financial condition, results of operations and prospects.  In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of such program until we find a suitable alternative partner.

Title to Assets

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, such reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim which may have a material adverse effect on our business, financial condition, results of operations and prospects.

Seasonality

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns.  Wet weather and spring thaw may make the ground unstable.  Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels.  Also, certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain.  Seasonal factors and unexpected weather patterns may lead to delays in our exploration and production activity which may in turn adversely affect our operations.

Expiration of Licences and Leases

Our properties are held in the form of licences and leases and working interests in licences and leases.  If we or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire.  There can be no assurance that any of the obligations required to maintain each licence or lease will be met.  The termination or expiration of our licences or leases or the working interests relating to a licence or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

We make acquisitions and dispositions of businesses and assets in the ordinary course of business.  Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as our ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with ours.  The integration of acquired business may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters.  Management continually assesses the value and contribution of services provided and assets required to provide such services.  In this regard, non-core assets are periodically disposed of, so that we can focus our efforts and resources more efficiently.  Depending on the state of the market for such non-core assets, certain of our non-core assets, if disposed of, could be expected to realize less than their carrying value on our financial statements.

Operational Dependence

Other companies operate some of the assets in which we have an interest.  As a result, we have limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect our financial performance.  Our return on assets operated by others therefore depends upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

Risks Related to the Mineral Exploration Business

We have no production history from our mineral properties.

We have no history of producing metals from any of our properties as each of our properties are in the exploration stage.  Advancing properties from exploration into the development stage requires significant capital and time, and successful commercial production from a property, if any, will be subject to completing positive feasibility studies, permitting and construction of the mine, processing plants and roads and other related works and infrastructure.  As a result, we are subject to all the risks associated with developing and establishing new mining operations and business enterprises including:

·

Completion of feasibility studies to define reserves and commercial viability, including the ability to find sufficient mineral reserves to support a commercial mining operation;

·

The timing and cost, which can be considerable, of further exploration, preparing feasibility studies, permitting and construction of infrastructure, mining and processing facilities;

·

The availability and costs of drill equipment, qualified exploration personnel, skilled and reliable labour and mining and processing equipment, if required;

·

The availability and cost of appropriate smelting and/or refining arrangements, if required;

·

Compliance with environmental and other governmental approval and permit requirements;

·

The availability of funds to finance exploration, development and construction activities, as warranted;

·

Potential opposition from non-governmental organizations, environmental groups, local groups or local inhabitants which may delay or prevent development activities; and

·

Potential increases in exploration, construction and operating costs due to changes in the cost of fuel, power, materials and supplies.

The costs, timing and complexities of exploration, development and construction activities may be increased by the location of our properties and demand by other mineral exploration and mining companies.  It is common in exploration programs to experience unexpected problems and delays during drill programs and, if warranted, development, construction and mine start-up.  Accordingly, our activities may not result in profitable mining operations and we may not succeed in establishing mining operations or profitability producing metals at any of our properties.

The business of mineral exploration is highly competitive and there is no assurance we can compete with other competitors for financing, qualified personnel and other resources related to the operation of our business.

Significant competition exists for the limited number of property acquisition opportunities available.  As a result of this competition, some of which is with large, established mining companies with substantial capabilities and greater financial and technical resources than us, we may be unable to acquire attractive mining properties on terms we consider acceptable.  Competition in the precious metals mining industry is primarily for mineral rich properties which can be developed and exploited economically; the technical expertise to find, develop, and produce such properties; the labour to operate the properties; and the capital for the purpose of funding such properties.  Many competitors not only explore for and mine precious metals and minerals but conduct refining and marketing operations on a worldwide basis.  Such competition may result in our being unable to acquire desired properties, to recruit or retain qualified employees, to obtain necessary exploration, development or production equipment or to acquire the capital necessary to fund our operations and develop our properties.  Our inability to compete with other mining companies for these resources may have a material adverse effect on our results of operation and business.  There can be no assurance that our exploration and acquisition programs will yield any reserves or result in any commercial mining operation.

Increased costs could affect our financial condition.

We anticipate that costs at our projects that we may explore or develop, will frequently be subject to variation from one year to the next due to a number of factors, such as changing ore grade, metallurgy and revisions to mine plans, if any, in response to the physical shape and location of the ore body.  In addition, costs are affected by the price of commodities such as fuel, rubber and electricity.  Such commodities are at times subject to volatile price movements, including increases that could make production at certain operations less profitable. A material increase in costs at any significant location could have a significant effect on our profitability.

A shortage of equipment and supplies could adversely affect our ability to operate our business.

We are dependent on various supplies and equipment to carry out our mining exploration and, if warranted, development operations. The shortage of such supplies, equipment and parts could have a material adverse effect on our ability to carry out our operations and therefore limit or increase the cost of production.

Our operations are subject to the inherent risk associated with mineral exploration activities.

Mineral exploration activities and, if warranted, development activities generally involve a high degree of risk, which even a combination of experience, knowledge and careful evaluation may not be able to overcome.  Environmental hazards, industrial accidents, unusual or unexpected geological formations, fires, power outages, labour disruptions, flooding, explosions, cave-ins, land-slides and the inability to obtain suitable or adequate machinery, equipment or labour are other risks involved in the operation of mines and the conduct of exploration programs.  Operations and activities in which we have a direct or indirect interest will be subject to all the hazards and risks normally incidental to exploration, development and production of precious and base metals, any of which could result in work stoppages, damage to or destruction of mines, if any, and other producing facilities, damage to life and property, environmental damage and possible legal liability for any or all damage.  We plan to obtain insurance, in amounts that we consider to be adequate, to protect ourselves against certain of these mining risks once we commence mining operations.  However, we may become subject to liability for certain hazards which we cannot insure against or which we may elect not to insure against because of premium costs or other reasons.  The payment of such liabilities may have a material, adverse effect on our financial position.  At the present time, we do not conduct any mining operations and none of our properties are under development, and, therefore, we do not carry insurance to protect us against certain inherent risks associated with mining.  Reclamation requirements vary depending on the location and the managing regulatory agency, but they are similar in that they aim to minimize long term effects of exploration and mining disturbance by requiring the operating company to control possible deleterious effluents and to re-establish to some degree pre-disturbance landforms and vegetation.

Mineral exploration involves a high degree of risk against which we are not currently insured.

Our exploration activities are subject to the hazards and risks normally incident to the exploration for and development and production of precious minerals, any of which could result in damage for which we may be held responsible. Hazards such as unusual or unexpected weather, rock formations, formation pressures, fires, power outages, landslides, flooding cave-ins or other adverse conditions such as the inability to obtain suitable or adequate machinery, equipment or labour may be encountered in the drilling and removal of material.  While Alberta Star may obtain insurance against certain risks in such amounts as we consider adequate, the nature of these risks is such that liabilities could exceed policy limits or could be excluded from coverage.  There are also risks against which we cannot insure or against which we may decide not to insure.  

It is not always possible to fully insure against such risks and we may decide to forego insuring against such risks as a result of high premiums or other reasons. Should such liabilities arise, they could reduce or eliminate any future profitability and result in increasing costs and a decline in the value of our common shares. We do not currently maintain insurance against environmental risks relating to our mineral property interests, though we have obtained third party liability insurance, to counter the effects of these risks.

All of our properties are in the exploration stage and are highly speculative in nature, which means there can be no assurance that our programs will result in the discovery of any economically feasible mineral deposit.

At present, none of our properties have a known body of ore and all our proposed exploration programs are an exploratory search for ore.  We will only develop our mineral properties if we obtain satisfactory results from our exploration programs.   The development of uranium, cobalt, gold, silver, copper, zinc and other mineral properties is affected by many factors, including the cost of operations, variations in the grade of ore mined, fluctuations in metal markets, costs of processing equipment and other factors such as government regulations, including regulations relating to royalties, allowable production, importing and exporting of minerals and environmental protection.  We have relied and may continue to rely upon consultants and others for exploration expertise.  Substantial expenditures are required to establish reserves through drilling, to develop metallurgical processes to extract the metal from the ore and, in the case of new properties, to develop the mining and processing facilities and infrastructure at any site chosen for mining.  We cannot assure you that any mineral deposits will be discovered in sufficient quantities to justify commercial operations or that funds required for development can be obtained on a timely basis.  Depending on the price of uranium or other minerals produced, if any, we may determine that it is impractical to commence or, if commenced, continue commercial production.

The marketability of any minerals acquired or discovered may be affected by numerous factors which are beyond our control and which cannot be accurately predicted, such as market fluctuations, the global marketing conditions for uranium and other metals, the proximity and capacity of milling facilities, mineral markets and processing equipment, and such other factors as government regulations, including regulations relating to royalties, allowable production, importing and exporting minerals and environmental protection.  Our properties are located in the Northwest Territories, Canada.  This jurisdiction imposes certain requirements and obligations on the owners of exploratory properties which includes, among other things, certain application and permit requirements, certain limitations on mining and exploration activities, periodic reporting requirements, limited terms and certain fees and royalty payments.  

Very few mineral properties are ultimately developed into producing mines.

The business of exploration for minerals and mining involves a high degree of risk such as unusual or unexpected geological formations and the inability to obtain suitable or adequate machinery, equipment or labour and is highly speculative in nature. Few properties that are explored are ultimately developed into commercially viable mining operations. At present, our existing properties have no known significant body of commercial ore. Most exploration projects do not result in the discovery of commercially mineable deposits of ore. The occurrence of unsuccessful exploration efforts may eventually lead to us needing to cease operations.

The success of commodity exploration is determined in part by the following factors:

·

Identification of potential mineralization based on superficial analysis;

·

Exploration permits, as granted by the various government bodies;

·

Experience and quality of management and geological consultants; and

·

Capital available for exploration activity.

Substantial expenditures are required for us to establish proven and probable ore reserves through drilling and analysis, to develop metallurgical processes, to extract the metal from the ore and, in the case of new properties, to develop the mining and processing facilities and infrastructure at any site chosen for mining.  In making the determination as to the commercial viability of a mineral deposit, a number of factors are considered, which include, without limitation, the particular attributes of the deposit, such as size, grade, and proximity to infrastructure; metal prices, which fluctuate widely; and government regulations, including, without limitation, regulations relating to prices, taxes, royalties, land tenure, and use importing and exporting or minerals and environmental protection.  

Although substantial benefits may be derived from the discovery of a major mineral deposit, no assurance can be given that we will discover minerals in sufficient quantities to justify commercial operations or that we can obtain the funds required for development on a timely basis.

We may invest significant capital and resources in exploration activities and abandon such investments if we are unable to identify commercially exploitable mineral reserves.  The decision to abandon a project may have an adverse effect on the market value of our securities and the ability to raise future financing.

We have no producing mines at this time.

Calculations of mineral reserves and of mineralized material are estimates only, subject to uncertainty due to factors including metal prices, inherent variability of the ore, and recoverability of metal in the mining process.

There is a degree of uncertainty attributable to the calculation of reserves and corresponding grades dedicated to future production. Until mineral reserves are actually mined and processed, the quantity of ore and grades must be considered as an estimate only. In addition, the quantity of mineral reserves and ore may vary depending on metal prices. Estimates of mineral resources under Canadian guidelines are subject to uncertainty as well. The estimating of mineral reserves and mineral resources under Canadian guidelines is a subjective process and the accuracy of such estimates is a function of the quantity and quality of available data and the assumptions used and judgments made in interpreting engineering and geological information. There is significant uncertainty in any reserve or estimate of mineral resources under Canadian guidelines, and the actual deposits encountered and the economic viability of mining a deposit may differ materially from our estimates. Estimated mineral reserves or mineral resources under Canadian guidelines may have to be recalculated based on changes in metal prices, further exploration or development activity or actual production experience. This could materially and adversely affect estimates of the volume or grade of mineralization, estimated recovery rates or other important factors that influence estimates of mineral reserves or mineral resources under Canadian guidelines. Any material change in the quantity of mineral reserves, mineralization, grade or stripping ratio may affect the economic viability of our properties. In addition, there can be no assurance that metal recoveries in small-scale laboratory tests will be duplicated in larger scale tests under on-site conditions or during production.

Differences in U.S. and Canadian reporting of reserves and resources

Our reserve and resource estimates are not directly comparable to those made in filings subject to SEC reporting and disclosure requirements, as we generally reports reserves and resources in accordance with Canadian practices. These practices are different from those used to report reserve and resource estimates in reports and other materials filed with the SEC.  It is Canadian practice to report measured, indicated and inferred resources, which are not permitted in disclosure filed with the SEC by United States issuers. In the United States, mineralization may not be classified as a "reserve" unless the determination has been made that the mineralization could be economically and legally produced or extracted at the time the reserve determination is made.  United States investors are cautioned not to assume that all or any part of measured or indicated resources will ever be converted into reserves.

Further, "inferred resources" have a great amount of uncertainty as to their existence and as to whether they can be mined legally or economically. Disclosure of "contained ounces" is permitted disclosure under Canadian regulations; however, the SEC permits issuers to report "resources" only as in-place tonnage and grade without reference to unit of metal measures.

Accordingly, information concerning descriptions of mineralization, reserves and resources contained in this Annual Report, or in the documents incorporated herein by reference, may not be comparable to information made public by United States companies subject to the reporting and disclosure requirements of the SEC.

Our management has only limited experience in resource exploration and our business has a higher risk of failure.

Our management, while experienced in business operations, has only limited experience in resource exploration.  During the 2008 fiscal year, we retained, on a consulting basis, the full-time services of a qualified geologist, Dr. Michael Bersch to act as our Chief Geologist for a period of 2 years.  While we try to hire and retain management with proper expertise, none of our directors or officers have any significant technical training or experience in resource exploration or mining despite their diverse business backgrounds.  Management may not be fully aware of the specific requirements related to working in mineral exploration, whether technical or operational.  Therefore, our managerial decisions and choices may not always reflect standard engineering or mineral exploration practices commonly used. We rely on the opinions of consulting geologists and mining experts that we retain from time to time for specific exploration projects or property reviews.

We cannot be certain that the measures we take will ensure that we implement and maintain adequate financial resources or profitability. Management’s lack of experience may cause failure to implement appropriate financial decisions, or cause difficulties in implementing proper decisions, ultimately harming our operating results.

The prices of precious metal and base metal fluctuate and directly impact on our business activities.

Our business activities are significantly affected by the prices of uranium, precious metals and base metals on international markets.  The price of minerals affects our ability to raise financing, the commercial feasibility of our properties, the future profitability of our properties should they be developed and our future business prospects. The prices of uranium, precious metals and base metals fluctuate widely and are affected by numerous factors beyond our control, including expectations with respect to the rate of inflation, the strength of the U.S. dollar and of other currencies, interest rates, and global or regional political or economic crisis.  

Our business is affected by market fluctuations in the prices of the minerals sought, which are highly volatile.  Depending on the price of such minerals, we may determine that it is impractical to continue our exploration activities or, if warranted, to commence commercial development or production of our properties, if a mineral deposit is identified.

Uranium, precious metals and base metals prices may fluctuate widely and are affected by numerous industry factors, such as demand for precious metals, forward selling by producers, central bank sales and purchases of gold and production and cost levels in major mineral-producing regions.  Moreover, mineral prices are also affected by macro-economic factors that are beyond our control, including international economic and political trends, expectations of inflation, currency exchange fluctuations (specifically, the Canadian dollar relative to other currencies), interest rates and global or regional consumption patterns, speculative activities and increased production due to improved mining and production methods.  We cannot assure you that the price of such minerals will remain stable or that such prices will be at a level that will prove feasible to continue our exploration activities, or, if applicable, begin development of our properties.

The current demand for and supply of uranium, precious metals and base metals affects their respective prices, but not necessarily in the same manner as current demand and supply affect the prices of other commodities.  If prices of such minerals should decline for a sustained period, we could determine that it is not economically feasible to continue our exploration activities and such decision will have a material adverse affect on our business and results of operations.

There may be defects in the title to our properties.

In accordance with mining industry practice, we attempt to acquire satisfactory title to our properties but have not obtained title insurance with the attendant risk that some titles, particularly titles to undeveloped properties, may be defective.  In accordance with mining industry practice, we have not obtained title insurance on the mineral claims held by us.  We carry out all normal procedures to obtain title and make a conscientious search of mining records to confirm that we have satisfactory title to the properties we have acquired by staking, purchase or option, and/or that satisfactory title is held by the optionor/owner of properties we may acquire pursuant to an option agreement, and/or that satisfactory title is held by the owner of properties in which we have earned a percentage interest in the property pursuant to a joint venture or other type of agreement.  However, the possibility exists that title to one or more of the claims held by us, or an optionor/owner, or the owner of properties in which we have earned a percentage interest, might be defective for various reasons.  We will take all reasonable steps to perfect title to any particular claims found to be in question or deficient.

There is no assurance of the title to or boundaries of our resource properties.

Our mineral property interests may be subject to prior unregistered agreements of transfers or native land claims and title may be affected by undetected defects. We have not conducted surveys on the property and there is a risk that the boundaries could be challenged.

Our operations may be adversely affected by government and environmental regulations.

Each phase of our operations are subject to government and environmental regulations promulgated by government agencies from time to time.  Environmental legislation provides for restrictions and prohibitions on spills, release or emissions of various substances produced in association with certain mining industry operations, such as seepage from tailings disposal areas, which would result in environmental pollution. A breach of such legislation may result in the imposition of fines and penalties. In addition, certain types of operations require the submission and approval of environmental impact assessments.

Environmental legislation is evolving in a manner which means that standards, enforcements, fines and penalties for non-compliance are more stringent. Environmental assessments of proposed projects carry a heightened degree of responsibility for us and our directors, officers and consultants. The cost of compliance with changes in governmental regulations has a potential to reduce the profitability of our operations. We do not maintain environmental liability insurance.

Our activities are subject to extensive regulations governing various matters, including management and use of toxic substances and explosives, management of natural resources, exploration, development of mines, production and post-closure reclamation, exports, price controls, taxation, regulations concerning business dealings with indigenous peoples, labour standards on occupational health and safety, including mine safety, and historic and cultural preservation.

Failure to comply with applicable laws and regulations may result in civil or criminal fines or penalties, enforcement actions thereunder, including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment, or remedial actions, any of which could result in our incurring significant expenditures.  We may also be required to compensate those suffering loss or damage by reason of a breach of such laws, regulations or permitting requirements.  It is also possible that future laws and regulations, or more stringent enforcement of current laws and regulations by governmental authorities, could cause additional expense, capital expenditures, restrictions on or suspension of our operations and delays in the exploration and development of our mineral properties.

We may require permits and licenses that we may not be able to obtain.

Our operations may require licenses and permits from various governmental authorities. There can be no assurance that we will be able to obtain all of the necessary licenses and permits that may be required to conduct exploration, development and mining operations at our projects on certain properties in the Northwest Territories.

General Risks Related to the Business of Alberta Star

Aboriginal Claims

Aboriginal peoples have claimed aboriginal title and rights to portions of Canada.  We are not aware that any claims have been made in respect of our properties and assets; however, if a claim arose and was successful such claim may have a material adverse effect on our business, financial condition, results of operations and prospects.

Likely Passive Foreign Investor Company (“PFIC”) Status Has Possible Adverse Tax Consequences for U.S. Investors

Current holders of and potentialinvestors in our common shares who are U.S. taxpayers should be aware that Alberta Star does not expect to be a passive foreign investment company (“PFIC”) for the current fiscal year, although it may have been a PFIC in prior years .   If we are a PFIC for any year during a U.S. taxpayer’s holding period, then such U.S. taxpayers generally will be required to treat any so-called “excess distribution” received on our common shares, or any gain realized upon a disposition of common shares, as ordinary income and to pay an interest charge on a portion of such distributions or gain, unless the taxpayer makes a qualified electing fund (“QEF”) election or a mark-to-market election with respect to the shares of Alberta Star.  In certain circumstances, the sum of the tax and the interest charge may exceed the amount of the excess distribution received, or the amount of proceeds of disposition realized, by the taxpayer.  A U.S. taxpayer who makesa QEF election generally must report on a current basis its share of Alberta Star’s net capital gain and ordinary earnings for any year in which Alberta Star is a PFIC, whether or not we distribute any amounts to its shareholders.  A U.S. taxpayer who makes the mark-to-market election generally must include as ordinary income each year the excess of the fair market value of the common shares over the taxpayer’s basis therein.  U.S. taxpayers are advised to seek the counsel of their professional tax advisors.  This paragraph is qualified in its entirety by the discussion below under the heading “Taxation—Certain U.S. Federal Income Tax Considerations.”  Each U.S. taxpayer should consult his or her own tax advisor regarding the U.S. federal, U.S. state and local, and foreign tax consequences of the PFIC rules and the acquisition, ownership, and disposition of our common shares.

We have a history of losses.

We have incurred losses in our business operations since inception, and we expect that we will continue to lose money for the foreseeable future.  Since our incorporation on September 6, 1996, to November 30, 2010, we incurred losses determined under US GAAP totalling $48,817,321. Failure to achieve and maintain profitability may adversely affect the market price of our common stock.   There can be no assurance that we will achieve profitability in the future or at all.

We have not identified any commercially viable mineral deposits.  We have not commenced development or commercial production on any of our properties.  We have no history or earnings or cash flow from operations.  We do not have a line of credit and our only present source of funds available may be through the sale of our equity shares or assets.  Even if the results of exploration are encouraging, we may not have the ability to raise sufficient funds to conduct further explorations to determine whether a commercially mineable deposit exists on any of our properties.  While additional working capital may be generated through the issuance of equity or debt, the sale of properties or possible joint venturing of the properties, we cannot assure you that any such funds will be available for operations on acceptable terms, if at all.

In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those contained in our financial statements.

We generally have limited financial resources and no source of cash flow.

Although we believe we have sufficient funds to meet our current obligations, we currently have no external sources of liquidity, and all additional funding required for our activities for the foreseeable future will be obtained from the sale of our securities.  Should we elect to satisfy our cash commitments through the issuance of securities, by way of either private placement or public offering, there can be no assurance that our efforts to raise such funding will be successful, or achieved on terms favourable to us or our shareholders.  Such financings, to the extent they are available may result in substantial dilution to our existing shareholders.

Failure to obtain additional financing on a timely basis could cause us to forfeit all or a portion of our interests in the assets or rights now held by us and our ability to continue as a going concern ..   As described in Note 1 to our financial statements, our financial statements have been prepared on the assumption that we will continue as a going concern, meaning that we will continue in operation for the foreseeable future, and will be able to realize assets and discharge our liabilities in the ordinary course of operations.  There can be no assurance that we will be able to continue as a going concern.

If we do not obtain additional financing, our business will fail.

Our current operating funds are less than necessary to complete exploration of our mineral claims, and therefore we will need to obtain additional financing in order to complete our business plan.  As of November 30, 2010, we had approximately $9,456,219 in cash on hand.  Cash on hand at the date of filing this Annual Report is approximately $8,000,000.

Our business plan calls for significant expenses in connection with the exploration of our mineral claims. We will require additional financing in order to complete these activities. In addition, we will require additional financing to sustain our business operations if we are not successful in earning revenues once exploration is complete. We do not currently have any arrangements for financing and we can provide no assurance to investors that we will be able to find such financing if required.

The loss of key management personnel may adversely affect our business and results of operations.

The success of our operations and activities is dependent to a significant extent on the efforts and abilities of our management team, particularly our CEO, Tim Coupland.  Investors must be willing to rely to a significant extent on their discretion and judgment.  While we do maintain key-man employee insurance on Mr. Coupland to the extent reasonably available on normal commercial terms, the amount of coverage may not be adequate to compensate us for the full financial loss should we lose his services.

Certain directors may be in a position of conflicts of interest.

Certain members of our board also serve as directors of other companies involved in natural resource exploration and development. Consequently, there exists the possibility that those directors may be in a position of conflict. Any decision made by those directors will be made in accordance with their duties and obligations to deal fairly and in good faith of our company and such other companies. In addition, such directors will declare, and refrain from voting on, any matter in which such directors may have a conflict of interest.

We are a foreign corporation and most of our directors and officers are outside of the United States, which may make enforcement of civil liabilities difficult.

We are incorporated under the laws of the Province of Alberta, Canada.  All of our directors and officers are residents of Canada, and all of our assets are located outside of the United States.  Consequently, it may be difficult for United States investors to effect service of process within the United States upon those directors or officers who are not residents of the United States, or to realize in the United States upon judgments of United States courts predicated upon civil liabilities under the United States Securities Exchange Act of 1934, as amended.  A judgment of a US court predicated solely upon such civil liabilities would probably be enforceable in Canada by a Canadian court if the US court in which the judgment was obtained had jurisdiction, as determined by the Canadian court, in the matter.  There is substantial doubt whether an original action could be brought successfully in Canada against any of such persons or us predicated solely upon such civil liabilities.

As a foreign private issuer, our shareholders may have less complete and timely data.

The Company is a “foreign private issuer” as defined in Rule 3b-4 under the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Equity securities of the Company are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act pursuant to Rule 3a12-3 of the Exchange Act.  Therefore, the Company is not required to file a Schedule 14A proxy statement in relation to the annual meeting of shareholders.  The submission of proxy and annual meeting of shareholder information on Form 6-K may result in shareholders having less complete and timely information in connection with shareholder actions. The exemption from Section 16 rules regarding reports of beneficial ownership and purchases and sales of common shares by insiders and restrictions on insider trading in our securities may result in shareholders having less data and there being fewer restrictions on insiders’ activities in our securities.

Recent market events and conditions

Throughout 2009, the U.S. credit markets experienced serious disruption due to a deterioration in residential property values, defaults and delinquencies in the residential mortgage market (particularly, sub-prime and non-prime mortgages) and a decline in the credit quality of mortgage backed securities. Theseproblems led to a slow-down in residential housing market transactions, declining housing prices, delinquencies in non-mortgage consumer credit and a general decline in consumer confidence. These conditions continued and worsened in early 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions. Notwithstanding various actions by the U.S. and foreign governments, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially in early 2009. In addition, general economic indicators have deteriorated, including declining consumer sentiment, increased unemployment and declining economic growth and uncertainty about corporate earnings.

These unprecedented disruptions in the current credit and financial markets have had a significant material adverse impact on a number of financial institutions globally and have limited access to capital and credit for many companies. These disruptions could, among other things, make it more difficult to obtain, or increase the cost of obtaining, capital and financing for the operations.  Our access to additional capital may not be available on terms acceptable to us or at all.

General economic conditions

The recent unprecedented events in global financial markets have had a profound impact on the global economy. Many industries, including the mining industry, are impacted by these market conditions. Some of the key impacts of the current financial market turmoil include contraction in credit markets resulting in a widening of credit risk, devaluations and high volatility in global equity, commodity, foreign exchange and precious metal markets, and a lack of market liquidity. A continued or worsened slowdown in the financial markets or other economic conditions, including but not limited to, consumer spending, employment rates, business conditions, inflation, fuel and energy costs, consumer debt levels, lack of available credit, the state of the financial markets, interest rates, and tax rates may adversely affect our growth and profitability.  Specifically:

·

The global credit/liquidity crisis could impact the cost and availability of financing and our overall liquidity;

·

the volatility prices of base and precious metals may impact our potential revenues, profits and cash flow;

·

volatile energy prices, commodity and consumables prices and currency exchange rates may impact potential production costs; and

·

the devaluation and volatility of global stock markets may impact the valuation of our equity securities.

These factors could have a material adverse effect on our financial condition and results of operations.

Issuance of Debt

From time to time we may enter into transactions to acquire assets or the shares of other organizations.  These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size.  Depending on future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms.  Neither our articles nor our by-laws limit the amount of indebtedness that we may incur.  The level of our indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

Management of Growth

We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls.  Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to expand, train and manage our employee base.  Our inability to deal with this growth may have a material adverse effect on our business, financial condition, results of operations and prospects.

Variations in Foreign Exchange Rates and Interest Rates

World oil and gas prices are quoted in United States dollars and the price received by Canadian producers is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time.  In recent years, the Canadian dollar has increased materially in value against the United States dollar.  Material increases in the value of the Canadian dollar negatively impact our production revenues.  Future Canadian/United States exchange rates could accordingly impact the future value of our reserves as determined by independent evaluators.

To the extent that we engage in risk management activities related to foreign exchange rates, there is a credit risk associated with counterparties with which we may contract.

An increase in interest rates could result in a significant increase in the amount we pay to service debt, which could negatively impact the market price of our Common Shares.

Risks Related to Our Common Stock

We do not intend to pay cash dividends.

We have never, and we do not have any intention of paying cash dividends in the foreseeable future.  In particular, there can be no assurance that our Board of Director’s will ever declare cash dividends, which action is completely within their discretion.

Investors may suffer dilution from future share issuances

We may make future acquisitions or enter into financings or other transactions involving the issuance of our securities, which may be dilutive.

Economic conditions and fluctuation and volatility of stock price may negatively impact shareholder value

The market price of our common shares is highly volatile.  If investors’ interest in the sector in which we operate declines, the price for our common shares would likely also decline.  In addition, trading volumes in our common shares can be volatile and if the trading volume of our common shares experiences significant changes, the price of our common shares could be adversely affected.  The price of our common shares could also be significantly affected by other factors, many of which are beyond our control.

Fluctuations in economic conditions, such as the continuing downturn in the global economy, may also significantly affect our ability to meet our objectives which could adversely affect our share price.

Broker-dealers may be discouraged from effecting transactions in our shares because they are considered a penny stock and are subject to the penny stock rules.

Our stock is a penny stock. The Securities and Exchange Commission has adopted Rule 15g-9 which generally defines "penny stock" to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and "accredited investors". The term "accredited investor" refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC, which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of our common stock.

If we raise additional funding through equity financings, then our current shareholders will suffer dilution.

We believe the only realistic source of future funds presently available to us is through the sale of equity capital. Any sale of equity capital will result in dilution to existing shareholders. The only other alternative for the financing of further exploration would be the offering by us of an interest in our properties to be earned by another party or parties carrying out further exploration thereof.

Dilution through contractor, director and consultant options could adversely affect our stockholders.

Because our success is highly dependent on our contractors, we grant some or all of our key contractors, officers, directors and consultants options to purchase common shares, as non-cash incentives. If significant numbers of these options are granted and exercised, the interests of other stockholders may be diluted.

As at May 13, 2011 there are currently options outstanding to purchase an additional 2,090,000common shares which upon exercise would result in a total of 23,493,979common shares being issued and outstanding.

Our common stock is thinly traded.

The trading market for our shares is not always liquid. The market price of Alberta Star’s common shares has ranged from a high of $1.20 and a low of $0.37 during the twelve month period ended November 30, 2010.  Although our shares trade on the TSX Venture Exchange (“TSX-V”), FINRA Over-the-Counter Bulletin Board (“OTCBB”) and the Frankfurt Exchange (“QLD”), the volume of shares traded at any one time can be limited, and, as a result, there may not be a liquid trading market for our shares.

ITEM 4 – INFORMATION ON THE COMPANY

A.

History and Development of the Company

The Company was incorporated under the name “Alberta Star Mining Corp.” pursuant to theBusiness Corporations Actin the Province of Alberta, Canada by registration of our articles of incorporation and the issuance by the Registrar of Companies of a Certificate of Incorporation on September 6, 1996. On September 20, 2001, we consolidated our share capital such that every five common shares in our capital stock pre-consolidation were exchanged for one post-consolidation common share. Concurrently, we changed our name to “Alberta Star Development Corp.” On March 11, 2010, we consolidated our share capital such that every five common shares in our capital stock pre-consolidation were exchanged for one post-consolidation common share with no change to the Company name.

Our head office is located at 506 – 675 West Hastings Street, Vancouver, British Columbia, Canada, V6B 1N2. Our telephone number is (604) 488 – 0860.

We have not been involved in any bankruptcy, receivership or similar proceedings, nor have we been a party to any material reclassification, merger, consolidation or purchase or sale of a significant amount of assets.

On April 21, 2010, we announced that we were unsuccessful in our bid to acquire 100% of the shares of Sterling and the Sunshine Mine Lease pursuant to a bankruptcy auction held on April 21, 2010.  We have confirmed that, as a result of the unsuccessful bid, certain conditions contained in the Acquisition Agreement (the “Agreement”) with Sterling dated November 17, 2009 have not been satisfied in accordance with the terms of the Agreement.  We received a compensation fee of US$250,000 provided for under the terms of the Agreement and the Second Amended Plan and Disclosure Statement filed by Sterling.

On or about August 6, 2010, we entered into an asset purchase agreement with Western Plains Petroleum Ltd. (“Western Plains”) under which we acquired an undivided 50% interest in the Lloydminster Alberta (“Lloydminster”) properties and the Landrose Saskatchewan (“Landrose”) properties.  We further entered into a joint operating agreement with Nordic Oil & Gas Ltd. with respect to the Lloydminster Alberta property and a sub-participation agreement with Arctic Hunter Uranium Inc.   On or about August 26, 2010, we entered into a further oil and gas asset purchase with Western Plains pursuant to which we acquired an undivided 33.33% interest in thirteen (13) crown leases located in the Lloydminster heavy oil area of Alberta for a cash purchase price of $1.467 million, subject to usual industry adjustments.

These transactions resulted in our diversification into the oil and natural gas resource sector with revenue producing heavy oil and natural gas assets, in addition to our existing mineral property interests.

We did not expend any significant amounts during the year ended November 2010 exploring or developing our mineral properties, and intend to maintain but not further explore or develop these properties at the present time in order to focus on our oil and gas business.

Our mineral properties have no known significant body of commercial ore, nor are any such properties at the commercial development or production stage.  No assurance can be given that commercially viable mineral deposits exist on any of our properties. Further, our interest in joint ventures which own properties will be subject to dilution if we fail to expend further funds on the projects. These facts increase the uncertainty and risks faced by investors in our Company. For more information see Item 3D – Risk Factors.

After acquisition of our oil and gas properties, we participated with our partners in the drilling and completion of certain wells on the properties,including those described below and under the heading "Oil and Gas Properties".  

On November 19, 2010, we announced that all 5 standing cased wells located in the Lloydminster Alberta heavy oil assets were completed and producing, the production from the first 3 of the wells being stabilized in aggregate at approximately 75 bbls/d from the Sparky formation.  We also announced that together with our industry partner, we had acquired a 100% interest in petroleum and natural gas rights on 120 acres located in the Lloydminster area of Alberta on a 50/50 basis, paying a cash consideration of aggregate $192,000, including administrative fees and taxes.

On November 23, 2010 we announced that we had been successful in acquiring a 100% interest (50/50 with our industry partner) in petroleum and natural gas rights on 40 gross acres in the Landrose heavy oil area paying an aggregate cash consideration of approximately $82,000 including administrative fees and applicable taxes.  

Subsequent to the year ending November 30, 1010, we acquired petroleum and natural gas rights on an additional 160 acre parcel in the Lloydminster heavy oil region and successfully drilled cased and completed 3 wells in the Phase 2 drilling program at Landrose, with all 3 wells being in production.  We also announced our Phase 3 drilling program at Landrose consisting of the three in-fill wells targeting the McClaren formation, and, in January, 2011 announced we had entered into an agreement with Southern Cross Energy (“Southern Cross”) to locate and pursue a number of heavy oil and natural gas opportunities in Colombia, SA.  In February  2011 we announced an agreement with Forent Energy Ltd. (“Forent”) to participate in drilling one well on the Blackfoot lands in the Lloydminster Alberta area.  Under the agreement, Forent will be the operator and we will pay 50% of the cost to drill, complete and equip or abandon the well to earn a 50% net interest before payout, reserving to Sashara Energy Ltd. a gross convertible overriding royalty of 15% until payout.  After payout Sahara has the option to convert its gross overriding royalty to a 25% working interest in the well spacing unit. On April 14, 2011 we announced the drilling, casing and completion of the Blackfoot heavy oil well.  On May 10, 2011 we announced an increase in our Landrose, Saskatchewan holdings by completing a property swap resulting in a 50% WI in petroleum and natural gas rights and one standing cased well on 240 acres,  in exchange for our 50% WI in 320 undeveloped acres in the Golden Lake area of west central Saskatchewan.

B.

Business Overview

We are a Canadian resource exploration and development company that identifies, acquires and finances oil and natural gas assets in Western Canada and advanced stage mineral exploration projects in North America.   At present, our mineral properties are in the exploration stage and further exploration will be required before final evaluations as to the economic and legal feasibility can be determined.  Our oil and gas properties are all non-operated interests with production focused on heavy oil and natural gas.  We are planning to expand our future production through exploration drilling activities, production acquisitions and strategic asset acquisitions.  The oil and gas industry is subject to a number of unique conditions that affect our business operations which are described below.  See "Cautionary Note Regarding Forward Looking Statements".

OIL AND GAS INDUSTRY CONDITIONS

Companies operating in the oil and natural gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining, transportation, and marketing) as a result of legislation enacted by various levels of government and with respect to the pricing and taxation of oil and natural gas through agreements among the governments of Canada, Alberta and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry.  It is not expected that any of these regulations or controls will affect our operations in a manner materially different than they will affect other oil and natural gas companies of similar size. All current legislation is a matter of public record and us is unable to predict what additional legislation or amendments may be enacted.  Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing

Oil

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil.  Oil prices are primarily based on worldwide supply and demand.  The specific price depends in part on oil quality, prices of competing fuels, distance to market, the value of refined products, the supply/demand balance, and contractual terms of sale.  Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "NEB").  Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such a licence requires a public hearing and the approval of the Governor in Council.

All our crude oil consists of heavy oil produced in Saskatchewan and Alberta that is marketed based on refiners’ posted prices for Western Canadian Select heavy oil, adjusted for the quality (primarily density) of the crude oil on a well by well basis.  The majority of our heavy oil ranges in density from approximately 13.6  API to 15.9  API.  The refiners’ posted prices are influenced by the US$ WTI reference price, transportation costs, US$/C$ exchange rates and the supply/demand situation of particular crude oil quality streams during the year.  The prices realized realized by Alberta Star on heavy oil sales are net of treating fees, blending costs, required for its heavy grades of oil to meet pipeline stream specifications, and pipeline tariffs.

Though crude oil prices increased during 2010, the price differential between heavy and light crude oil increased in the second half of 2010 primarily due to a transportation disruption resulting from the nine week maintenance shut-down of a pipeline that carries Canadian crude oil to refineries in the US Midwest.  Further short term maintenance shut downs of this pipeline followed in January and February 2011, with product delivery rates having been largely restored as of the date hereof.

Natural Gas

The price of the vast majority of natural gas produced in western Canada is now determined through the liquid market established at the Alberta "NIT" hub rather than through direct negotiation between buyers and sellers.  Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada.  Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada.  Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day) must be made pursuant to an NEB order.  Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or for a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such a licence requires a public hearing and the approval of the Governor in Council.

The governments of Alberta and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.

Pipeline Capacity

As a result of pipeline expansions over the past several years, there is ample pipeline capacity to accommodate Current Production levels of oil and natural gas in western Canada and pipeline capacity does not generally limit the ability to produce and market such production.

The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico became effective on January 1, 1994.  NAFTA carries forward most of the material energy terms that are contained in the Canada United States Free Trade Agreement.  In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of goods of the party maintaining the restriction as compared to the proportion prevailing in the most recent 36 month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); and (iii) disrupt normal channels of supply.   All three signatory countries are prohibited from imposing a minimum or maximum export price requirement in any circumstance where any other form of quantitative restriction is prohibited.  The signatory countries are also prohibited from imposing a minimum or maximum import price requirement except as permitted in enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA prohibits discriminatory border restrictions and export taxes.  NAFTA also requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports.

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern royalties, production rates and other matters.  The royalty regime in a given province is a significant factor in the profitability of crude oil, NGLs, sulphur and natural gas production.  Royalties payable on production from lands other than Crown lands are determined by negotiation between the mineral freehold owner and the lessee, although production from such lands is subject to certain provincial taxes and royalties.  Royalties from production on Crown lands are determined by governmental regulation and are generally calculated as a percentage of the value of gross production.  The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced.  Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner's interest through non-public transactions.  These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development.  Such programs often provide for royalty rate reductions, royalty holidays or royalty tax credits and are generally introduced when commodity prices are low to encourage exploration and development activity by improving earnings and cash flow within the industry.

Alberta

Producers of oil and natural gas from Crown lands in Alberta are required to pay annual rental payments, currently at a rate of $3.50 per hectare, and make monthly royalty payments in respect of oil and natural gas produced.

On October 25, 2007, the Government of Alberta released a report entitled "The New Royalty Framework" ("NRF") containing the Government's proposals for Alberta's new royalty regime which were subsequently implemented by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008.  The NRF took effect on January 1, 2009.  On March 11, 2010, the Government of Alberta announced changes to Alberta's royalty system intended to increase Alberta's competitiveness in the upstream oil and natural gas sectors, which changes included a decrease in the maximum royalty rates for conventional oil and natural gas production effective for the January 2011 production month.  Royalty curves incorporating the changes announced on March 11, 2010 were released on May 27, 2010.  Alberta royalties in effect after December 31, 2010 are known as the "Alberta Royalty Framework" ("ARF").

With respect to conventional oil, the NRF eliminated the classification system used by the previous royalty structure which classified oil based on the date of discovery of the pool.  Under the ARF, royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and incorporates separate variables to account for production rates and market prices.  Royalty rates for conventional oil under the NRF ranged from 0-50%, an increase from the previous maximum rates of 30-35% depending on the vintage of the oil, and rate caps were set at $120 per barrel.  Effective January 1, 2011, the maximum royalty payable under the ARF was reduced to 40%.  The royalty curve for conventional oil announced on May 27, 2010 amends the price component of the conventional oil royalty formula to moderate the increase in the royalty rate at prices higher than $535/m3 compared to the previous royalty curve.

Royalty rates for natural gas under the ARF are similarly determined using a single sliding rate formula incorporating separate variables to account for production rates and market prices.  Royalty rates for natural gas under the NRF ranged from 5-50%, an increase from the previous maximum rates of 5-35%, and rate caps were set at $16.59/GJ.  Effective January 1, 2011, the maximum royalty payable under the ARF was reduced to 36%.  The royalty curve for natural gas announced on May 27, 2010 amends the price component of the natural gas royalty formula to moderate the increase in the royalty rate at prices higher than $5.25/GJ compared to the previous royalty curve.

Oil sands projects are also subject to the ARF.  Prior to payout, the royalty is payable on gross revenues of an oil sands project.  Gross revenue royalty rates range between 1-9% depending on the market price of oil, determined using the average monthly price, expressed in Canadian dollars, for WTI crude oil and Cushing, Oklahoma: rates are 1% when the market price of oil is less than or equal to $55 per barrel and increase for every dollar of market price of oil increase to a maximum of 9% when oil is priced at $120 or higher.  After payout, the royalty payable is the greater of the gross revenue royalty based on the gross revenue royalty rate of 1-9% and the net revenue royalty based on the net revenue royalty rate.  Net revenue royalty rates start at 25% and increase for every dollar of market price of oil increase above $55 up to 40% when oil is priced at $120 or higher.  An oil sands project reaches payout when its cumulative revenue exceeds its cumulative costs.  Costs include specified allowed capital and operating costs related to the project plus a specified return allowance.  As part of the implementation of the NRF, the Government of Alberta renegotiated existing contracts with certain oil sands producers that were not compatible with the NRF or the ARF.

Producers of oil and natural gas from freehold lands in Alberta are required to pay annual freehold production taxes.  The level of the freehold production tax is based on the volume of monthly production and a specified rate of tax for both oil and gas.

In April 2005, the Government of Alberta implemented the Innovative Energy Technologies Program (the "IETP"), which has the stated objectives of increasing recovery from oil and gas deposits, finding technical solutions to the gas over bitumen issue, improving the recovery of bitumen by in-situ and mining techniques and improving the recovery of natural gas from coal seams.  The IETP is backed by a $200 million funding commitment over a five-year period beginning April 1, 2005 and provides royalty adjustments to specific pilot and demonstration projects that utilize new or innovative technologies to increase recovery from existing reserves.

On April 10, 2008, the Government of Alberta introduced two new royalty programs to be implemented along with the NRF and intended to encourage the development of deeper, higher cost oil and gas reserves.  A five-year program for conventional oil exploration wells over 2,000 metres provides qualifying wells with up to a $1 million or 12 months of royalty relief, whichever comes first, and a five-year program for natural gas wells deeper than 2,500 metres provides a sliding scale royalty credit based on depth of up to $3,750 per metre.  On May 27, 2010, the natural gas deep drilling program was amended, retroactive to May 1, 2010, by reducing the minimum qualifying depth to 2,000 metres, removing a supplemental benefit of $875,000 for wells exceeding 4,000 metres that are spudded subsequent to that date, and including wells drilled into pools drilled prior to 1985, among other changes.

On November 19, 2008, in response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced the introduction of a five-year program of transitional royalty rates with the intent of promoting new drilling.  The 5-year transition option is designed to provide lower royalties at certain price levels in the initial years of a well's life when production rates are expected to be the highest.  Under this new program, companies drilling new natural gas or conventional deep oil wells (between 1,000 and 3,500 m) are given a one-time option, on a well-by-well basis, to adopt either the new transitional royalty rates or those outlined in the NRF.  Pursuant to the changes made to Alberta's royalty structure announced on March 11, 2010, producers were only able to elect to adopt the transitional royalty rates prior to January 1, 2011 and producers that had already elected to adopt such rates as of that date were permitted to switch to Alberta's conventional royalty structure up until February 15, 2011.  On January 1, 2014, all producers operating under the transitional royalty rates will automatically become subject to the ARF. The revised royalty curves for conventional oil and natural gas will not be applied to production from wells operating under the transitional royalty rates.

On March 3, 2009, the Government of Alberta announced a three-point incentive program in order to stimulate new and continued economic activity in Alberta.  The program introduced a drilling royalty credit for new conventional oil and natural gas wells and a new well royalty incentive program, both applying to conventional oil or natural gas wells drilled between April 1, 2009 and March 31, 2010.  The drilling royalty credit provides up to a $200 per metre royalty credit for new wells and is primarily expected to benefit smaller producers since the maximum credit available will be determined using our production level in 2008 and its drilling activity between April 1, 2009 and March 31, 2010, favouring smaller producers with lower activity levels.  The new well incentive program initially applied to wells that began producing conventional oil or natural gas between April 1, 2009 and March 31, 2010 and provided for a maximum 5% royalty rate for the first 12 months of production on a maximum of 50,000 barrels of oil or 500 MMcf of natural gas.  In June, 2009, the Government of Alberta announced the extension of these two incentive programs for one year to March 31, 2011.  On March 11, 2010, the Government of Alberta announced that the incentive program rate of 5% for the first 12 months of production would be made permanent, with the same volume limitations.

In addition to the foregoing, on May 27, 2010, in conjunction with the release of the new royalty curves, the Government of Alberta announced a number of new initiatives intended to accelerate technological development and facilitate the development of unconventional resources (the "Emerging Resource and Technologies Initiative").  Specifically:

• Coalbed methane wells will receive a maximum royalty rate of 5% for 36 producing months on up to 750 MMcf of production, retroactive to wells that began producing on or after May 1, 2010;

• Shale gas wells will receive a maximum royalty rate of 5% for 36 producing months with no limitation on production volume, retroactive to wells that began producing on or after May 1, 2010;

• Horizontal gas wells will receive a maximum royalty rate of 5% for 18 producing months on up to 500 MMcf of production, retroactive to wells that commenced drilling on or after May 1, 2010;

• Horizontal oil wells and horizontal non-project oil sands wells will receive a maximum royalty rate of 5% with volume and production month limits set according to the depth of the well (including the horizontal distance), retroactive to wells that commenced drilling on or after May 1, 2010.

The Emerging Resource and Technologies Initiative will be reviewed in 2014, and the Government of Alberta has committed to providing industry with three years notice at that time if it decides to discontinue the program.

Saskatchewan

In Saskatchewan, the amount payable as Crown royalty or freehold production tax in respect of oil depends on the type and vintage of oil, the quantity of oil produced in a month, the value of the oil produced and specified adjustment factors determined monthly by the provincial government.  For Crown royalty and freehold production tax purposes, conventional oil is classified as "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil".  The conventional royalty and production tax classifications ("fourth tier oil", "third tier oil", "new oil" and "old oil") depend on the finished drilling date of a well and are applied to each of the three crude oil types slightly differently.  Heavy oil is classified as third tier oil (having a finished drilling date on or after January 1, 1994 and before October 1, 2004), fourth tier oil (having a finished drilling date on or after October 1, 2002) or new oil (not classified as either third tier oil or fourth tier oil).  Southwest designated oil uses the same definitions of third and fourth tier oil but new oil is defined as conventional oil produced from a horizontal well having a finished drilling date on or after February 9, 1998 and before October 1, 2002.  For non-heavy oil other than southwest designated oil, the same classification is used but new oil is defined as conventional oil produced from a vertical well completed after 1973 and having a finished drilling date prior to 1994, whereas old oil is defined as conventional oil not classified as third or fourth tier oil or new oil.

Base prices are used to establish lower limits in the price-sensitive royalty structure for conventional oil.  Where average wellhead prices are below the established base prices of $100 per m3 for third and fourth tier oil and $50 per m3 for new oil and old oil, base royalty rates are applied.  Base royalty rates are 5% for all fourth tier oil, 10% for heavy oil that is third tier oil or new oil, 12.5% for southwest designated oil that is third tier oil or new oil, 15% for non-heavy oil other than southwest designated oil that is third tier or new oil, and 20% for old oil.  Where average wellhead prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base oil price.  Marginal royalty rates are 30% for all fourth tier oil, 25% for heavy oil that is third tier oil or new oil, 35% for southwest designated oil that is third tier oil or new oil, 35% for non-heavy oil other than southwest designated oil that is third tier or new oil, and 45% for old oil.

The amount payable as Crown royalty or freehold production tax in respect of natural gas production is determined by a sliding scale based on a reference price (which is the greater of the amount obtained by the producer and a prescribed minimum price), the quantity produced in a given month, the type of natural gas, and the vintage of the natural gas.  Like conventional oil, natural gas is classified as "non-associated gas" or "associated gas" and royalty rates are determined according to the finished drilling date of the respective well.  As an incentive for the production and marketing of natural gas which may have been flared, the royalty rate on natural gas produced in association with oil is less than on non-associated natural gas.  Non-associated gas is classified as new gas (having a finished drilling date before February 9, 1998 with a first production date on or after October 1, 1976), third tier gas (having a finished drilling date on or after February 9, 1998 and before October 1, 2002), fourth tier gas (having a finished drilling date on or after October 1, 2002) and old gas (not classified as either third tier, fourth tier or new gas).  A similar classification is used for associated gas except that the classification of old gas is not used, the definition of fourth tier gas also includes production from oil wells with a finished drilling date prior to October 1, 2002, where the individual oil well has a gas-oil production ratio in any month of more than 3,500 m3 of gas for every m3 of oil, and new gas is defined as oil produced from a well with a finished drilling date before February 9, 1998 that received special approval, prior to October 1, 2002, to produce oil and gas concurrently without gas-oil ratio penalties.

On December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010 which replaces the existing Freehold Oil and Gas Production Tax Act and is intended to facilitate more efficient payment of freehold production taxes by industry.  No regulations have been passed with respect to the calculation of freehold production taxes under the new Act.

As with conventional oil production, base prices are used to establish lower limits in the price-sensitive royalty structure for natural gas.  Where average field-gate prices are below the established base prices of $50 per thousand m3 for third and fourth tier gas and $35 per thousand m3 for new gas and old gas, base royalty rates are applied.  Base royalty rates are 5% for all fourth tier gas, 15% for third tier or new gas, and 20% for old gas.  Where average well-head prices are above base prices, marginal royalty rates are applied to the proportion of production that is above the base gas price.  Marginal royalty rates are 30% for all fourth tier gas, 35% for third tier and new gas, and 45% for old gas.

The Government of Saskatchewan currently provides a number of targeted incentive programs.  These include both royalty reduction and incentive volume programs, including the following:

• Royalty/Tax Incentive Volumes for Vertical Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 8,000 m3 for deep development vertical oil wells, 4,000 m3 for non-deep exploratory vertical oil wells and 16,000 m3 for deep exploratory vertical oil wells (more than 1,700 metres or within certain formations);

• Royalty/Tax Incentive Volumes for Exploratory Gas Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 25,000,000 m3 for qualifying exploratory gas wells;

• Royalty/Tax Incentive Volumes for Horizontal Oil Wells Drilled on or after October 1, 2002 providing reduced Crown royalty and freehold tax rates on incentive volumes of 6,000 m3 for non-deep horizontal oil  wells and 16,000 m3 for deep horizontal oil wells (more than 1,700 metres or within certain formations);

• Royalty/Tax Regime for Incremental Oil Produced from New or Expanded Waterflood Projects Implemented on or after October 1, 2002 treating incremental production from waterflood projects as fourth tier oil for the purposes of royalty calculation;

• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing prior to April 1, 2005 providing Crown royalty and freehold tax determinations based in part on the profitability of enhanced recovery projects pre- and post-payout;

• Royalty/Tax Regime for Enhanced Oil Recovery Projects (Excluding Waterflood Projects) Commencing on or after April 1, 2005 providing a Crown royalty of 1% of gross revenues on enhanced oil recovery projects pre-payout and 20% post-payout and a freehold production tax of 0% on operating income from enhanced oil recovery projects pre-payout and 8% post-payout;

• Royalty/Tax Regime for High Water-Cut Oil Wells granting "third tier oil" royalty/tax rates to incremental high water-cut oil production resulting from qualifying investments made to rejuvenate eligible oil wells and/or associated facilities; and

• Royalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and before April 1, 2013 providing reduced Crown royalty and freehold tax rates on incentive volumes of 25,000,000 m3 for horizontal gas wells.

In 1975, the Government of Saskatchewan introduced a Royalty Tax Rebate ("RTR") as a response to the Government of Canada disallowing crown royalties and similar taxes as a deductible business expense for income tax purposes.  As of January 1, 2007, the remaining balance of any unused RTR will be limited in its carry forward to seven years since the Government of Canada's initiative to reintroduce the full deduction of provincial resource royalties from federal and provincial taxable income.  Saskatchewan's RTR will be wound down as a result of the Government if Canada's plan to reintroduce full deductibility of provincial resource royalties for corporate income tax purposes.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments.  Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments.  Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Each of the provinces of Alberta and Saskatchewan has implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a lease or license.

In Alberta, the NRF includes a policy of "shallow rights reversion" which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for all leases and licenses.  For leases and licenses issued subsequent to January 1, 2009, shallow rights reversion will be applied at the conclusion of the primary term of the lease or license.  Holders of leases or licences that have been continued indefinitely prior to January 1, 2009 will receive a notice regarding the reversion of the shallow rights, which will be implemented three years from the date of the notice.  The order in which these agreements will receive the reversion notice will depend on their vintage and location, with the older leases and licenses receiving reversion notices first beginning in January 2011.  Leases and licences that were granted prior to January 1, 2009 but continued after that date will not be subject to shallow rights reversion until they reach the end of their primary term and are continued (at which time deep rights reversion will be applied); thereafter, the holders of such agreements will be served with shallow rights reversion notices based on vintage and location similar to leases and licences that were already continued as of January 1, 2009.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation, all of which is subject to governmental review and revision from time to time.  Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide.  In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities.  Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

In December, 2008, the Government of Alberta released a new land use policy for surface land in Alberta, the Alberta Land Use Framework (the "ALUF").  The ALUF sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province.  It calls for the development of region-specific land use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.   TheAlberta Land Stewardship Act (the "ALSA") was proclaimed in force in Alberta on October 1, 2009, providing the legislative authority for the Government of Alberta to implement the policies contained in the ALUF.  Regional plans established pursuant to the ALSA are deemed to be legislative instruments equivalent to regulations and are binding on the Government of Alberta and provincial regulators, including those governing the oil and gas industry.  In the event of a conflict or inconsistency between a regional plan and another regulation, regulatory instrument or statutory consent, the regional plan will prevail.  Further, the ALSA requires local governments, provincial departments, agencies and administrative bodies or tribunals to review their regulatory instruments and make any appropriate changes to ensure that they comply with an adopted regional plan.  The ALSA also contemplates the amendment or extinguishment of previously issued statutory consents such as regulatory permits, licenses, approvals and authorizations in order for the purpose of achieving or maintaining an objective or policy resulting from the implementation of a regional plan.  Among the measures to support the goals of the regional plans contained in the ALSA are conservation easements, which can be granted for the protection, conservation and enhancement of land; and conservation directives, which are explicit declarations contained in a regional plan to set aside specified lands in order to protect, conserve, manage and enhance the environment.  Although no regional plans have been established under the ALSA, the planning process is underway for the Lower Athabasca Region (which contains the majority of oil sands development) and the South Saskatchewan Region.  While the potential impact of the regional plans established under the ALSA cannot yet be determined, it is clear that such regional plans may have a significant impact on land use in Alberta and may affect the oil and gas industry.

Climate Change Regulation

Federal

In December 2002, the Government of Canada ratified the Kyoto Protocol ("Kyoto Protocol"), which requires a reduction in greenhouse gas ("GHG") emissions by signatory countries between 2008 and 2012.  The Kyoto Protocol officially came into force on February 16, 2005 and commits Canada to reduce its greenhouse gas emissions levels to 6% below 1990 "business-as-usual" levels by 2012.

On February 14, 2007, the House of Commons passed Bill C-288, An Act to ensure Canada meets its global climate change obligations under the Kyoto Protocol.  The resulting Kyoto Protocol Implementation Act came into force on June 22, 2007.  Its stated purpose is to "ensure that Canada takes effective and timely action to meet its obligations under the Kyoto Protocol and help address the problem of global climate change." It requires the federal Minister of the Environment to, among other things, produce an annual climate change plan detailing the measures to be taken to ensure Canada meets its obligations under the Kyoto Protocol.  It also authorizes the establishment of regulations respecting matters such as emissions limits, monitoring, trading and enforcement.

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both greenhouse gases and air pollution.  An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan").  The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis.  Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors.  Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets.

The Updated Action Plan makes a distinction between "Existing Facilities" and "New Facilities".  For Existing Facilities, the Updated Action Plan requires an emissions intensity reduction of 18% below 2006 levels by 2010 followed by a continuous annual emissions intensity improvement of 2%.  "New Facilities" are defined as facilities beginning operations in 2004 and include both green-field facilities and major facility expansions that (i) result in a 25% or greater increase in a facility's physical capacity, or (ii) involve significant changes to the processes of the facility.  New Facilities will be given a 3-year grace period during which no emissions intensity reductions will be required.  Targets requiring an annual 2% emissions intensity reduction will begin to apply in the fourth year of commercial operation of a New Facility.  Further, emissions intensity targets for New Facilities will be based on a cleaner fuel standard to encourage continuous emissions intensity reductions over time.  The method of applying this cleaner fuel standard has not yet been determined.  In addition, the Updated Action Plan indicates that targets for the adoption of carbon capture and storage ("CCS") technologies will be developed for oil sands in-situ facilities, upgraders and coal-fired power generators that begin operations in 2012 or later.  These targets will become operational in 2018, although the exact nature of the targets has not yet been determined.

Given the large number of small facilities within the upstream oil and gas and natural gas pipeline sectors, facilities within these sectors will only be subject to emissions intensity targets if they meet certain minimum emissions thresholds.  That threshold will be (i) 50,000 tonnes of CO₂ equivalents per facility per year for natural gas pipelines; (ii) 3,000 tonnes of CO₂ equivalents per facility per year for the upstream oil and gas facility; and (iii) 10,000 boe/d/company.  These regulatory thresholds are significantly lower than the regulatory threshold in force in Alberta, discussed below.  In all other sectors governed by the Updated Action Plan, all facilities will be subject to regulation.

Four separate compliance mechanisms are provided for in the Updated Action Plan in respect of the above targets: Regulated entities will be able to use Technology Fund contributions to meet their emissions intensity targets.  The contribution rate for Technology Fund contributions will increase over time, beginning at $15 tonnes per CO₂ equivalent for the 2010-12 period, rising to $20 in 2013, and thereafter increasing at the nominal rate of GDP growth.  Maximum contribution limits will also decline from 70% in 2010 to 0% in 2018.  Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions.  Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as described above.

The offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities.  In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued to the project proponent.  Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either purchase the offset credits for cancellation or banking for future use or sale.

Under the Updated Action Plan, regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto Protocol which facilitates investment by developed nations in emissions-reduction projects in developing countries.  The purchase of such Emissions Reduction Credits will be restricted to 10% of each firm's regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

Finally, a one-time credit of up to 15 million tonnes worth of emissions credits will be awarded to regulated entities for emissions reduction activities undertaken between 1992 and 2006.  These credits will be both tradable and bankable.

The United Nations Framework Convention on Climate Change is working towards establishing a successor to the Kyoto Protocol.   From December 7 to 18, 2009, a meeting between government leaders and representatives from approximately 170 countries in Copenhagen, Denmark (the "Copenhagen Conference") resulted in the Copenhagen Accord, which reinforces the commitment to reducing GHG emissions contained in the Kyoto Protocol and promises funding to help developing countries mitigate and adapt to climate change.  From November 29 to December 10, 2010, a meeting between representatives from approximately 190 countries in Cancun, Mexico resulted in the Cancun Agreements, in which developed countries committed to additional measures to help developing countries deal with climate change.  Unlike the Kyoto Protocol, however, neither the Copenhagen Accord nor the Cancun Agreements establish binding GHG emissions reduction targets.

In response to the Copenhagen Accord, the Government of Canada indicated on January 29, 2010 that it will seek to achieve a 17% reduction in greenhouse gas emissions from 2005 levels by 2020.  This goal is similar to the goal expressed in previous policy documents which were discussed above.

Although draft regulations for the implementation of the Updated Action Plan were intended to be published in the fall of 2008 and become binding on January 1, 2010, no such regulations have been proposed to date.  Further, representatives the Government of Canada have indicated that the proposals contained in the Updated Action Plan will be modified to ensure consistency with the direction ultimately taken by the United States with respect to greenhouse gas emissions regulation.  As a result, it is unclear to what extent, if any, the proposals contained in the Updated Action Plan will be implemented.

On December 23, 2010, the United States Environmental Protection Agency indicated its intention to impose greenhouse gas emissions standards for fossil fuel-fired power plants by July, 2011 and for refineries by December, 2011.

Alberta

Alberta enacted the Climate Change and Emissions Management Act (the "CCEMA") on December 4, 2003, amending it through the Climate Change and Emissions Management Amendment Act which received royal assent on November 4, 2008.  The CCEMA is based on an emissions intensity approach similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.

Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year are subject to comply with the CCEMA.  Similarly to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make a distinction between "Established Facilities" and "New Facilities".  Established Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2000 or that have completed eight or more years of commercial operation.  Established Facilities are required to reduce their emissions intensity to 88% of their baseline for 2008 and subsequent years, with their baseline being established by the average of the ratio of the total annual emissions to production for the years 2003 to 2005. New Facilities are defined as facilities that completed their first year of commercial operation on December 31, 2000, or a subsequent year, and have completed less than eight years of commercial operation, or are designated as New Facilities in accordance with the Specified Gas Emitters Regulation.  New Facilities are required to reduce their emissions intensity by 2% from baseline in the fourth year of commercial operation, 4% of baseline in the fifth year, 6% of baseline in the sixth year, 8% of baseline in the seventh year, and 10% of baseline in the eighth year.  Unlike the Updated Action Plan, the CCEMA does not contain any provision for continuous annual improvements in emissions intensity reductions beyond those stated above.

The CCEMA contains similar compliance mechanisms as the Updated Action Plan.  Regulated emitters can meet their emissions intensity targets by contributing to the Climate Change and Emissions Management Fund (the "Fund") at a rate of $15 per tonne of CO2 equivalent.  Unlike the Updated Action Plan, CCEMA contains no provisions for an increase to this contribution rate.  Emissions credits can be purchased from regulated emitters that have reduced their emissions below the 100,000 tonne threshold or non-regulated emitters that have generated emissions offsets through activities that result in emissions reductions in accordance with established protocols published by the Government of Alberta.  Unlike the Updated Action Plan, the CCEMA does not contemplate a linkage to external compliance mechanisms such as the Kyoto Protocol's Clean Development Mechanism.

On December 2, 2010, the Government of Alberta passed the Carbon Capture and Storage Statutes Amendment Act, 2010, which deemed the pore space underlying all land in Alberta to be, and to have always been, the property of the Crown and provided for the assumption of long-term liability for carbon sequestration projects by the Crown, subject to the satisfaction of certain conditions.

Saskatchewan

On May 11, 2009, the Government of Saskatchewan announced The Management and Reduction of Greenhouse Gases Act (the "MRGGA") to regulate greenhouse gas emissions in the province.  The MRGGA received Royal Assent on May 20, 2010 and will come into force on proclamation.  Regulations under the MRGGA have also yet to be proclaimed, but draft versions indicate that Saskatchewan will adopt the goal of a 20% reduction in greenhouse gas emissions from 2006 levels by 2020 and permit the use of pre-certified investment credits, early action credits and emissions offsets in compliance, similar to both the federal and Alberta climate change initiatives.  It remains unclear whether the scheme implemented by the MRGGA will be based on emissions intensity or an absolute cap on emissions.

MINERAL EXPLORATION INDUSTRY CONDITIONS

Background

Cautionary Note to U.S. Investors –In this Annual Report we use the terms “Mineral Resource”, “Measured Mineral Resource”, “Indicated Mineral Resource” and “Inferred Mineral Resource”, which are geological and mining terms as defined in accordance with NI 43-101 under the guidelines adopted by CIM, as CIM Standards in Mineral Resources and Reserve Definition and Guidelines adopted by the CIM. US investors in particular are advised to read carefully the definitions of these terms as well as the “Cautionary Note to U.S. Investors Regarding Reserve and Resource Estimates” above.

We are engaged in the exploration and acquisition of mineral properties in Canada, and specifically hold all of our interests in the Northwest Territories.

We are a junior mining company in the exploration stage and none of our mineral properties are currently beyond the initial exploration stage. There is no assurance that a commercially viable mineral deposit exists on any of our properties and further exploration work will be required before a final evaluation as to the economic and legal feasibility is determined. For further information, see “Item 3D – Risk Factors.”

We have conducted acquisitions and initial surveys for the purpose of determining the viability of exploration work on properties located in the Northwest Territories, Canada.  The equity markets for junior mineral exploration companies are unpredictable. We may also and have historically entered into cost sharing arrangements through joint venture agreements and interest agreements in the form of letters of intent. For detailed property descriptions please refer to “Item 4D – Property, Plant and Equipment.”

During the year ended November 30, 2010, we diversified into the oil and natural gas resource sector with the acquisition of revenue producing resource assets to complement our existing advanced stage mining interests and provides us with a reputable working interest partner for future expansion in the oil and natural gas resource sector. We are now a heavy oil producer.

At present, we have income from our oil and gas operations but none of our mineral properties have significant reserves nor are in production. Our ability to finance the future acquisition, exploration and development, if warranted, of our mineral properties, to make concession payments and to fund general and administrative expenses is therefore dependent upon our ability to secure additional financing.

Competition

The mineral property exploration business, in general, is intensively competitive and there is not any assurance that even if commercial quantities of ore are discovered, a ready market will exist for sale of same. Numerous factors beyond our control may affect the marketability of any substances discovered. These factors include market fluctuations; the proximity and capacity of natural resource markets and processing equipment; and government regulations, including regulations relating to prices, taxes, royalties, land tenure, land use, importing and exporting of mineral and environmental protection. The exact effect of these factors cannot be accurately predicted, but the combination of these factors may make it difficult for us to receive an adequate return on investment.

We compete with many companies possessing greater financial resources and technical facilities for the acquisition of mineral concessions, claims, leases and other mineral interests as well as for the recruitment and retention of qualified employees.

Environmental Regulations

Mineral exploration in the Northwest Territories is governed by Indian and Northern Affairs Canada, a Federal Government office which is responsible for negotiating the development of healthy and sustainable communities on behalf of the First Nation and Inuit peoples. Applicable statutes are the Canadian Environmental Assessment Act (1992) and the Canadian Environmental Protection Act (1999).

In order to conduct exploration on any of our properties, we obtain land use permits. When exploration ceases on a Northwest Territories property, the land affected needs to be reclaimed in order to protect public health and safety, to reduce or prevent environmental degradation and to allow future productive land use of the property.

The reclamation plan for any property is site specific. In general, the reclamation plan consists of ensuring that the physical structures that remain do not impose a long-term hazard to public health and safety and the environment, which includes ensuring that the land and watercourses are returned to a safe and environmentally sound state. We do not anticipate incurring any reclamation costs in connection with our other mineral property interests.

Seasonality

The prevailing climate in the Northwest Territories is severe, with extremely cold and dark winters and short warm summers.  Programs typically are completed between the end of spring thaw and fall/winter freeze-up.  Programs are suspended throughout the winter due to harsh conditions and remote locations.

C.

Organizational Structure

We are not part of a group, nor do we hold any subsidiary companies.

D.

Property, Plant and Equipment

Office Space

We utilize about 1,467 square feet of office space in Vancouver, British Columbia. On April 1, 2006, we entered into a five year lease which expired March 1, 2011.  We are currently renting on a month to month basis, with minimum lease commitments of approximately $4,395.16 per month.  

Oil and Gas Properties

During the year ended November 30, 2010, we made two strategic heavy oil & gas acquisitions in Lloydminster, Alberta and Saskatchewan which expanded our operations from mineral exploration into the oil and natural gas resource sector.

We acquired most of our property interests under two agreements.  The first was an asset purchase agreement with Western Plains Petroleum Ltd. (“Western Plains”) we entered into on or about August 6, 2010 (the "Western Plains Agreement").   Under this agreement, we acquired an undivided 50% interest in properties near the town of Lloydminster, which straddles the Alberta/Saskatchewan border (see map “Property Locations”) including our Western Plains Lloydminster properties in Alberta and our  Landrose, Maidstone, Dee Valley and Hillmond properties in the Province of Saskatchewan, for a cash purchase price of $1.7 million.  

The second agreement was an asset purchase agreement with Western Plains we entered into on or about August 26, 2010, with an effective date of July 1, 2010 (the "Western Plains Nordic Blackfoot Agreement").  Under this agreement, we acquired an undivided 33.33% interest in thirteen (13) crown leases located in the Lloydminster area of Alberta (the "Western Plains Nordic - Blackfoot Properties") for a cash purchase price of $1.467 million.

We subsequently participated with our partners in the drilling and completion of certain wells on the properties, which are described below.  

We currently hold interests in four (4) core producing areas and undeveloped oil and gas properties in the Canadian provinces of Alberta and Saskatchewan, which are described below.  

4

5

Lloydminster Saskatchewan

Maidstone

Maidstone

Landrose

 Lloydminster Nordic

Hillmond

6

Alberta

Western Plains Properties Lloydminster

The Western Plains Lloydminster properties are located in close proximity to the city of Lloydminster in east central Alberta in townships 12-22-49-1W4, 11-12-50-3W4 and 12-04-49-1W4. As of November 30th, 2010, the property consisted of 6 producing oil wells and 3 non-producing wells with Alberta Star having a 50% working interest in approximately 440 acres of land in this area. A combined total of 6 oil wells produce medium- heavy oil from the Sparky formation. In 2010, this area averaged 40 bbls day (20 net to Alberta Star). Oil is transported by a tanker truck to the terminal Lloydminster Blackfoot battery facility and then to the Husky upgrader and pipeline system.

Acquisition and Ownership

We acquired our interest in the Lloydminster- Western Plains on or about August 6, 2010 under the Western Plains Agreement.

We further entered into a joint operating agreement with Western Plains Petroleum Ltd., with respect to the Lloydminster Alberta property and a sub-participation agreement with Arctic Hunter Uranium Inc., providing for Arctic Hunter to pay 100% of the drilling costs, equipment and completion costs with a 100% working interest before payout, reserving a convertible overriding royalty of 10% to Alberta Star and Western Plains.  

Western Plains Nordic- Blackfoot Properties

The Western Plains Nordic -Blackfoot properties consist of 9 shut in wells and 5 drilled cased wells on 27 LSD’s and is located in close proximity to the city of Lloydminster in east central Alberta in townships 06-24-50-2W4 and 06-50-1W4 when purchased in August 2010. As of November 30th, 2010, the property consisted of 14 producing oil wells completed and with Alberta Star having a 33 1/3% working interest in 1,420 acres of land in this area. A combined total of 10 oil wells are now producing medium-heavy oil from the Sparky formation. Oil is transported by a tanker truck to the terminal at the Lloydminster Blackfoot battery facility and then to Husky upgrader and pipeline system for shipment to refineries in the United States Midwest.

Acquisition and Ownership

We acquired our interest in the Western Plains Nordic Blackfoot Properties on or about August 26, 2010, with an effective date of July 1, 2010, under the Blackfoot Agreement. We acquired a net 33^1/3% working interest in certain heavy oil assets located in the Lloydminster, Alberta area, comprised of 1,040 acres (347 net), including 9 shut in heavy oil wells (previously producing) and 5 standing cased wells (previously drilled but not completed). We acquired this interest for a cash purchase price of $1.467 million.

On or about February 16, 2011 we entered into an agreement with Forent Energy Ltd. (“Forent”) to participate in drilling one well on the Blackfoot property, located at 04-02-050-02-W4M.  Under the terms of the agreement, Forent was to be the operator and hold a 50% working interest in the well.  We were required to pay 50% of the cost to drill, complete and equip or abandon the well to earn a 50% net interest before payout, reserving to Sahara Energy Ltd. (“Sahara”) a gross convertible overriding royalty of 15% until payout.  After payout Sahara had the option to convert its gross overriding royalty to a 25% working interest in the well spacing unit.  On April 21, 2011, the agreement was amended to provide that Sahara would be the operator and hold a 50% working interest in the well.  We are required to pay 50% of the cost to drill, complete and equip or abandon the well to earn a 50% working interest, reserving to the Sahara a gross convertible overriding royalty of 15%.

Geology - Lloydminster, Alberta

Hydrocarbons on the Lloydminster, Alberta properties are found accumulated in the Grand Rapids formation of the Upper Mannville Group, principally in the Sparky and Lloydminster Sands.  The Sparky Sand is a clastic unit of Lower Cretaceous age which is formed within a prograding delta environment.  In this area, the gross Sparky Sand thickness is approximately 6m and encountered at approximately 590m.  The Lloydminster Sand is a clastic unit of Lower Cretaceous age which is formed within a shoreline to shallow shelf environment.  In this area, the gross Lloydminster Sand thickness is approximately 10m and encountered at approximately 630m. A detailed description of the wells and interests is presented in Table 2.

Work on the Property

Since acquisition, we have completed and put into production 5 standing cased wells located on the Blackfoot Property, with 3 of the wells being stabilized in aggregate at approximately 75 bbls/d from the Sparky formation.  Subsequent to year end, we announced that we would participate in and be drilling 3 additional wells in the Lloydminster, Alberta area.   

7

 [Insert Diagram - Manville Group (Formations) 3-D Block Diagram]

8

Saskatchewan

Landrose

The Landrose property is located in close proximity to the city of Lloydminster in west central Saskatchewan in township 6-50-25-W4M. As of November 30th, 2010, the property consisted of 2 producing oil wells with Alberta Star having a 50% working interest and 1 producing oil well with 25% working interest in 560 acres of land situated in this area. A combined total of 6 oil wells now produce medium-heavy oil from the McClaren formation.  Oil is transported by a tanker truck to the Blackfoot or Marwain battery’s and then to the terminal Lloydminster Husky upgrader and pipeline system.

During the year ended November 30, 2010, we completed the second of 5 standing cased wells on the property and subsequently entered into a sub-participation agreement with Arctic Hunter. Under the agreement, Arctic Hunter has agreed to participate with us in two (2) test wells by October 31, 2010. Under the agreement, Arctic Hunter must pay 100% of our share of the cost to drill, complete and equip or abandon the test wells to earn a (50% net to Alberta Star) before payout (BPO), reserving to Arctic Star a convertible overriding royalty of 10% until payout. After payout, we have the option to either convert the gross overriding royalty to a 50% working interest (25% net to Alberta Star) in the two test well spacing units or remain in a gross overriding royalty position. Arctic Hunter has no option to drill post-earning wells under the sub-participation agreement.  Western Plains will be the operator of the test wells.

Acquisition and Ownership

We acquired our interest in this property on or about August 6, 2010 under the Western Plains Agreement.  

We own various working and GORR interests in three producing oil wells plus a fifty percent working interest in a three recently drilled wells in this area.  Production is subject to 4^th tier Crown Royalties.

A detailed description of the wells and interests is presented in Table 2.

Geology

Hydrocarbons on the property are found accumulated in the Mannville Group, principally in the McLaren and Waseca Sand units.  The McLaren Member is a clastic unit of lower Cretaceous Age which is formed within a prograding delta environment. In this area, the McLaren Member is approximately 10 metres thick.  The Waseca Sand is a clastic unit of Lower Cretaceous age which is formed within a prograding deltaic environment.  In this area, the Waseca Sand is approximately 40 m. thick.

Maidstone

The Maidstone property is located in close proximity to the city of Lloydminster in west central Saskatchewan in township 01-48-24-W3. As of November 30, 2011 the property consisted of 4 producing oil wells with Alberta Star having a 50% working interest in 160 acres of land in this area. A combined total of 4 oil wells now produce 35 bbls day of medium-heavy oil from the Sparky formation. In 2010, this area averaged 35 bbls day (17.5 net to Alberta Star). Oil is transported by a tanker truck to the Blackfoot or Marwain Battery and then to the Lloydminster Husky upgrader and pipeline system.

Acquisition and Ownership

We acquired our interest in this property on or about August 6, 2010 under the Western Plains Agreement.

Geology

Hydrocarbons on the property are found accumulated in the Grand Rapids formation of the Upper Mannville Group, principally in the Sparky and Lloydminster Sands.  The Sparky Sand is a clastic unit of Lower Cretaceous age which was formed within a pro-grading delta environment.  In this area, the gross Sparky Sand thickness is approximately 6m and encountered at approximately 590m.  The Lloydminster Sand is a clastic unit of Lower Cretaceous age which was formed within a shoreline to shallow shelf environment.  In this area, the gross Lloydminster Sand thickness is approximately 10m and encountered at approximately 630m. A detailed description of the wells and interests is presented in Table 2.

Total gross remaining proved developed producing heavy oil reserves of 255.3  MSTB have been estimated for the Sparky and Lloydminster zones in 18 producing wells based on reservoir parameters derived from log analysis, analogy to Sparky wells in the area, past production performance and recent production.  Total proved developed non-producing heavy oil reserves of 28.8 MSTB have been estimated for the Sparky zone in one stand-by well based on reservoir parameters derived from log analysis and analogy to the producing wells in this area.  Total proved undeveloped heavy oil reserves of 140 MSTB have been assigned to the Sparky zone in seven locations based on analogy to Sparky wells and current successful developments.  Total incremental probable heavy oil reserves of 385.7 MSTB have been assigned to the same Sparky zone.  Thereof, 210.7 MSTB have been assigned to the same proved reserves assuming a better recovery than in the proved case and another 175.0 MSTB to seven future locations.  A summary of reserves is presented in Table 2.  

Production

Total production from the 16 wells in the area currently averages 153 STB/d and is expected to gradually decline to each well’s economic limit.

Dee Valley

The Dee Valley property is located in close proximity to the city of Lloydminster in west central Saskatchewan in township 32-48-22-W3. As of November 30, 2010 the property consisted of 1 producing oil well and 3 non-producing wells with Alberta Star having a 50% working interest in 280.0 acres of land in this area. The single well produces medium- heavy oil from the Sparky formation. In 2010, this area averaged 12 bbls day (6 net to Alberta Star). Oil is transported by a tanker truck to the Blackfoot & Marwain battery’s and then to the Husky upgrader and pipeline system. A detailed description of the wells and interests is presented in Table 2.

Hillmond

The Hillmond property is located in close proximity to the city of Lloydminster in east central Alberta in township 06-51-25-W3. As of November 30, 2010 the property consisted of 1 producing oil well with Alberta Star having a 50% working interest in 40.25 acres of land in this area. The single well produces medium-heavy oil from the Sparky formations. In 2010, this area averaged 12 bbls day (6 net to Alberta Star). Oil is transported by a tanker truck to the Balckfoot or Marwain terminal Lloydminster and then to the Husky upgrader and pipeline system. A detailed description of the wells and interests is presented in Table 2.

Non-Operating (Shut in) Wells

The Company also holds a 50% working interest in 4 properties (Celtic, Celtic, Neilburg, Aberfelty and Lashburn which contain 5 wells, all of which are non-producing or shut in.

Other Oil and Gas Properties

Wells

As at November 30, 2010, we had an interest in 18 gross (7 net) producing and 14 gross (9 net) non producing oil and natural gas wells and 0 gross (0 net) service wells as follows:

Table 1
	PRODUCING				NON-PRODUCING				SERVICE
	Oil		Natural Gas		Oil		Natural Gas		WELLS
Location	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
Alberta	14	5	0	0	7	3	0	0	0	0
Saskatchewan	4	2	0	0	7	6	0	0	0	0
TOTAL	18	7	0	0	14	9	0	0	0	0

A detailed description of the wells and interests are set out below.

Well #	Property	Well UWID	Zone Produced	Interest Held
	Western Plains	5-20-049-01 W4M,	Sparky	50% WI
	Western Plains	12-20-049-01 W4M,	Lloydminster	50% WI
	Western Plains	12-22-049-01 W4M,	Sparky	50% WI
	Western Plains	16-22-049-01 W4M,	Sparky	50% WI
	Western Plains	07-36-048 04  W4M,	Sparky	50% WI
	Western Plains	13-12-050-03- W4M	Sparky	50% WI
1	Blackfoot	10-22-050-02W4M	Lloydminster	33 1/3% WI
2	Blackfoot	09-22-050-02W4M	Sparky	33 1/3% WI
3	Blackfoot	12-14-050-02W4M	Sparky	33 1/3% WI
4	Blackfoot	12-14-050-02W4M	Sparky	33 1/3% WI
5	Blackfoot	13-14-050-02 W4M,	Sparky	33 1/3% WI
6	Blackfoot	16-06-050-01-W4M	Sparky	33 1/3% WI
7	Blackfoot	10-22-050-02-W4M	Sparky	33 1/3% WI
8	Blackfoot	15-14-050-02 W4M,	Sparky	33 1/3% WI
9	Blackfoot	15-06-050-01 W4M,	Sparky	33 1/3% WI
10	Blackfoot	12-14-050-02W4M	Sparky	33 1/3% WI
11	Blackfoot	04-24-050-02W4M	Sparky	33 1/3% WI
12	Blackfoot	10-06-050-01W4M	Sparky	33 1/3% WI
13	Blackfoot	06-24-050-02 W4M,	Sparky	33 1/3% WI
14	Blackfoot	15-14-050-02 W4M	Sparky	33 1/3% WI
15	Blackfoot	15-14-050-01 W4M,	Sparky	33 1/3% WI
2	Landrose	5-06-050-25-W3M	McLaren	50% WI
3	Landrose	6-06-050-25-W3M	McLaren	50% WI
4	Landrose	12-06-050-25-W3M	McLaren	10% GOOR/ Conv. to 25% WI
5	Landrose	11-06-050-25-W3M	McLaren	10% GOOR/ Conv. to 25% WI
6	Landrose	14-06-050-25-W3M	McLaren	10% GOOR/ Conv. to 25% WI
1	Maidstone	10-01-048-24 W3M	Sparky	50% WI
2	Maidstone	15-01-048-24 W3M	Sparky	50% WI
3	Maidstone	16-01-048-24 W3M	Sparky	50% WI
4	Maidstone	09-01-048-24 W3M	Sparky	50% WI
	Dee Valley	14-32-048-22 W3M	Sparky	50% WI
	Hillmond	13-06-051-25 W3M	Sparky	50% WI
	Celtic	01-06-052-23 W3M	Sparky	50% WI
	Neilburg	02-18-045-25 W3M	Sparky	50% WI
	Aberfelty	16-12-050-27 W3M	Sparky	50% WI
	Lashburn NW	13-045-25 W3M	Sparky	50% WI
	Lashburn NE	13-045-25 W3M	Sparky	50% WI

Forward Contracts

We may use certain financial instruments to hedge our exposure to commodity price fluctuations on a portion of our crude oil and natural gas production, however we do not currently have any hedging transactions.

Additional Information Concerning Abandonment and Reclamation Costs

We estimate the costs associated with well abandonment and reclamation cost for surface leases, wells, facility and pipeline based on our previous experience, current regulations, costs, technology and industry standards.  We expect to incur abandonment and reclamation costs on 32 gross wells (16 net), including 2 net non-producing and 0 net service wells.  Our share of the expected total abandonment and reclamation costs for wells with assigned reserves, non-producing and service wells and facilities, net of salvage value are summarized, without discount and using a discount rate of 10%, in the following table:

See:  Statement of Reserve Data and other Oil and Gas Information and “Cautionary Note Regarding Forward looking Statements”.

	Forecast Pricing (M$)
Category	Proved 0%	Proved 10%	Proved Plus Probable 0%	Proved Plus ProbableNPV10%
Wells with reserves assigned(1)	594	316	895	334
Wells with no reserves assigned and facilities(2)	0	0	0	0
Total abandonment and reclamation cost provision	594	316	895	334
Portion forecast to be paid during the next three years	27	21	14	11

Notes:

(1)

Abandonment and reclamation costs were estimated by Chapman and included in the Chapman Report for all wells assigned reserves.

(2)

We estimated the timing and the costs associated with the abandonment and reclamation for wells with no reserves assigned and for facilities.  This represents the total abandonment and reclamation costs that were not deducted in computing future net revenue.

Properties With No Attributed Reserves

We do not have any properties with no attributed reserves.

There are no costs or work commitments associated with our non-producing properties except for annual lease rental payments and abandonment costs.  

See “Statement of Reserve Data and other Gas and Oil Information”.

Tax Horizon

As of November 30, 2010, we had estimated income tax deductions of approximately $16,078,136 per F/S available to reduce future taxable income.  We did not incur current income taxes in 2010.  

Costs Incurred

The following table summarizes our oil and gas property acquisition costs, exploration costs and development costs (before property dispositions) incurred during the financial year ended November 30, 2010:

	Property Acquisitions and Capital Expenditures
Nature of Cost	Amount (M$)
Property Acquisition Costs
Proved	3,165
Unproved
Exploration Costs	441
Development Costs	0
Total	3,606

Exploration and Development Activities

The following table summaries the results of oil and gas exploration and development activities in Canada during the financial year ended November 30, 2010:

	CANADA
Wells Completed in 2010	Gross	Net
Development
Oil	Nil	Nil
Unsuccessful	Nil	Nil
Service	Nil	Nil
Exploratory
Oil	Nil	Nil
Unsuccessful	Nil	Nil
Service	Nil	Nil
Total

Our 2011 Capital Program has been established at $2.5 million which we plan to fund from cash flow from operating activities and bank debt.  Approximately $2.1 million has been (5-6 net to Alberta Star) allocated to exploration and development programs, focused primarily on drilling 10-12 vertical heavy oil wells. The remaining CDN $400,000 has been allocated to upgrade facilities, optimize work-overs – improve production efficiencies and to acquire land. See "Cautionary Note Regarding Forward Looking Statements".

Production History

The following table summarizes our share of average daily production in Canada, before deduction of royalties, for the periods indicated:

	2010
Product	Year	Q4	Q3	Q2	Q1
Heavy Oil (Bbl/d)	2010	55	23	-	-
Total (BOE/d)	2010	55	23	-	-

Note:

Natural gas volume includes associated, non-associated and solution gas.

Netback History

The following table sets forth information respecting average net product prices received, royalties paid, production expenses and operating netbacks received by us in respect of our Canadian production for the periods indicated.

		2010
Category	Year	Q4	Q3
Selling Prices
Heavy Oil ($/Bbl)	2010	64.39	56.83
Royalties
Heavy Oil ($/Bbl)	2010	6.75	7.78
Production Expenses(2)
Heavy Oil ($/Bbl)	2010	43.64	29.22
Operating Netbacks
Heavy Oil ($/Bbl)	2010	$14.00	$18.83
Total (BOE/d)		55	23

Notes:

Natural gas volume includes associated, non-associated and solution gas and coal-bed methane.

Production expenses include petroleum and surface lease rentals, transportation costs, property taxes and expenses related to the operation and maintenance of wells, production facilities and gathering systems.

Production Volume by Field

The following table discloses for each important field, and in total, our production volumes for the financial year ended November 30, 2010 for each product type:

Field	Heavy Oil (Bbl/d)
Alberta
Lloydminster	106
Total Alberta	106
Saskatchewan
Lloydminster	4
Landrose	33
Maidstone	20
Other
Total Saskatchewan	57
Total	163

Note:

Includes associated, non-associated and solution gas and coalbed methane.

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

As a Canadian issuer, our management and directors are required to prepare information with respect to our oil and gas activities in accordance with applicable securities regulatory requirements in Canada under Canadian National Instrument 51 101 –Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).  This information includes reserves data, which are estimates of proved reserves and probable reserves and related future net revenue as at November 30, 2010, estimated using forecast prices and costs.   In compliance with these requirements, management and directors have prepared a report on oil and gas disclosure on Form 51-101F3 and have engaged Chapman Associates Limited ("Chapman") as an independent qualified reserves evaluator, to a report evaluating our reserves data entitled“Alberta Star Development Corp. - Reserve and Economic Evaluation (as of December 1, 2010)” (the “Chapman Report”), effective November 30, 2010, and dated March 14, 2011.  Both reports have been filed with securities regulatory authorities in Canada and with the SEC on Form 6-K.  

We incorporate additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States.  We follow the Canadian practice of reporting gross production and reserve volumes; however, we also follow the US practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments).  We also follow the Canadian practice of using forecast prices and costs when we estimate our reserves.  However, we separately estimate our reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements.  These latter requirements are similar to the average constant pricing reserve methodology utilized in the United States.

We have included estimates of proved and proved plus probably reserves, as well as contingent resources in this Annual Report.

The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated March 28, 2011.  The effective date of the Statement is November 30, 2010 and the preparation date of the Statement is March 28, 2011.

Disclosure of Reserves Data

The reserves data set forth below (the "Reserves Data") is based upon an evaluation by Chapman with an effective date of November 30, 2010 contained in a report of Chapman dated March 28, 2011 (the "Chapman Report").  The Reserves Data the proved and probable reserves attributable to our oil and gas properties and the net present value of estimated future cash flow from such reserves, based on forecast price and cost assumptions. We engaged Chapman to provide an evaluation of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.  Except as noted already,  The Reserves Data conforms with the requirements of Rule 4-10(a) of Regulation S-X. Additional information not required by Rule 4-10(a) has been presented to provide continuity and additional information which we believe is important to the readers of this information.  

All of our reserves are in Canada and, specifically, in the provinces of Alberta and Saskatchewan.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.  There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.  The recovery and reserve estimates of our crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.

See:  Risk Factors “Reserve Estimates” and “Cautionary Note Regarding Forward Looking Statements”.

In certain of the tables set forth below, the columns may not add due to rounding.

SUMMARY OF OIL AND GAS RESERVES as of November 30, 2010 FORECAST PRICES AND COSTS
Reserves Category	Reserves
	Light and Medium Oil		Heavy Oil		Natural Gas(1)		Natural Gas Liquids		Coalbed Methane
	Gross (MSTB)	Net (MSTB)	Gross (MSTB)	Net (MSTB)	Gross (MMscf)	Net (MMscf)	Gross (Mbbl)	Net (Mbbl)	Gross (MMscf)	Net (MMscf)
PROVED
Developed Producing	0	0	114	101	0	0	0	0	0	0
Developed Non-Producing	0	0	30	25	0	0	0	0	0	0
Undeveloped	0	0	47	38	0	0	0	0	0	0
TOTAL PROVED	0	0	190	164	0	0	0	0	0	0
Probable	0	0	343	294	0	0	0	0	0	0
TOTAL PROVED PLUS PROBABLE	0	0	533	457	0	0	0	0	0	0

Note:Natural gas volumes include associated, non-associated and solution gas but not coalbed methane.

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE as of November 30, 2010
				Net Present Values of Future Net Revenue
				Before Income Tax Discounted at										After Income Tax Discounted at
				0%/yr		5%/yr.		10%/yr.		15%/yr.		20%/yr.		0%/yr		5%/yr.		10%/yr.		15%/yr.		20%/yr.
Reserves Category				$M		$M		$M		$M		$M		$M		$M		$M		$M		$M
PROVED
Developed Producing				4,237		3,666		3,246		2,925		2,671		4,237		3,666		3,246		2,925		2,671
Developed Non-Producing				1,274		1,175		1,094		1,026		969		1,274		1,175		1,094		1,026		969
Undeveloped				1,004		792		623		487		376		1,004		792		623		487		376
TOTAL PROVED				6,515		5,633		4,963		4,438		4,017		6,515		5,633		4,963		4,438		4,017
TOTAL PROBABLE				14,383		10,719		8,309		6,626		5,400		13,080		9,842		7,699		6,190		5,080
TOTAL PROVED + PROBABLE				20,899		16,352		13,272		11,065		9,417		19,595		15,476		12,662		10,629		9,097
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) As of November 30, 2010 FORECAST PRICES AND COSTS
Reserves Category		Revenue (M$)			Royalties (M$)		Operating Costs (M$)		Development Costs (M$)		Well Abandonment Reclamation and Costs (M$)				Future Net Revenue Before Income Taxes (M$)		Future Income Taxes and Expenses (M$)				Future Net Revenue After Deducting Income Taxes (M$)
PROVED
Developed Producing		9,157			1,151		3,316		10		442				4,238		0				4,238
Developed Non- Producing		2,192			364		476		34		44				1,274		0				1,274
Undeveloped		3,658			660		971		916		108				1,003		0				1,003
TOTAL PROVED		15,007			2,175		4,763		960		594				6,515		0				6,515
Probable		28,392			4,021		7,581		2,106		301				14,385		(1,303)				13,080
TOTAL PROVED PLUS PROBABLE		43,399			6,196		12,344		3,066		895				20,899		(1,303)				19,595
	FUTURE NET REVENUE BY PRODUCTION GROUP as of November 30, 2010 FORECAST PRICES AND COSTS
	RESERVES CATEGORY		PRODUCTION GROUP										FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year) (M$)						FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year) ($/MCF) ($/BBL)
	PROVED		Light and Medium Oil (including solution gas and associated by products)										0						0
			Heavy Oil (including solution gas and other associated by products)										4,963						26.06
			Natural Gas (including associated by-products but excluding solution gas and by-products from oil wells)										0						0
			Coalbed Methane (including associated by-products)										0						0
			Non-Conventional Oil & Gas Activities (excluding coalbed methane)										0						0
			Total
	PROVED PLUS PROBABLE		Light and Medium Oil (including solution gas and associated by products)										0						0
			Heavy Oil (including solution gas and associated by-products)										13,272						24.90
			Natural Gas (including associated by-products but excluding solution gas and by-products from oil wells)										0						0
			Coalbed Methane (including associated by-products)										0						0
			Non-Conventional Oil & Gas Activities (excluding coalbed methane)										0						0
			Total										13,272						0

PRICING ASSUMPTIONS

Chapman employed the following pricing, exchange rate and inflation rate assumptions in estimating our reserves data using forecast prices and costs as of December 1, 2010.

		Alberta	Alberta	Sask.	Sask.	B.C.
	WTI [1]	Par Price [2]	Heavy [3]	Light [4]	Heavy [5]	Light [6]
Date	$US/STB	$CDN/STB	$CDN/STB	$CDN/STB	$CDN/STB	$CDN/STB
HISTORICAL PRICES
2000	30.39	44.90	34.51	43.37	40.12	n/a
2001	25.98	39.66	25.41	35.57	31.84	n/a
2002	26.09	40.63	32.20	37.67	34.57	n/a
2003	30.84	43.57	32.65	40.13	37.64	n/a
2004	41.48	52.89	37.52	48.96	45.74	n/a
2005	56.62	69.16	43.25	62.04	56.53	n/a
2006	65.91	72.88	50.40	66.77	61.23	n/a
2007	70.61	75.57	53.17	71.42	64.55	n/a
2008	99.70	102.98	83.88	98.02	92.45	n/a
2009	61.64	68.91	58.48	65.15	63.48	n/a
2010 (11 mos)	81.01	79.97	66.18	76.27	72.19	n/a
CONSTANT PRICES
November 30, 2010 [7]	84.11	85.10	71.50	85.55	79.82	82.97
CURRENT YEAR FORECAST
2010 (1 mos)	80.00	83.21	70.31	78.38	75.17	81.13
FUTURE FORECAST
2011	83.00	86.37	72.98	81.36	78.02	84.21
2012	86.00	89.53	75.65	84.33	80.88	87.29
2013	90.00	93.74	79.21	88.30	84.68	91.39
2014	93.00	96.89	81.88	91.27	87.53	94.47
2015	96.00	100.05	84.54	94.25	90.39	97.55
2016	98.00	102.16	86.32	96.23	92.29	99.60
2017	100.00	104.26	88.10	98.22	94.19	101.66
2018	102.00	106.37	89.88	100.20	96.09	103.71
2019	104.04	108.52	91.70	102.22	98.03	105.80
2020	106.12	110.71	93.55	104.29	100.01	107.94
2021	108.24	112.94	95.43	106.39	102.03	110.12
2022	110.41	115.22	97.36	108.54	104.09	112.34
2023	112.62	117.54	99.32	110.73	106.19	114.60
2024	114.87	119.91	101.33	112.96	108.33	116.92
2025	117.17	122.33	103.37	115.24	110.51	119.27
Constant thereafter

Notes:

[1]

West Texas Intermediate quality (D2/S2) crude landed in Cushing, Oklahoma.

[2]

Equivalent price for Light Sweet Crude (D2/S2) landed in Edmonton, Alberta after exchange of 0.95US$/C$ from 2010 to  2025 during forecasting period and transportation differential of $1.00 CDN/STB.

[3]

Bow River at Hardisty, Alberta (905 kg/m3, 2.1% sulphur).

[4]

Light Sour Blend at Cromer, Saskatchewan (880 kg/m3, 2.0% sulphur).

[5]

Midale at Cromer, Saskatchewan (880 kg/m3, 2.0% sulphur).

[6]

B.C. Light at Taylor, British Columbia (825 kg/m3, 0.5% sulphur).

[7]

November 30, 2010 is the last trading day of November 2010.

Our weighted average realized sales prices for the year ended November 30, 2010 were $56.90 /bbl for heavy oil.

Reserves Reconciliation

The following tables set forth a reconciliation of our total gross proved, probable and proved plus probable reserves as at November 30, 2010 against such reserves as at November 30, 2009 based on forecast price and cost assumptions:

	LIGHT AND MEDIUM OIL			HEAVY OIL			NATURAL GAS(1)
FACTORS	Gross Proved (Mbbl)	Gross Probable (Mbbl)	Gross Proved Plus Probable (Mbbl)	Gross Proved (Mbbl)	Gross Probable (Mbbl)	Gross Proved Plus Probable (Mbbl)	Gross Proved (MMcf)	Gross Probable (MMcf)	Gross Proved Plus Probable (MMcf)
November 30, 2009	0	0	0	0	0	0	0	0	0
Acquisitions				203	447	649
Discoveries	0	0	0	0	0	0	0	0	0
Dispositions	0	0	0	0	(120)	(120)	0	0	0
Extensions and Improved Recovery	0	0	0	20	40	60	0	0	0
Technical Revisions(2)	0	0	0	12	(23)	(10)	0	0	0
Economic Factors	0	0	0	0	0	0	0	0	0
Gross Production	0	0	0	43	0	43	0	0	0
November 30, 2010	0	0	0	192	344	536	0	0	0

Notes:

(1) Natural gas volumes include associated, non-associated and solution gas but does not include coal-bed methane.

(2) Technical revisions to reserve volumes for November 30, 2010.

ADDITIONAL INFORMATION RELATING TO RESERVES DATA

Proved Undeveloped Reserves and Probable Undeveloped Reserves

Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year or wells further away from our gathering systems. In addition, such reserves may relate to planned infill drilling locations. These reserves are planned to be on stream within a two year timeframe.

Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. These reserves are planned to be on stream within a two year timeframe.  See:  “Risk Factors – Reserve Estimates” and “Cautionary Notes Regarding Forward Looking Statements”.

The following provides the gross volumes of proved undeveloped reserves and probable undeveloped reserves of we that were first attributed and booked in each of our most recent three financial years ending on the date of the Chapman Report, and in the aggregate, before that time:

TOTAL CORPORATION
TIME PERIOD	LIGHT AND MEDIUM OIL				HEAVY OIL				NATURAL GAS LIQUIDS				NATURAL GAS				COAL BED METHANE
	(Mbbl)				(Mbbl)				(Mbbl)				(Mmcf)				(Mmcf)
	PROVED		PROBABLE		PROVED		PROBABLE		PROVED		PROBABLE		PROVED		PROBABLE		PROVED		PROBABLE
	A*	B*	A*	B*	A*	B*	A*	B*	A*	B*	A*	B*	A*	B*	A*	B*	A*	B*	A*	B*
2010	0	0	0	0	47	47	343	343	0	0	0	0	0	0	0	0	0	0	0	0
2009	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
2008	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0
Prior to 2007	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0	0

Notes:

“A*” - First Attributed

“B*”  - Booked

Production Estimates

The following tables disclose the estimated average daily production for 2011 for each product type associated with the first year of the gross proved reserves and gross probable reserves reported in the Chapman Report effective November 30, 2010, based on forecast prices and costs:

Corporation	Light/Medium Oil (Bbl/d)	Heavy Oil (Bbl/d)	Natural Gas(1) (Mcf/d)	Natural Gas Liquids (Bbl/d)	Coal-Bed Methane (Mcf/d)	Combined (BOE/d)
Proved Developed Producing	-	188	-	-	-	188
Developed Non-Producing and Undeveloped	-	13	-	-	-	13
Total Proved	-	201	-	-	-	201
Probable	-	44	-	-	-	44
Total Proved Plus Probable	-	245	-	-	-	245

Note:Natural gas volume includes associated and non-associated gas.

Significant Factors or Uncertainties Affecting Reserves Data

The process of estimating reserves is complex. It requires significant judgment and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, commodity prices and economic conditions. Our reserves are evaluated by Chapman, an independent engineering firm.

Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, commodity prices, economic conditions and governmental restrictions.  Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science.  Our actual production, revenues, taxes, development and operating expenditures with respect to our reserves may vary from such estimates, and such variances could be material.

See:  “Risk Factors – Reserve Estimates” and “Cautionary Notes Regarding Forward Looking Statements”.

Future Development Costs

The following table outlines development costs deducted in the estimation of future net revenue attributable to proved reserves and proved plus probable reserves using forecast prices and costs:

	Canada
Year	Proved Reserves (M$)	Proved Plus Probable Reserves (M$)
2011	950	2,606
2012	0	0
2013	0	0
2014	0	0
2015	0	0
Remaining Years	0	0
Total Undiscounted	950	2,606

We have established a $2.5 million capital program (the “2011 Capital Program”) to fund our exploration and development activities for 2011 of which $2.1 million is budgeted for drilling, completing and equipping an estimated 10-12 wells (5-6 net to us) in Alberta and Saskatchewan. The 2011 Capital Program does not include any new acquisition opportunities, which we believe will likely be financed through debt or equity financings.

We estimate that our internally generated cash flow and unused bank credit facilities are sufficient to fund the future development costs disclosed above. We typically have available three sources of funding to finance our capital expenditure program: internally generated cash flow from operating activities, debt financing when appropriate and new equity issues, if available on favourable terms. See:  “Cautionary Notes Regarding Forward Looking Statements”.

Mineral Properties

We are engaged in the acquisition and exploration of mineral property interests in Canada, and specifically hold all of our current mineral property interests within the Northwest Territories, Canada (Figures 1 and 2). What follows is a description of our current and former properties, including information on expenses for the years ended November 30, 2010, and, if applicable, November 30, 2009 and 2008. We are not planning to complete any exploration work on our mineral properties in the upcoming fiscal year.

We are an exploration stage company and have no mineral producing properties at this time.  All of our properties are exploration projects, and we receive no revenues from production.  All work presently planned by us is directed at defining mineralization and increasing understanding of the characteristics and economics of that mineralization.  There is no assurance that a commercially viable mineral deposit exists in any of our properties nor do we anticipate same until after completion of further exploration work and a comprehensive evaluation based upon unit cost, grade, recoveries and other factors conclude economic feasibility.  The information contained herein respecting our mineral properties is based upon information reviewed by Dr. Michael Bersch, LPG, CPG.  Dr. Bersch is a “qualified person” pursuant to NI 43-101 concerning standards of disclosure for mineral projects.

10

Figures1&2

11

Eldorado-Contact Lake Area Geological Setting

Regional Geology

Adapted from Hildebrand, 1981; Hildebrand et al.1987; and Hoffman and Hall, 1993

The Eldorado-Echo Bay Project is located in the northern portion of the Great Bear Magmatic Zone (GBMZ), part of the Bear Structural Province of the Canadian Shield (Figure 3).  The Bear province covers some 40,000 square kilometres (100 x 400 km) and consists of the gneissic Coronation Geosyncline to the east, and the GBMZ to the west, with the long-lived, polyphase Wopmay Deformation Zone (WDZ) separating the two terranes (Hildebrand, 1986) (Figure 4).  This orogenic zone developed on the western side of the Archean Slave craton between 2.1 and 1.8 Ga. Hoffman (1980a) divided the Wopmay Deformation Zone into four distinct tectonic zones: (1) a thin autochthonous cratonic cover and foreland basal sequence overlies the northwestern area of the Slave Craton (2) the Asiak fold and thrust belt of continental shelf and carbonate sequences overthrust on the Craton (3) the Hepburn orthotectonic zone of deformed rift sediment-volcanic sequences intruded by post tectonic S-type plutons (4) the little deformed GBMZ, of subgreenschist facies volcano-sedimentary sequences intruded by I-type plutons. The GBMZ is on lapped by platformal Paleozoic cover sequences to the west.  The Eldorado-Echo Bay Property is situated in the western part of the GBMZ.

The Hottah Terrane is a basement continental calc-alkaline volcano-plutonic arc and associated sedimentary rocks which formed above an eastward subducting plate along the western margin of the Slave Province (Hildebrand et al. 1987; Clowes, 1997).  The volcano-sedimentary rocks of this terrane were cut by calc-alkaline biotite-hornblende bearing plutons with ages ranging from 1.914 Ga to 1.902 Ga.  A depositional prism of geosynclinal shelf and slope sediments (Epworth, Snare and Akaitcho Groups) of the Coronation Supergroup formed at the edge of the continental margin and at about 1.90 Ga, arc magmatism stopped and a bimodal suite of submarine volcanic rocks erupted onto the block faulted and subsided sediments of the margin.  This tectono-magmatic episode lasted only 5-10 Ma, related to intra-arc extension which also generated a marginal basin originally to the east of the Hottah arc. The basin filled with siliciclastic and carbonate rocks overlying the volcanic succession and lapping on to the Slave Craton to the east.

Within 5-10 Ma, the sedimentary basin was simultaneously shortened and intruded by peraluminous to metalumious plutons of the Hepburn intrusive suite (1.896-1.879 Ma).  The shortening resulted in detachment and eastward thrusting of the imbricated basinal sediments into the Calderian accretionary wedge forming the Asiak Fold belt in the east and the Hepburn plutonic and metamorphic zone (Turmoil Klippe) in the west part of the former basin.  As the hot plutons of the Hepburn suite were emplaced over the colder authochton of the western Slave Craton, inverted metamorphic isograds developed.

The 1.878 Ga closure of the marginal basin resulted in the initiation and growth of the 1.876 -1.850 Ga continental, arc complex of the GBMZ at the suture between the Hottah arc to the west and the Hepburn suite to the east.  The Great Bear Magmatic Zone is a 100 x 400 km wide corridor which is the product of the final stages of continental volcanism and related plutonic activity.

It consists of low titanium/high aluminum calc-alkaline volcano-plutonic rocks which have been intruded by a suite of hornblende and biotite bearing plutons of similar age (Hoffman and Bowring, 1984; Hildebrand and Bowring, 1084).  The thick supracrustal sequences are referred to as the McTavish Supergroup, and consist of sub-greenschist facies, calc-alkaline andesitic to rhyolitic volcanic, volcaniclastic and sedimentary rocks, which have been interpreted as remnants of ancient stratovolcanoes and the products of caldera collapse (Hildebrand, 1984).

The occurrence of these sequences as isolated roof pendants within larger batholiths of the GBMZ hinders regional stratigraphic correlations between widely spaced regions.  The northern part of the GBMZ is underlain by a 10 km thick section of supracrustal rocks of the MacTavish Supergroup, which comprises three Groups: the Labine, Dumas and Sloan, in ascending order.  The southern part of the GBMZ is underlain by a 5 km thick section of the Faber Group, which has been interpreted as broadly correlatable with the Sloan Group.  These units occupy the central core of the GBMZ, and are flanked to the west and east, by rocks of the Labine and Dumas Groups, respectively. Cannuli (1989) also suggested that the Labine and Dumas may be broadly correlative and that the distribution of supracrustal sequences define a regional scale syncline within the GBMZ volcano-plutonic complex.  Ghandi (1994) noted that synvolcanic quartz monzonitic plutons within the stratigraphy of both the Labine and Faber Groups were closely coeval; however, the predominantly basaltic and less andesitic strata of the Labine Group contrasts with the more felsic strata of the Faber and Sloan Groups.  The Faber Group volcanic sequences were suggested to be texturally and chemically similar to products formed in anorogenic extensional settings, such as in the Missouri granite-rhyolite terrane and the Gawler ranges of South Australia, rather than a subduction setting (Ghandi, 1994).

The Labine Group, which represents the main magmatic arc in the western part of the GBMZ, consists of a 7 km thick section of volcanic-derived rocks which is exposed in the Port Radium-Echo Bay area.  The Labine Group consists of the lower Port Radium Formation and the overlying Echo Bay and Cameron Bay Formations, which collectively define a minimum of two caldera collapse sequences.  The rocks of the Labine Group have been intruded along a minimum of two stratigraphic levels, by intermediate plutons and largely concordant sills of the Mystery Island Intrusive Complex.  The lower sheet includes the Bertrand and Mystery Island plutons and the upper sheet includes the Contact Lake and Glacier/Tut plutons.  These intrusive typically have pronounced zoned alteration haloes within the intrusions and/or their flanking host rocks.  Large, felsic syn- to post-volcanic, granite to monzonite plutons of the Great Bear batholith also intrude this sequence.  These intrusions have locally developed hornfels aureoles but lack the strong alteration associated with the earlier intermediate sills.

The cessation of volcanism in the GBMZ may have been the result of subduction of an oceanic spreading ridge or other high topographic features such as remnant arcs.  Gravity studies have suggested the presence of another arc further to the west (Fort Simpson arc) existed on the western side of the ocean, and now under Paleozoic cover.  The cessation of arc magmatism due to ridge subduction is common to Mesozoic-Cenozoic volcanic arcs worldwide, such as in South America, where the Chile Rise and Nazca Ridge were subducted into the Peru-Chile Trench and in California, where the East Pacific Rise was subducted under North America (Hildebrand, et al. 1987).  Such an event may also have resulted in a change in plate motion in the GBMZ, to transpression (dextral wrenching) and folding oblique to the original subduction direction (Bowring, 1984).  As a result, the concordant plutons and their host rocks were folded around northwest trending axes at about 1.843 Ga (Bowring, 1984), exposing the plutons and their altered wall rocks in oblique cross-section.

Post-dating the development of the northwest trending folds, large, discordant, epizonal, biotite bearing granites and quartz diorites were emplaced between about 1.858 and 1.843 Ga (Bowring and van Schmus, 1987), formed as a result of melting due to crustal thickening from folding (Hildebrand et al, 1987).  Bodies of this syenogranitic suite are also offset by continued movement on a swarm of later transcurrent, predominantly north to northeast trending faults.  These structures were developed as a result of east-west shortening which generated the northeast trending, dextral strike-slip structures (Hoffman, 1980; Hildebrand et al., 1987).  Evidence of plutonism in this setting is noted as swarms of related northeast trending dykes.

Movement on these northeast faults is related to displacement on north-south, transcurrent fault zones, parallel to the Wopmay Deformation Zone.  Displacement along these structures continued after the development of the igneous and sedimentary rock assemblages in the GBMZ, commonly resulting in kilometre scale offset of units.

The northeast trending faults are also cut by Cleaver diabase (Hoffman, 1984; Hildebrand, 1982), and both are unconformably overlain by the sedimentary basin of the 1.663 Ga Hornby Bay Group (McGrath and Hildebrand, 1984; Bowring and Ross, 1985).  Hildebrand (1988) noted that many of the northeasterly faults were reactivated during a period of normal faulting which occurred during the late stages of, or after, the deposition of the Hornby Bay Group (Hildebrand, 1988). Gabbro sills known as Western Channel diabase are considered to be the youngest rocks in the area (Hildebrand, 1982).

12

Figure 3

13

Figure 4

14

Local Geology

Adapted from Hoffman & McGlynn, 1977; Hildebrand, 1981; Reardon, 1992; Robinson & Ohmoto, 1971.  The geology of the Eldorada-Contact Lake area, as shown inFigure 5, has been compiled from mapping completed by Hildebrand, 1981, and Reardon, 1992.

Figure 5

15

Stratigraphy

The Port Radium-Echo Bay area is underlain by volcano-sedimentary rocks of the Labine Group, which is subdivided into 3 main formations: Port Radium, Echo Bay, Cameron Bay.  These are further subdivided into members which represent two main eruptive caldera phases: an early phase characterized by relatively gas-poor eruptions of andesitic lavas (Port Radium and Echo Bay Formations) and a younger, more gas-charged phase of voluminous siliceous volcanics and volcaniclastics (within the Cameron Bay and Feniak Formations) (Hildebrand, 1981).  The stratigraphy can be locally isolated into distinct calderas, 3 to 5 km in diameter.  The two cycles of caldera collapse, resurgence and intermediate plutonism are characterized by cone facies andesite, marr diatreme breccias and caldera fill sediments.

Lithogeochemical studies indicate that the Labine sequence is high in potassium (K), calc-alkaline belt of stratavolcanoes similar to Andean continental arc sequences (Ewart and LeMaitre, 1980). The sequence has only been subjected to low grade metamorphism (zeolite facies), with local contact metamorphic effects (i.e. hornfels) noted in supracrustal rocks flanking large plutons of the Great Bear Batholith series.

The Eldorado & Contact Lake IOCG & Uranium Projects 2010 Explorations Program

Management has determined that due to the remote location of the projects, high cost of exploration in Canada’s far north and other factors, no further work will be planned for the 2011 field season.

Mineral Claim and Lease Claim Payments in the Northwest Territories

In order to retain property title or mineral claims in the Northwest Territories, we must complete and file assessment work of at least $4 per acre during the two-year period immediately following the date the claim is recorded.  In respect to the representation of work, the types of undertakings on the claims are as follows:

·

Drilling

·

Trenching

·

Sinking shafts

·

Geochemical and geophysical investigation made on the ground or by aircraft

·

Surveyor claims must be proved by the surveyor general

·

Work done in constructing roads and airstrips

We must pay annual payments to the federal government in order to maintain lease claims.

There is no electricity available at the Northwest Territories property sites, with surface water abundant within the property boundaries.

Contact Lake Mineral Claims – Contact Lake, NT (Eldorado-Contact Lake Project)

During the year ended November 30, 2005, we acquired a 100% undivided right, title and interest, subject to a 1% net smelter return royalty (“NSR”), in five (5) mineral claims, totalling 1,801.82 ha (4,450.50 acres) located five miles southeast of Port Radium on Great Bear Lake, NT for cash payments of $60,000 (paid) and 60,000 of our common shares (issued and valued at $72,000).  We may purchase the NSR for a one-time payment of $1,000,000.  We completed additional staking in the area in order to increase the project size to sixteen (16) contiguous claims, totalling 10,563.76 ha (26,103.52 acres).  Collectively, the properties are known as the Contact Lake Mineral Claims. (Figure 6).

The area has traditionally been underexplored, but encompasses a mineral rich portion of the Great Bear Magmatic Zone, and includes the Contact Lake Mineral Belt itself, approximately 15 km long.

A summary of our claims can be found below:

Name	Tag Number	Size (ha)
BEN 1	F91861	1,003.30
BEN 2	F91862	752.47
BON 1	F91863	1,003.30
BON 2	F91864	1,003.30
BON 3	F91865	1,003.30
COBALT 1	F91852	1,045.10
COBALT 2	F91853	1,045.10
COBALT 3	F91854	418.04
COBALT 4	F91855	250.82
COBALT 5	F91856	752.47
COBALT 6	F91857	522.53
Lease # 4748		554.82
Lease # 4749		533.38
Lease # 4750		346.01
Lease # 4751		227.03
Lease # 4752		102.79
		10,563.76

16

Figure 6

17

Our expenditures related to the Contact Lake Mineral Claims can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Amortization		322,489		50,327		65,497		122,091
Assaying and geochemical		413,031		125		1,097		93,816
Camp costs and field supplies		1,554,662		4,845		120,468		141,074
Claim maintenance and permitting		88,613		826		260		4,544
Community relations and government		215,000		-		19,153		70,930
Drilling		3,318,148		-		12,304		105,994
Equipment rental		200,831		-		-		3,750
Geology and engineering		680,644		15,521		28,682		227,902
Geophysics		16,643		-		-		16,643
Ortho-photography		199,451		-		-		-
Staking and line cutting		339,160		-		6,500		-
Surveying		1,473,493		-		-		-
Transportation and fuel		4,938,609		-		212,326		289,276
Wages, consulting and management fees		4,545,567		11,898		626,682		771,526
Write down of field equipment		209,831		209,831		-		-
		18,516,172		293,373		1,092,969		1,847,546
Acquisition of mineral property interests		132,000		-		-		-
		18,648,172		293,373		1,092,969		1,847,546

Accessibility, Local Resources and Infrastructure

The best access to the area is from Yellowknife, NT, using charter fixed wing aircraft which can land at the 900 meter long unmaintained gravel airstrip at the western shore of Glacier Lake, which lies in the centre of the Eldorado-Contact Lake Project area.  A road extends west from the airstrip to the area of the Echo Bay and Eldorado Mines.  Bulk freight has also previously been mobilized by seasonal barging along the Mackenzie River, from Alberta to Tulita (Fort Norman), NT, on the western shore of Great Bear Lake.  When mining was active in the area, a barge service also operated along the Bear River from Tulita to Deline, and across Great Bear Lake to the various mining operations. Lake barging service is in limited operation.

Currently, the Northwest Territories Department of Transport maintains a winter road from Yellowknife to Rae-Edzo and beyond, to Rae Lakes which is approximately 100 km south of the property.  Recent records indicate that local conditions have allowed this road to be open for a period of approximately 6 weeks, from mid- February to late March/early April.  During operation of the silver mines at Camsell River and Echo Bay prior to 1984, the winter road was extended to Port Radium, via Marian Lake and Camsell River.

Although the area immediately surrounding the property lacks any significant infrastructure, logistical support and supplies are available from Yellowknife.  There is no electricity available at the property site, but surface water is abundant within the property boundaries.  Established fishing camps on the eastern side of Great Bear Lake also provide some support.  The town of Yellowknife has a long history of mining, where the services of many experienced explorers can be obtained.  As well, personnel may be available from several smaller communities within the Great Bear Lake area.

18

In 2006, we undertook a successful exploratory drill program (Phase 1) on our Eldorado & Contact Lake Projects.  From June to October, 2006, 14,475 metres of NQ drill core was recovered, and 6,470 samples including 289 standards were assayed.  The 2006 drill program targeted seven areas, 1) the K2 area in which there is a low-grade Cu+ Co, Au and Ag mineralized breccia system that has strong affinities to an IOCG system, 2) the Echo Bay gossan at the end of the southeast arm of Echo Bay which marks the location of a newly discovered silver zone; 3) a high-grade Cu-Ag-Mo-Zn-Pb-W mineralized hydrothermal breccia at Mile Lake, 4) uranium, nickel, cobalt and silver mineralized zones adjacent to the past producing Eldorado mine site, 5) uranium, nickel, cobalt and silver mineralized zones adjacent to the past producing Echo Bay mine site, 6) an area centered on a strong VTEM plus magnetic anomaly near the southeast end of Echo Bay; and 7) the Thompson Showing of a high-grade Cu-Ag-Co-Ni-Au-U polymetallic vein.  

In 2007, we completed Phase 2 of the exploratory drill program based on the preliminary investigations from the 2006 drill program at the Eldorado & Contact Lake Project areas.  Our two base exploration camps, personnel and supporting infrastructures were fully operational from May to October, 2007.  We completed almost 20,000 meters of drilling in 72 drill holes and collected over 10,000 surface samples.  The 2007 drill program targeted ten areas; K2, Echo Bay South, Mag Hill, Glacier Creek, Breccia Island, Camelback, Skinny Lake and Contact Lake, located on the Contact Lake Mineral Claims and Eldorado and Echo Bay, located on the Glacier Lake Mineral Claims.  

In 2008, we targeted five areas on our Eldorado-Contact Lake Project for further exploration drilling: K2, Skinny Lake, K4, Long Bay, and Gossan Island.  

In 2009, because of the significant decline in the price of uranium, coupled with the very high cost of exploration cost in the Northwest Territories, we carried out no on-site exploration activities, demobilized the field camp and placed it in storage and completed a review and summary report.

We have no work planned for these properties in 2011.

19

Port Radium – Glacier Lake Mineral Leases, NT (Eldorado-Contact Lake Project)

In 2005, we acquired a 100% undivided right, title and interest, subject to a 2% NSR in four (4) mineral leases, totalling 2,520.78 ha (6,229.00 acres) (the “Glacier Lake Mineral Leases”) located one mile east of Port Radium on Great Bear Lake, NT.  for cash payments of $30,000 (paid) and 72,000 of our common shares (issued and valued at $72,000).  We may purchase one-half of the NSR for a one-time payment of $1,000,000.

The Echo Bay lease (produced 23,779,178 ounces of silver) and the Port Radium – Eldorado lease (produced 15 million pounds of uranium and 8 million ounces of silver).  The Port Radium uranium belt was formerly one of Canada’s principal producers of Pitchblende uranium during the 1930s and 1940s.

A summary of our claims can be found below:

Name	Size (ha)
Lease # 4815	843.77
Lease # 4816	104.81
Lease # 4817	872.50
Lease # 4818	699.70
	2,520.78

Figure 8

20

Our expenditures related to the Port Radium – Glacier Lake Mineral Leases can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Amortization		33,444		6,550		8,371		10,727
Assaying and geochemical		197,313		-		-		54,136
Camp costs and field supplies		383,489		-		-		1,178
Claim maintenance and permitting		20,648		1,050		6,227		6,241
Community relations and government		21,472		-		-		-
Drilling		758,681		-		-		-
Equipment rental		58,038		-		-		-
Geology and engineering		69,879		-		-		36,206
Metallurgical studies		62,977		-		-		-
Ortho-photography		25,522		-		-		-
Staking and line cutting		88,335		-		-		-
Surveying		17,309		-		-		-
Transportation and fuel		5,029,890		-		-		344,031
Wages, consulting and management fees		840,723		-		-		159,905
Write down of field equipment		11,039		11,039		-		-
		7,618,759		18,639		14,598		612,424
Acquisition of mineral property interests		102,000		-		-		-
Recovery of mineral property costs		(603,750)		-		-		-
		7,117,009		18,639		14,598		612,424

21

Figure 9

22

Eldorado South IOCG & Uranium Project, NT (Eldorado South Project)

During the year ended November 30, 2007, we staked sixteen (16) claims (the “Eldorado South Uranium Mineral Claims”), and four (4) additional claims (the “Eldorado West Uranium Mineral Claims”) located ten miles south of Eldorado uranium mine on the east side of Great Bear Lake, NT and 680 km (423 miles) north of the city of Yellowknife, NT, collectively known as the Eldorado South Uranium Project.  During the year ended November 30, 2009, fourteen claims were allowed to lapse.  The Eldorado South Uranium Project now consists of sixteen (16) mineral claims totalling 11,281.85 ha (27,878.62 acres) (Figure 10).

The Eldorado South claims cover a radiometric anomaly that is over 3.5 kilometers in length and the expression suggests a potential near surface IOCG & uranium target.  The radiometric maps show a well defined uranium anomaly with a marked correlation of strong thorium (Th) and potassium (k) ratio patterns.  The Eldorado South Anomaly has never been drill tested.  The Eldorado South Anomaly was discovered in 2006 as a result of the completion of a High Resolution, Multi-Parameter Regional radiometric and magnetic geophysical survey which was conducted in July, 2006.  The survey consisted of 16,708 line-kilometers at 100 meter line-spacing’s.  The purpose of the radiometric survey was to measure the gamma radiation field and locate prospective areas of high-grade uranium and poly-metallic deposition.

In December 2007, the Deline Land Corporation passed a resolution placing a moratorium on any further uranium exploration and development on Deline District lands.  The Deline Land Corporation has stated publicly and reiterated that all current agreements between the Deline Land Corporation and the Company would be fully honored.  Several uranium mining moratoriums have been placed in several mining jurisdictions in Canada recently.  They include a three year moratorium on uranium mining in Labrador (April 2008) and a moratorium issued in the Deline District (January 2008) in the Northwest Territories stating that they will not approve or consent to new uranium exploration or development until the 26 recommendations of the Canada-Deline Uranium Table have been addressed to the satisfaction of the leadership of the local community.  The moratoriums do not apply to exploration for other minerals and mineral exploration activity is expected to continue in full force.  

On June 16, 2008, we completed our Community Consultation in the community of Deline and finalized an expanded TEK (Traditional Education Knowledge) study for the region.  Our Land-Use permit application #SO7C-008 was deemed completed by the Sahtu Land and Water Board.

On July 14, 2008, we received final permit approval from the Sahtu Land and Water Board (SLWB) for the issuance of a third “Class A”- 5 year 75,000 meter drill permit (#S07C-008) for our Eldorado South Iron oxide, copper, gold, silver, and uranium project located in Canada’s Northwest Territories. The Eldorado South permit (#S07C-008) is valid until July 10, 2013.  

We completed a comprehensive First Nations Traditional Educational Knowledge Report for this region which was completed to the satisfaction of the Deline Land Corporation and the Community of Deline.  We intends to further expand wildlife and environmental programs and baseline studies in the Eldorado & Contact Lake uranium districts as the projects advance.  On December 19, 2005 we signed a 5 Year Cooperation, Access and Benefits Agreement with the Deline Land Corp and the Sahtu Dene & Metis for the eastern Great Bear Lake Region.  

In our effort to maintain strong relations and an ongoing working relationship with the Deline Land Corp. and the people of Sahtu-Dene First Nations peoples living in Deline, we visited and participated in a comprehensive Community Consultation on June 18, 2008 in the community of Deline, NT.  We made a detailed presentation to the community of the  results of our 2007 exploration & drilling program and our future plans for expanded exploration and drilling in the 2008 season.  We addressed various environmental issues, environmental best practices management strategy, sustainable development philosophy and our policy of First Nations community outreach and development in the Sahtu Region.  We continue to maintain strong relations and a solid working relationship with the Deline Land Corp. and the people of Deline Sahtu-Dene First Nations.  We place the long term relationship and well-being of the Community of Deline, as the cornerstone to a successful working relationship and a corporate priority, governing our long-term principles with regard to the responsible sustainable development in the Sahtu Region.

No work is planned on this property in 2011.

A summary of our claims can be found below:

Name	Tag Number	Size (ha)
PR 1	K06181	1,045.10
PR 2	K06182	1,045.10
PR 3	K06183	1,045.10
PR 4	K06194	1,045.10
PR 5	K06195	1,045.10
PR 8	K06198	1,045.10
PR 9	K06199	1,045.10
PR 11	K06201	480.77
PR 12	K06202	1,045.10
PR 13	K06203	1,045.10
PR 14	K06204	449.40
PR 15	K06205	41.80
PR 16	K06206	585.18
PR 18	K06208	94.09
PR 19	K06209	161.98
PR 20	K06210	62.73
		11,281.85

23

Figure 10

Our expenditures related to the Eldorado South Uranium Project can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Camp costs and field supplies		27,967		-		-		8,989
Claim maintenance and permitting		17,153		-		10,762		916
Community relations and government		3,555		-		-		3,555
Equipment rental		2,623		-		-		1,778
Geology and engineering		301,883		-		71,193		118,858
Geophysics		3,000		-		-		-
Staking and line cutting		415,099		-		71,500		237,944
Transportation and fuel		176,011		-		2,230		171,561
Wages, consulting and management fees		278,323		-		48,942		210,381
		1,225,614		-		204,627		753,982

Port Radium - Crossfault Lake Mineral Claims, NT (Eldorado-Contact Lake Project)

In 2005, we acquired a 100% undivided right, title and interest, subject to a 2% NSR, in five mineral claims totalling 1,820.56 ha (4,498.68 acres) (the “Port Radium – Crossfault Lake Mineral Claims”) located north of Port Radium on Great Bear Lake, NT, for cash payments of $60,000 (paid) and 90,000 of our common shares (issued and valued at $297,000).  We may purchase one-half of the NSR for a one-time payment of $1,000,000 (Figure 11).

We have no work planned on this property in 2011.

A summary of our claims can be found below:

Name	Tag Number	Size (ha)
GOSSAN 1	F91851	418.04
GOSSAN 2	F91858	418.04
CROSS	F91458	2.10
RAD 1	F91859	627.06
RAD 2	F91860	323.98
		1,789.22

Our expenditures related to the Crossfault Lake Property, can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Camp maintenance and permitting		682		-		-		682
Transportation and fuel		817		-		-		817
Wages, consulting and management fees		16,258		-		-		16,258
		17,757		-		-		17,757
Acquisition of mineral property interests		357,000		-		-		-
Recovery of mineral property costs		(12,645)		-		-		(12,645)
		362,112		-		-		5,112

24

Figure 11

25

Port Radium - Eldorado Uranium Mineral Claims, NT (Eldorado-Contact Lake Project)

In 2005, we entered into a lease agreement with South Malartic Exploration Inc. to purchase a 50% undivided interest, title and right in three mineral claims, totalling 106.53 ha (263.13 acres) (the “Eldorado Uranium Mineral Claims”) located at Port Radium on Great Bear Lake, NT, for a cash payment of $20,000 (paid) (Figure 12).

Acquisition of the 50% ownership in the property entitled us to full access and possession to a detailed technical library, exploration reports and historical data in South Malartic’s possession.  Also, included in the data acquisition were reports, maps, historical uranium production records, drill logs and uranium assay reports.

The property is located on Labine Point at Port Radium, NT.  Starting in 1933, the mine produced 15 million pounds of high grade uranium and 8 million ounces of silver, plus copper, nickel, radium, lead and polonium.  The mine currently has about 40 km of existing underground workings on 14 levels.

J. Fingler, P.Geo., of Vancouver, British Columbia completed a National Instrument 43-101 compliant technical report dated August 21, 2006 (“Technical Report”) on the Eldorado-Port Radium Property.  The Technical Report provides a comprehensive description of the Eldorado-Port Radium Property including previous work, geology and mineralization and also makes recommendations for further work on the Property.

We have no work planned for this property in 2011.

A summary of our claims can be found below:

Name	Tag Number	Size (ha)
ELDORADO	Lease # 3032	30.32
ELDORADO	Lease # 3033	44.81
ELDORADO	Lease # 3034	31.40
		106.53

Our expenditures related to the Eldorado Uranium Mineral Claims can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expense
Claim maintenance and permitting		1,052		-		526		-
Acquisition of mineral property interests		20,000		-		-		-
		21,052		-		526		-

26

Figure 12

27

North Contact Lake Mineral Claims, NT (Eldorado-Contact Lake Project)

In  2006, we acquired a 100% right, interest and title, subject to a 2% NSR, in eleven mineral claims (the “North Contact Lake Mineral Claims”), for a payment of $75,000 cash (paid) and the issuance of 50,000 of our common shares (issued and valued at $182,500).  We may purchase one-half of the NSR for a one-time payment of $1,000,000.  The North Contact Lake Mineral Claims are situated north of Contact Lake on Great Bear Lake approximately 680 km (423 miles) north of Yellowknife, NT, totalling 6,305.22 ha (15,580.48 acres) (Figure 13).

The property is the northern extension of the Contact Lake Project and includes the Contact Lake – Echo Bay Stato-volcanic complex, having hundreds of known or recorded copper, gold, silver, nickel, cobalt, REE and high grade uranium occurrences identified in Proterozoic rocks.

We have no work planned for this property in 2011.

A summary of our claims can be found below:

Name	Tag Number	Size (ha)
EC 1	F98661	250.82
EC 2	F98662	940.59
EC 3	F98663	940.59
EC 4	F98664	587.35
EC 5	F98665	55.60
EC 6	F98666	192.30
EC 7	F98667	477.82
EC 8	F98668	1,045.10
EC 9	F98669	1,045.10
EC 10	F98670	731.57
EC 24	F98369	38.38
		6,305.22

Total expenditures related to the North Contact Lake Mineral Claims can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expense
Camp costs and field supplies		1,034		-		-		1,034
Drilling		353,182		-		-		353,182
Transportation and fuel		9,606		-		-		9,606
Wages, consulting and management fees		13,012		-		-		13,012
		376,834		-		-		376,834
Acquisition of mineral property interests		257,500		-		-		-
		634,334		-		-		376,834

28

Figure 13

29

Longtom Property (Damp Claim Lease), NT

We hold a 50% undivided interest subject to a 2% NSR, totalling 355.34 ha (878.05 acres), in the Longtom Property (the “Longtom Property”) located about 350 km northwest of Yellowknife, NT.  The Longtom Property is registered in the name of the Company . (Figure 14).

We have the right to acquire the remaining 50% interest in the Longtom Property (the “Longtom Option”) for $315,000 payable either in cash or50% ($157,500) in cash and 50% in common shares of the Company.  The deemed price of our shares issued on the exercise of the Longtom Option would be the average TSX Venture Exchange closing market price of our common shares on the five trading days immediately preceding and the five trading days immediately following the date that the option is exercised. We are  compelled to exercise the Longtom Option: 1) within 90 days from the date it has incurred $5,000,000 in exploration expenditures on the Longtom Property; or 2) at the date we advise the optionor in writing that it will complete the Longtom Option to purchase the remaining 50% interest in the Longtom Property.

We have  the right to enter into joint venture or option agreements related to the Longtom Property with third parties prior to the exercise of the Longtom Option.

In 2003, we entered into a Letter of Intent (the “Letter of Intent”) with Fronteer Development Group Inc. (“Fronteer”).  On October 26, 2006, Fronteer earned its 75% interest in the Longtom Property by paying us $15,000 cash (received) and spending an aggregate of $500,000 (incurred) on exploration expenditures over three years.

The Longtom Property is located 50 km southeast of Great Bear Lake, NT.

The Longtom property is located within the Bear Geological Province, bounded by the Coronation Geo-syncline to the East and the Great Bear Magmatic Zone to the West. All known mineral deposits and showings occur along north-south and north-east fault zones and north-west fold axial planes. These features are related to the Wopmay Deformation Zone, which was reactivated during an east-west shortening event, resulting in north-south folding and the development of pervasive north-east striking strike slip faults. The development of these faults undoubtedly played a role in the development of IOCG style mineralization in the Bear Province.

The rocks of the main Longtom claim area have been divided into seven lithological units. Volcanic and sedimentary units dip moderately to steeply to the south in the area of the Damp prospect and gently to the north northeast in the Devil’s Lake area. All units except the later diabase dykes are affected by northeast trending faults and fractures.

A summary of our Damp mineral lease claim can be found below:

Claim Name	Tag Number	Size (ha)
DAMP	Mineral Lease # 3759	355.34

30

Figure 14

31

Our expenditures related to the Longtom Property are summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Assaying and geochemical		335		-		-		-
Camp costs and field supplies		147,024		-		-		-
Claim maintenance and permitting		3,572		893		893		-
Drilling		210,057		-		-		-
Geology and engineering		418,998		-		-		-
Transportation and fuel		322,529		-		-		-
Wages, consulting and management fees		200,899		-		-		10,626
		1,303,414		893		893		10,626
Recovery of mineral property costs		(52,497)		-		-		-
Sales of mineral property interests		(55,000)		-		-		-
Write-off of mineral properties and related costs		220,552		-		-		-
		1,416,469		893		893		10,626

Most previous work on the property was concentrated on the Damp Zone, a relatively small area near its north end.  The mineralization occurs in a specular hematite-magnetite breccia, similar to that seen at major IOCG deposits.  Shallow holes were drilled at the Damp Zone in 1988 (16 holes by CEGB totalling 1200m) and 1997 (4 holes by Mongolia Gold Resources totalling 944).  Appreciable copper, gold, cobalt, silver, uranium bismuth and nickel were obtained over considerable widths in a zone of albite and hematite-magnetite alteration in volcanic flows.  The Damp Zone is near the north end of a strong magnetic anomaly.

In 2003, we carried out semi-regional gravity and IP surveys and followed up with a diamond drill program. A 12-hole (2634 m) drill program was carried out to test anomalies arising from the magnetic, gravity and IP surveys.  This drill program intersected IOCG-style mineralization and anomalous copper values. The strongest combined magnetic-gravity-chargeability anomalies on the property remain untested.

During July and early August 2004, a nine-hole NQ diamond drilling program was completed on the Longtom Property.  A total of 2132 metres were drilled over the course of the program.  Drilling was designed to target IOCG style mineralization.  In January 2005, a five day reconnaissance program was carried out in order to re-examine drill core from historic operations.

No work is planned on this property in 2011.

32

Longtom Property (Target 1), NT

During the year ended  November 30, 2003, we acquired a 50% interest in a 710.67 ha (1,756.10 acres) mineral property located in the Longtom Lake area of the Northwest Territories for cash proceeds of $15,000 and 40,000 of our common shares valued at $56,000 (Figure 15).

Travel to the Target 1 claim can be accessed via aircraft. As of December 31, 2004, it was known that no electricity was available at the site and that surface water was plentiful within the boundaries of the property. No known mineralization had been found in this target, nor were there any known resources or reserves; sufficiency of surface rights and availability of power, water, tailings storage and waste disposal areas, heap leach pad sites and potential processing plant sites had not been addressed.

A summary of our claim can be found below:

Claim Name	Tag Number	Size (ha)
TARGET 1	F71013	710.67

Total expenditures related to the Longtom Property (Target 1) can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Geology and engineering		2,103		-		-		-
Wages, consulting and management fees		21,648		-		-		-
				-		-		-
Acquisition of mineral property interests		71,000		-		-		-
Recovery of mineral property costs		(3,530)		-		-		-
		91,221		-		-		-

No work is planned on this property in 2011.

33

Figure 15

ITEM 4A - UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5 - OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The Company is engaged in the acquisition, exploration and development of resource properties. As we are currently in the exploration stage, we have had no operating revenue during the years ended November 30, 2009, and 2008. As of November 30, 2010, we have conducted exploration work on several properties located in the Northwest Territories, Canada. In August 2010, the Company diversified into the oil and natural gas resource sector with the acquisition of revenue producing resource assets to complement our existing advanced stage mining interests and provide us with a reputable working interest partner for future expansion in the oil and natural gas resource sector. We are now a heavy oil producer.

This discussion and analysis of the operating results and financial position of our Company for the three years ended November 30, 2010, 2009, and 2008 should be read in conjunction with the financial statements and the related notes included in Item 17.  This section contains ‘forward-looking statements”.  See “Cautionary Note on Forward-Looking Statements”.

General Assumptions and Policies

Exchange Rates

Transaction amounts denominated in foreign currencies are translated into functional currency at exchange rates prevailing at transaction dates.

Inflation

Based on prior history for at least the past two fiscal years, we do not believe that inflation will have a materially adverse effect on our financial condition. However, no assurance can be given that we will not experience a substantial increase in inflation.

Financial Instruments and Other Instruments

Fair Value

The fair value of cash and cash equivalents, amounts receivable and accounts payable approximates their carrying value due to the short-term nature of these financial instruments.

Exchange Risk

We operate in Canada and so are not subject to foreign currency risk arising from changes in exchange rates with other currencies.

Interest Rate Risk

We are exposed to interest rate risk on our short-term investments, but this risk relates only to investments held to fund future activities and does not affect our current operating activities.

Credit Risk

Our cash resources are invested in R1-High bankers acceptance notes on deposit with large Canadian chartered Banks.  None of our funds are exposed to repayment risks associated with short term commercial paper or asset-backed commercial paper.  These securities comply with our strict investment criteria and policy of utilizing only R1-High investment guaranteed instruments that are paid promptly on maturity.

A.

Operating Results

As at November 30, 2010, we had working capital of $8,025,748, inclusive of $9,456,219 of cash and cash equivalents on hand.  Cash and cash equivalents on hand at the date of this MD&A are approximately $8,000,000 which is sufficient to cover additional property acquisitions, planned exploration expenditures, and administration for at least 12 months.

Effective August 1, 2010, we started receiving revenue from our recently acquired interests in our oil and gas resource properties. Only the 3^rd and 4^th quarters shows oil and gas revenue and prior quarters are not shown as there was no production. The following table is from August 1, 2010 to November 30, 2010.

FINANCIAL AND OPERATING SUMMARY

TABLE A - OPERATIONS BY QUARTER (August 1, 2010 to November 30, 2010)

All production is conventional heavy oil
	Q4	Q3
Production and per share	2010	2010
Production  - total barrels	5,045	722
Production  -  bbls/ day	55	23
Heavy oil revenue	281,651	46,489
Royalty income	36,493	6,632
Royalties	(39,255)	(4,874)
Production & transportation	(147,432)	(31,505)
Operating net back	131,457	16,742
General and administrative	(516,823)	(325,127)
Corporate net back	(385,366)	(308,385)
Depletion & amortization	(141,262)	(21,460)
Accretion	(6,339)	(1,211)
Other (expenses) revenue	(267,115)	253,521
Income (loss) for the period	(800,082)	(77,535)
Basic and diluted income (loss) per share	(0.037)	(0.004)
Royalties as % of petroleum revenue	14	10
Per bbl analysis	Per bbl	Per bbl
Heavy oil revenue	55.83	64.39
Royalty income	7.23	9.19
Royalties	(7.78)	(6.75)
Production and transportation	(29.22)	(43.64)
Operating net back	26.06	23.19
Depletion & amortization	(28.00)	(29.72)
Accretion	(1.26)	(1.68)
Income (loss) for the period	(158.59)	(107.39)
Funds (invested in) petroleum properties	(482,979)	(3,123,779)

FINANCIAL AND OPERATING SUMMARY

TABLE C – BALANCE SHEET

	Q4	Q3
	2010	2010
Net cash	9,456,219	10,292,528
Total assets	13,605,905	14,077,712
Total liabilities	2,066,420	1,747,766
Shareholders’ equity	11,539,485	12,329,946
SHARES
Basic outstanding	21,403,979	21,403,979
Weighted average	21,403,979	21,403,979

OPERATING RESULTS FOR 2010 - Oil and Gas Operations

(See "Table A - Financial and Operating Summary")

·

Production volumes and revenues

The oil and gas properties were acquired on August 9, 2010 and August 26, 2010.  The pre-acquisition earnings are an adjustment to the purchase price with the revenue and operating costs not being recorded.  Only the August production of 722 barrels from the August 9, 2010 acquisition are recorded in Q3 and 5,045 barrels of production were recorded in the 4^th quarter.  18 wells were producing in Q4.

We plan to increase production on the properties acquired. The strong balance sheet following the acquisition in August 2010 has allowed us to complete six wells that are now in production.  

·

Royalties

The “Financial and Operating Summaries” show royalty expense as a per cent of oil sales.  The Saskatchewan wells incurred a higher royalty burden than the Alberta wells.

·

Production and transportation costs

A significant portion of production costs are fixed and therefore production expense per bbl varies significantly with volume.  Heavy oil production costs tend to be higher than light oil production costs. Transportation costs are low and comprise only the trucking of clean oil short distances to the sales terminal. The plans to drill additional wells to increase production should reduce production costs per bbl for 2011.

·

General and administrative  

As production just started as a result of the oil and gas acquisitions, costs per bbl will reduce significantly as general and administrative costs tend to be fixed.  Legal, accounting, advisory, regulatory and travel expenses were incurred in Q3 2010 related to the property transactions.  

·

Depletion and accretion

Depletion expense is a function of volume produced as it is computed on a “units of production” basis.

The property acquisitions during the year added $3,951,988 to property, plant and equipment which includes $345,230 in asset retirement obligations and these costs were subjected to depletion. These properties include 196,204 bbls of proven reserves which is the volume base on which depletion is computed.

Probable reserves for the acquired property were significant and may include future locations.  Under IFRS energy companies may choose this larger production basis for the computation of depletion. As probable reserves are determined based on a probability of recovery of 50% or more, this broader depletion base under IFRS will generate a more realistic estimate of real depletion.

RESULTS OF OPERATIONS – YEAR ENDED NOVEMBER 30, 2010

Our net loss for the year ended November 30, 2010 was $2,006,658 or $0.094 per share compared to a net loss of $3,364,852 or $0.157 per share for the year ended November 30, 2009.  The significant changes during the current fiscal period compared to the same period a year prior are as follows:

Advertising and promotion expenses increased to $73,465 during the year ended November 30, 2010 from the $30,649 during the same period a year prior.  The increase in advertising and promotion is primarily attributable to an increase in advertising costs and news release dissemination.

Filing and financing fees decreased to $87,997 for the year ended November 30, 2010 from $153,211 for the year ended November 30, 2009.  The decrease in costs is attributed to a general decrease in fees associated with regulatory authorities.

Part XII.6 tax for the year ended November 30, 2010 was $Nil as compared to $7,392 for the year ended November 30, 2009.  Included in accounts payable and accrued liabilities at November 30, 2010 is $639,445 related to this amount as well as $739,687 charged against capital stock for potential future flow-through obligations.  

Legal and accounting fees decreased to $259,616 for the year ended November 30, 2010, from $332,372 for the year ended November 30, 2009.  The legal and accounting fees were reduced from the previous year and were mainly for legal fees paid to our legal counsel in Alberta, British Columbia and the Northwest Territories for our Annual General Meeting, and other general corporate matters.

Office and miscellaneous expenses for the year ended November 30, 2010 were reduced to $64,404 as compared to $81,910 in the prior year.  The current year office expenses were less due to reduced office overhead associated with the exploration programs.

Salaries and benefits for the year ended November 30, 2010 were $523,805 as compared to $479,878 for the year ended November 30, 2009.  

Stock-based compensation expense totalling $40,305, a non-cash item, was incurred during the year ended November 30, 2010 for previously granted stock options that vested during the period as compared to $539,159 for the year ended November 30, 2009.  No stock options were granted during the year ended November 30, 2010.

Transfer fees and shareholder information costs increased slightly to $281,879 for the year ended November 30, 2010 from $279,242 for the year ended November 30, 2009.  The increase in transfer fees and shareholder information costs period over period is due mainly to an increase in fees and number of consultants and analysts used for our investor relations and corporate development activities.

Travel expenses decreased to $34,390 during the year ended November 30, 2010 from $70,266 during the same period a year prior.  This was due to decreased expenditures on trade show attendances and conferences during the current year.

Interest income decreased to $34,269 for the year ended November 30, 2010, compared to $166,287 during the same period a year prior primarily due to lower interest rates being paid on deposits during the current year.

SELECTED ANNUAL INFORMATION

The following table sets forth our selected financial information for the last three fiscal years. This financial information is derived from the audited financial statements of the Company.

Item	For the Year Ended November 30
	2010	2009	2008
Total Revenue	$371,265	$Nil	$Nil
Total (Loss) from Continuing Operations	($2,006,658)	($3,364,852)	($6,489,209)
Operating basic and diluted (Loss) per Share	($0.094)	($0.157)	($0.310)
Net (Loss) in Total	($2,006,658)	($3,364,852)	($6,489,209)
Net  basic and diluted (Loss) per Share	($0.094)	($0.157)	($0.310)
Total Assets	$13,605,905	$15,224,722	$17,880,351
Total Long Term Financial Liabilities	Nil	Nil	Nil
Cash Dividends Declared per Share	Nil	Nil	Nil

Net loss was reduced to $3,364,852 during fiscal 2009 from the $6,489,209 incurred during fiscal 2008 primarily due to an increase in future income tax recovery of $104,590 from the $Nil recorded during fiscal 2008, a decrease in interest income during fiscal 2009 to $166,287 from the $767,768 earned during the prior fiscal period and a decrease in stock-based compensation, a non-cash expense, to $539,159 from the $548,070 incurred during fiscal 2008.  This reduction also included a substantial decrease in exploration expenses to $1,313,613 incurred during 2009, as compared to $3,612,962 incurred during 2008.

Net loss was reduced to $2,006,658 during fiscal 2010 from the $3,364,852 incurred during fiscal 2009 primarily due the decrease in exploration expenses to $324,641 incurred during 2010, as compared to $1,313,613 incurred during 2009. We began receiving oil and gas revenue in August 2010 which contributed an operating net back of $148,199.

Year ended November 30, 2010 compared to year ended November 30, 2009

We incurred a net loss of $2,006,658 for the fiscal year ended November 30, 2010 as compared to a loss of $3,364,852 for fiscal 2009. The decrease in our net loss in the 2010 fiscal year over 2009 can be attributed to reduced exploration costs relating to our mineral property interests in the Northwest Territories, and in particular, to our Contact Lake Mineral Claims and Eldorado/Port Radium – Glacier Lake Mineral Claims, on which we spent a total of $293,373 (2009 - $1,092,969) and $18,639 (2009 - $14,598) respectively.  Our exploration program budget was reduced due to market conditions.  The decision was made to conserve capital until more favourable market conditions return.  This decrease was partially attributed to a decrease in future income tax recovery to $Nil from the $104,590 recorded during fiscal 2009, a decrease in interest income during fiscal 2010 to $34,269 from the $166,287  earned during the prior fiscal period and a decrease in stock-based compensation, a non-cash expense, to $40,305 from the $539,159  incurred during fiscal 2009.

This decrease in development activities incurred a corresponding decrease in general and administration expenses for the year ended November 30, 2010 of $410,042; a total of $1,912,074 was spent in fiscal year 2010, as compared to $2,322,116 in the comparable period of 2009. There were notable increases in the areas of advertising and promotion expenses (2010 - $73,465, 2009 - $30,649), salaries and benefits (2010 – $523,805, 2009 - $479,878),  and transfer fees and shareholder information (2010 - $281,879, 2009 - $279,242).  There were several decreases in the areas of filing and financing fees (2010 – $87,997, 2009 - $153,211), meals and entertainment (2010 - $52,020, 2009 - $78,346) and legal and accounting expenses (2010 - $259,616, 2009 - $332,372).

Year ended November 30, 2009 compared to year ended November 30, 2008

We incurred a net loss of $3,364,852 for the fiscal year ended November 30, 2009 as compared to a loss of $6,489,209 for fiscal 2008. The decrease in our net loss in the 2009 fiscal year over 2008 can be attributed to reduced exploration costs relating to our mineral property interests in the Northwest Territories, and in particular, to our Contact Lake Mineral Claims and Eldorado/Port Radium – Glacier Lake Mineral Claims, on which we spent a total of $1,092,969 (2008 - $1,847,546) and $14,598 (2008 - $612,424) respectively.  Our exploration program budget was reduced due to market conditions.  The decision was made to conserve capital until more favourable market conditions return.  This decrease was partially attributed to an increase in future income tax recovery to $104,590 from the $Nil recorded during fiscal 2008, a decrease in interest income during fiscal 2009 to $166,287 from the $767,768  earned during the prior fiscal period and a decrease in stock-based compensation, a non-cash expense, to $539,159 from the $548,070  incurred during fiscal 2008.

This decrease in development activities incurred a corresponding decrease in general and administration expenses for the year ended November 30, 2009 of $1,321,899; a total of $2,322,116 was spent in fiscal year 2009, as compared to $3,644,015 in the comparable period of 2008. There were notable decreases in the areas of advertising and promotion expenses (2009 - $30,649, 2008 - $265,378), salaries and benefits (2009 – $479,878, 2008 - $575,269), Part XII.6 tax (2009 - $7,392, 2008 - $711,124), legal and accounting expenses (2009 - $332,372, 2008 - $349,567) and transfer fees and shareholder information (2009 - $279,242, 2008 - $477,635).  There were several increases in the areas of filing and financing fees (2009 – $153,211, 2008 - $119,881), and meals and entertainment (2009 - $78,346, 2008 - $68,989).

Year ended November 30, 2008 compared to year ended November 30, 2007

We incurred a net loss of $6,489,209 for the fiscal year ended November 30, 2008 as compared to a loss of $7,916,250 for fiscal 2007. The decrease in our net loss in the 2008 fiscal year over 2007 can be attributed to reduced exploration costs relating to our mineral property interests in the Northwest Territories, and in particular, to our Contact Lake Mineral Claims and Eldorado/Port Radium – Glacier Lake Mineral Claims, on which we spent a total of $1,847,546 (2007 - $5,968,067) and $612,424 (2007 - $5,524,766) respectively.  Our exploration program budget was reduced due to market conditions.  The decision was made to conserve capital until more favourable market conditions return.  This decrease was partially attributed to a decrease in future income tax recovery to $Nil from the $7,123,638 recorded during fiscal 2007, a decrease in interest income during fiscal 2008 to $767,768 from the $1,279,560 earned during the prior fiscal period and a decrease in stock-based compensation, a non-cash expense, to $548,070 from the $1,970,027 incurred during fiscal 2007.

This decrease in development activities incurred a corresponding decrease in general and administration expenses for the year ended November 30, 2008 of $1,047,418; a total of $3,644,015 was spent in fiscal year 2008, as compared to $4,691,433 in the comparable period of 2007. There were notable decreases in the areas of advertising and promotion expenses (2008 - $265,378, 2007 - $475,043), and filing and financing fees (2008 - $119,881, 2007 - $136,896).  There were several increases in the areas of salaries and benefits (2008 – $575,269, 2007 - $397,982), Part XII.6 tax (2008 - $711,124, 2007 - $556,200), legal and accounting expenses (2008 - $349,567, 2007 - $314,683) and transfer fees and shareholder information (2008 - $477,635, 2007 - $248,649).

B.

Liquidity and Capital Resources

General

Since incorporation, we has financed our operations almost exclusively through the sale of common shares to investors. As we are a mining exploration and development company with no producing resource properties, operating income or cash flow generated from business operations. Until a significant body of ore is found, working capital requirements are minimal, and we expect to continue to finance operations through the sale of equity in fiscal 2010.

In August 2010, we diversified into the oil and natural gas resource sector with the acquisition of revenue producing resource assets to complement our existing advanced stage mining interests and provide us with a reputable working interest partner for future expansion in the oil and natural gas resource sector. We are now a heavy oil producer.

There is no guarantee that we will be successful in arranging financing on acceptable terms.  See “Cautionary Note on Forward-Looking Statements”.

To a significant extent, the ability to raise capital is affected by trends and uncertainties beyond the Companies control. These include the market prices for base and precious metals and results from our exploration programs. Our ability to attain our business objectives may be significantly impaired if prices for metals such as gold and uranium fall or if results from our intended exploration programs on our properties are unsuccessful.

We currently have oil and gas operating revenues but we rely primarily on equity financing to fund our exploration and administrative costs.

Our cash resources are invested in R1-High bankers acceptance notes on deposit with an AAA rated Canadian Banking Institution.  None of our funds are exposed to repayment risks associated with short term commercial paper or asset-backed commercial paper.  These securities comply with our strict investment criteria and policy of utilizing only R1-High investment guaranteed instruments that are paid promptly on maturity.

As at November 30, 2010, we had cash and cash equivalents on our balance sheet of $9,456,219 and working capital of $8,025,748 as compared to cash and cash equivalents on our balance sheet of $14,700,318 and working capital of $13,132,754 at November 30, 2009.  The reduction in cash and cash equivalents and working capital of $5,244,099 and $5,107,006, respectively, are in part due to annual exploration expenditures and general and administrative costs.

As at May 13, 2011, we had cash and cash equivalents of approximately $8,000,000 on our balance sheet.  

We believe that this is sufficient to fund our currently planned exploration and administrative budget through the balance of fiscal 2011.   

Recently, the poor conditions in the U.S. housing market and the credit quality of mortgage backed securities continued and worsened in early 2009, causing a loss of confidence in the broader U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity, widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions.  These disruptions in the current credit and financial markets have had a significant material adverse impact on a number of financial institutions and have limited access to capital and credit for many companies. These disruptions could, among other things, make it more difficult to obtain, or increase the cost of obtaining, capital and financing for the operations.   Our access to additional capital may not be available on terms acceptable to us or at all.

We expect to rely upon our current available capital throughout the current fiscal year.  If costs increase substantially or we incur greater losses than expected, our exploration activities and other operations will be reliant upon equity financings to continue into the future.  The current market conditions could make it difficult or impossible for us to raise necessary funds to meet our capital requirements.  If we are unable to obtain financing through equity investments, we will seek multiple solutions including, but not limited to, credit facilities or debenture issuances.

We do not have any loans outstanding at this time but our success in adding production in the last six months of 2010 has enabled us to establish a credit facility of $1.1 million with the Canadian Western Bank consisting of a $800,000 revolving operating loan and a non-revolving acquisition and development loan.  The Credit facility combined with our strong cash position will allow financial flexibility as we look to implement and execute our 2011 capital plan. see "Cautionary Note Regarding Forward Looking Statements".

LIQUIDITY AND CAPITAL RESOURCES

We began recognizing and receiving revenue from our oil and gas resource properties as of August 1, 2010.  We also rely on equity financing as well as the exercise of options and warrants to fund our exploration and administrative costs.

Our cash resources are invested in R1-High bankers acceptance notes and redeemable Canadian Guaranteed Investment Certificates on deposit with an AAA rated Canadian Banking Institution.  None of our funds are exposed to repayment risks associated with short term commercial paper or asset-backed commercial paper.  These securities comply with our strict investment criteria and policy of utilizing only R1-High Investment Guaranteed Instruments that are paid promptly on maturity or are convertible on demand.

As at November 30, 2010, we had cash and cash equivalents on our balance sheet of $9,456,219 and working capital of $8,025,748 as compared to $14,700,318 of cash and cash equivalents and working capital of $13,132,754 at November 30, 2009.  The reduction in cash and cash equivalents of $1,634,461 was due to cash used in operations of $1,634,461 and $3,609,638 that was used to acquire an interest in oil and gas resource properties.

On April 21, 2010, we announced that we were unsuccessful in our bid to acquire 100% of the shares of Sterling and the Sunshine Mine Lease pursuant to a bankruptcy auction held on April 21, 2010.  As a result of the unsuccessful bid, we have confirmed that certain conditions contained in the Agreement with Sterling dated November 17, 2009 have not been satisfied.  As a result of the unsatisfied terms and conditions, we received our entire break fee of Cdn$256,975 (US$250,000) in accordance with the terms of the Agreement and the Second Amended Plan and Disclosure Statement filed by Sterling.

We established a credit facility agreement with a Canadian chartered bank, consisting of a revolving operating facility of $800,000 with an interest rate of bank prime plus 1.5%, and a development facility of $300,000 with an interest rate of bank prime plus 2.0%.

 We has not yet drawn on either credit facility.

Total assets at November 30, 2010 decreased to $13,605,905 from $15,224,722 at November 30, 2009, primarily as a result of general and administrative and mineral property expenses.  

As of the date of this report we have cash and cash equivalents of approximately $8,000,000.  We believe that this is sufficient to fund our currently planned exploration and administrative budget through the balance of fiscal 2011.

A $2,500,000 capital budget of which approximately $2,100,000 is budgeted for drilling, completing and equipping an estimated 10 - 12 wells (5 - 6 net to us) in Alberta and Saskatchewan.  The budget also includes facilities investments, primarily in Saskatchewan which will optimize new production while improving existing production efficiencies.

Financing Activities

A summary of the components of the funds raised in 2010 and the two prior years is as follows:

	2010 $	2009 $	2008 $
Issuance of common shares	-	-	-
Issuance of flow-through shares	-	350,000	-
Warrants exercised	-	-	-
Options exercised	-	-	30,000
	-	350,000	30,000

The particulars of all capital raising transactions for the last two years are detailed below. Proceeds of these financings have been used for exploration and for development expenditures (only when and if warranted) in connection with our mineral projects, for working capital and for acquisition of additional projects.

i.

During the year ended 30 November, 2010, a total of 575,000 stock options with an exercise price of $4.25 per share expired.

ii.

During the year ended 30 November, 2010, a total of 145,000 stock options with an exercise price of $1.75 per share were cancelled.

iii.

During the year ended 30 November, 2010, a total of 20,000 stock options with an exercise price of $5.00 per share were cancelled.

iv.

During the year ended 30 November, 2010, a total of 120,000 stock options with an exercise price of $1.00 per share were cancelled.

v.

Durng the year ended November 30, 2009, we issued 100,000 stock options to certain of our consultants with an exercise price of $1.00 per share.  The 100,000 options vest in four equal quarters starting March 4, 2010.  All options in this series expire November 3, 2014.

vi.

During the year ended November 30, 2009, we issued 790,000 stock options to directors, officers, employees and consultants of the Company with an exercise price of $1.00 per share.  A total of 720,000 options vested immediately upon issuance and the remaining 70,000 options vest in four equal quarters starting November 3, 2009.  All options in this series expire July 2, 2014.3.

vii.

During the year ended November 30, 2009, we issued 466,667 units at a price of $0.75 per unit.  Each unit consists of one flow-through common share and one non flow-through share purchase warrant.  Each whole share purchase warrant entitles the holder to purchase an additional common share at a price of $0.90 up to December 12, 2010.

viii.

During the year ended November 30, 2009, 480,000 stock options with an exercise price of $3.00 per share expired.  .

ix.

During the year ended November 30, 2009, 65,000 stock options with an exercise price of $4.25 per share were cancelled.

x.

During the year ended November 30, 2009, 125,000 stock options with an exercise price of $1.75 per share were cancelled.  

Financial Instruments

All financial instruments we use are predominantly denominated in Canadian dollars.  We do not engage in any hedging operations with respect to currency or in-situ minerals. Funds which are currently in excess of our current expenditures are invested in low risk, highly liquid investments with original maturations of three months or less.

Capital Expenditure Commitments

At November 30, 2010, we were not party to any capital expenditure commitments other than the $594,000 potential asset retirement obligations to abandon our oil and gas wells.

C.

Research and Development, Patents and Licenses, etc.

None.

D.

Trend Information

Mineral Exploration

As we are an exploration company with no producing mining properties, information regarding trends in: production, sales and inventory, and similar are not meaningful.

Oil and Gas

The outlook for the oil and gas industry is fundamentally linked to a variety of international economic factors, including the rate of growth of the world economy.    Global energy consumption contracted significantly in 2009 due in large part to the global recession which followed the global financial crisis of 2008-2009.  Led by growth in China and other emerging economies, global oil demand recovered sharply in 2010 with some of the strongest annual growth in demand seen over the past 30 years.   At the same time, North American demand fell for the first time since 2005.  At the same time non-OPEC production expanded strongly while OPEC production increased moderately.  The number of factors affecting global oil demand and production make it difficult to predict these trends precisely, although expansion in Iraq is expected in increase strongly in the next few years, subject to internal limitations in Iraq due to internal political and infrastructure challenges, and growth in non-OPEC supply is expected to moderate.  Oil supply from the Middle East producers may also be significantly affected by recent political events throughout middle east which, although they cannot be predicted with accuracy, could have the effect of radically curtailing production from one or more countries. This in turn could have a significant short to mid term effect on the price of domestically produced oil.  We anticipate continued strong demand for oil over the next year which should increase as North American economies emerge from the continuing effects of the recession, but likely with significant price volatility due to the many uncertain economic and political factors affecting global oil supply and demand, which are expected to continue throughout the year and for some time into the foreseeable future.

We have decided to curtail our mineral exploration activities in the following year to concentrate on development of our oil and gas business.  We anticipate to aggressively pursue acquisition of additional oil and gas properties and exploration and development of our existing properties.  As a result, although we expect that our revenue from oil and gas production will increase over the next 12 months, we anticipate our net losses will continue in the short to mid term as we continue to conduct oil and gas exploration activities to expand our existing oil and gas reserves.   See "Cautionary Note Regarding Forward Looking Statements".

E.

Off-balance Sheet Arrangements

We have no off-balance sheet arrangements that would require disclosure.

F.

Tabular Disclosure of Contractual Obligations

In the year ended November 30, 2010, we were not party to any agreements or arrangements which gave rise to any contractually obligated payments.  We are party to an agreement with Sterling Mining Company to subscribe for all of our issued and outstanding shares after satisfaction of claims under ongoing bankruptcy proceedings which, if accepted by the Court and completed, would require us to pay the sum of US$ 11,750,000 in consideration therefore, however such obligation remains subject to court approval and a number of other conditions which remain outstanding as of the date of filing of this Annual Report.

G.

Safe Harbour

Certain statements contained in this Annual Report may be viewed as "forward-looking statements" within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the US Securities Exchange Act of 1934, as amended. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause actual events, and/or the actual performance, financial condition or results of operations of our company to be materially different from any future performance, financial condition or results of operations implied by such forward-looking statements. Further information regarding these risks, uncertainties and other factors is included in this Annual Report under “Item 3D” and such other documents that we may file with the SEC from time to time.  See “Cautionary Note on Forward-Looking Statements.”

ITEM 6 - DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.

Directors and Senior Management

Directors

Name of Director	Age	Date of First Election or Appointment
Tim Coupland	52	September 14, 2000
Robert Hall	33	September 27, 2006
Stuart Rogers	54	March 1, 2007
Brian Morrison	29	September 5, 2008
Edward Burylo	67	December 17, 2008

Executive Officers and Management

Name of Officer	Age	Office
Tim Coupland	52	President, Chief Executive Officer
Gordon Steblin	51	Chief Financial Officer
Robert Hall	33	Director, Manager of Field Operations

The following describes the business experience of our directors and executive officers, including other directorships held in reporting companies:

Tim Coupland, President and Chief Executive Officer

Tim Coupland has acted as President and Chief Executive Officer of the Company since September 14, 2000. Mr. Coupland has held numerous officer and directorship positions with TSX-V listed companies and OTCBB listed junior mining companies.

Mr. Coupland has over 20 years of business experience with both public and private companies and has been involved in both debt and equity financings of up to $75 million dollars. He brings expertise in raising equity capital and then assembling highly seasoned teams of professionals, consultants, financial consultants and mineral exploration advisors who have proven track records in financing, negotiation and promotion required to secure and develop successful mineral exploration projects. Mr. Coupland oversaw the rigorous permitting process with regulatory authorities responsible for issuing land use permits, water licences and conducting environmental assessments for the Eldorado & Contact Lake projects in Canada's Northwest Territories. Mr. Coupland was the lead negotiator who secured the impacts and benefits agreement with the Sahtu-Dene First Nations on their traditional Territories. He has been instrumental in acquiring key land packages and then permitting these land packages for exploration.

He brings a wealth of technical and financial experience as well as long-term business relationships with many First Nations, Inuit and Métis groups operating in Canada's Northwest Territories.

Mr. Coupland has a Bachelor's Degree in Geography from Simon Fraser University.

Gordon Steblin, Chief Financial Officer

Mr. Steblin obtained a Bachelor of Commerce degree in 1983 from the University of British Columbia (UBC), and in 1985 he became a Certified General Accountant. Mr. Steblin has over 20 years of financial experience in the junior mining/exploration sector. Mr. Steblin was previously the Chief Financial Officer of CanAlaska Uranium Ltd., El Nino Ventures Inc. and Pacific North West Capital Corp.  Mr. Steblin is currently the Chief Financial Officer of Freegold Ventures Limited, Dynamic Gold Corp, Next Gen Metals Inc., Arctic Hunter Uranium Inc. and CVC Cayman Ventures Corp.

Robert Hall, Director, Manager of Field Operations

In September 2006, Robert Hall joined Alberta Star as a director. Mr. Hall also acts as a director and officer of Arctic Hunter Uranium Inc. which trades on the CNSX and Dynamic Gold Corp., a company trading on the FINRA OTC Bulletin Board.  Mr. Hall holds a Bachelor's degree in Education from the University of British Columbia.

Stuart Rogers, Director

A director since March 2007, Stuart Rogers has been involved in the venture capital community since 1987.  He is the President and founder of West Oak Capital Group, Inc., a privately held investment banking firm specializing in the early stage finance of technology and resource projects through the junior capital markets in Canada and the United States, and has served as a director of client companies listed on the TSX Venture Exchange, the Toronto Stock Exchange, NASDAQ Small Capital Market and FINRA OTC Bulletin Board.   Mr. Rogers is the President and director of MAX Resource Corp. and serves as a director and Chief Financial Officer of TerraX Minerals Inc.

Brian Morrison, Director

Mr. Morrison received a Bachelor of Commerce degree from the University of Northern British Columbia in 2004 and completed the Canadian Securities Course in 2006. Mr. Morrison has spent the past four years working in the area of public company administration.

Currently, Mr. Morrison is a business consultant for a number of listed Junior Mining Companies on the TSX Venture Exchange. Prior to that, Mr. Morrison was Manager at Computershare Investor Services.

Edward Burylo

Edward Burylo is a successful businessman with over 40 years of Public Market Experience. Mr. Burylo is currently a Director of Arctic Hunter Uranium Ltd., a CNSX listed Company.

Family Relationships

There are no familial or marital relationships that exist amongst our officers and directors.

Arrangements

There are no arrangements or understandings between any of our directors or executive officers, and with our major shareholders, customers, suppliers or others, pursuant to which they were selected to be a director or executive officers.

B.

Compensation

We are required, under applicable securities legislation in Canada, to disclose to our shareholders details of compensation paid to our directors and members of our administrative, supervisory or management bodies.  The following fairly reflects all material information regarding compensation paid to our directors and members of our administrative, supervisory or management bodies in our fiscal year ended November 30, 2010.

We paid $1,000 per month to our directors for their services in their capacity as directors until December 31, 2010.  The board of directors may award special remuneration to any director undertaking any special services on our behalf other than services ordinarily required of a director. Other than indicated below, no director received any compensation for his or her services as a director, including committee participation and/or special assignments.

34

2010 Summary Compensation Table

NAME AND PRINCIPAL POSITION			ANNUAL COMPENSATION			LONG-TERM COMPENSATION
			Salary	Bonus	Other Annual Compensation	Awards		LTIP payouts	Other
						Restricted Stocks	Options/ SARs(1)
Tim Coupland :  President, Chief Executive Officer and Director			$350,000	$50,000	-	Nil	Nil	Nil	Nil
Gord Steblin:  CFO				$10,000	$66,000(2)	Nil	Nil	Nil	Nil
Robert Hall:  Manager of Field Operations and Director			$80,000	$15,000	-	Nil	Nil	Nil	Nil
Stuart Rogers:   Director				$15,000	$12,000(3)	Nil	Nil	Nil	Nil
Brian Morrison (appointed Sept. 5, 2008)  Director				$15,000	$12,000(3)	Nil	Nil	Nil	Nil
Edward Burylo (appointed Dec. 17, 2008)  Director				$15,000	$12,000(3)	Nil	Nil	Nil	Nil
Notes:
	(1)	“Securities Under Options/SARs Granted” are grants made under the stock option plan of the Company. “SAR” means stock appreciation rights.
	(2)	Fee paid to a company controlled by Mr. Steblin for accounting services.
	(3)	These amounts are directors fees paid to entities controlled by the named director.

In accordance with our stock option plan, summarized below, we award the above members of the board of directors with the annual compensation, in the form of employee incentive stock options, as is set forth beside their names. Each option is exercisable from $$0.48 to $1.75 per common share, exercisable for a maximum period of up to five years, excepting those terms, found below.

Stock Option Plan

Our stock option plan provides for equity participation by eligible directors, officers, employees and consultants through the acquisition of common shares pursuant to the grant of options. Our board of directors administers the plan. Options may be granted to purchase common shares on terms that the directors may determine, subject to the limitations of the stock option plan and the requirements of the TSX-Venture Exchange.   

The following is a summary of the terms of the stock option plan and is qualified in its entirety by the full text of the stock option plan which is available for review at our offices:

1.

The number of common shares to be reserved and authorized for issuance, pursuant to options granted under the stock option plan, is 10% of our issued and outstanding common shares from time to time;

2.

Under the stock option plan, the aggregate number of optioned common shares granted to any one optionee in a 12-month period must not exceed 5% of the issued and outstanding common shares. The number of optioned common shares granted to any one consultant in a 12-month period must not exceed 2% of the issued and outstanding common shares. The aggregate number of optioned common shares granted to optionees who are employed to provide investor relations activities must not exceed 2% of our issued and outstanding common shares in any 12-month period;

3.

The exercise price for options granted under the our stock option plan will not be less than the market price of the common shares less applicable discounts permitted by the TSX-Venture Exchange;

4.

Options will be exercisable for a term of up to five years, subject to earlier termination in the event of death or the optionee’s cessation of services to us; and;

5.

Options granted under the stock option plan are non-assignable, except by will or the laws of descent and distribution.

See “Item 6.E. – Share Ownership of Director and Officers” for table setting out the stock options currently outstanding to our directors and officers.

Pension or Retirement Benefits

We do not have a pension, retirement fund or similar benefits plan or other arrangement for non-cash compensation to our directors or senior officers, with the exception of incentive stock options.

C.

Board Practices

General

For a discussion of our directors’ term in office, please see “Item 6.A.”

The directors hold office until the next annual general meeting of the shareholders, at which time they may stand for re-election. We are required to hold an annual general meeting within fifteen months from the last annual general meeting.  Our most recent annual general meeting was held on February 8, 2010.

Service Contracts

There are no director service contracts.

Audit Committee

Our Board of Directors has one committee, an audit committee.  We do not have a compensation or remuneration committee.

Our audit committee is comprised of Tim Coupland, Brian Morrison, Edward Burylo, Robert Hall and Stuart Rogers. The audit committee performs the following functions, among others:

·

Directly appoints, retains and compensates our independent auditor and pre-approves all auditing and non-auditing services of the independent auditor;

·

Evaluates the independent auditor's qualifications, performance and independence;

·

Discusses the scope of the independent auditors' examination;

·

Reviews and discusses the annual audited financial statements and quarterly financial statements with management and the independent auditor and the report of the independent auditor thereon;

·

Assesses our accounting practices and policies;

·

Reviews and approves of all related-party transactions, including transactions between our company and our officers or directors or affiliates of officers or directors;

·

Develops, and monitors compliance with, a code of ethics for senior financial officers;

·

Develops, and monitors compliance with, a code of conduct for all our employees, officers and directors;

·

Establishes procedures for the receipt, retention and treatment of complaints regarding accounting, internal accounting controls or auditing matters; and

·

Establishes procedures for the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters.

The specific functions and responsibilities of the audit committee are set forth in our audit committee charter. We have determined that Stuart Rogers qualifies as an audit committee financial expert, pursuant to SEC regulations and section 803 of the NYSE AMEX company guide.  Members of the audit committee satisfy the financial literacy requirements for audit committee members under the SEC rules and regulations.  We have determined that Messrs. Morrison, Burylo and Rogers are independent directors in accordance with Rule 10A3 under the Securities Exchange Act of 1934 and Section 803 of the NYSE AMEX Company Guide.

In order to act in a forward-thinking manner, our board of directors intends to elect a compensation committee, in 2011 whose members will include members of the audit committee, to complete the following functions, among others:

·

Develops executive compensation philosophy and establishes and annually reviews and approves policies regarding executive compensation programs and practices;

·

Reviews and approves corporate goals and objectives relevant to the Chief Executive Officer's compensation, evaluates the Chief Executive Officer's performance in light of those goals and objectives and sets the Chief Executive Officer's compensation based on this evaluation;

·

Reviews the Chief Executive Officer's recommendations with respect to, and approves annual compensation for, our other executive officers;

·

Establishes and administers annual and long-term incentive compensation plans for key executives;

·

Recommends to the board for its approval and, where appropriate, submission to our stockholders, incentive compensation plans and equity-based plans;

·

Recommends to the board for its approval changes to executive compensation policies and programs; and

·

Reviews and approves all special executive employment, compensation and retirement arrangements.

D.

Employees

At the end of the fiscal year ended November 30, 2010, we had three employees consisting of the Chief Executive Officer, Manager of Field Operations and an office assistant.  All employees were located in British Columbia.  We hire contractors on an as-needed basis for geological services and other trades and when required, we have retained geological and other consultants to conduct work programs on our mineral property interests.

E.

Share Ownership

Our directors and officers beneficially own the following shares as of the date of this Annual Report:

Common Shares

Director or Officer			Number of Common Shares Owned	Percentage of Outstanding (%)(1)
Tim Coupland			1,031,517	4.82
Brian Morrison			5,800	0.03
Edward Burylo			3,800	0.02
Stuart Rogers			29,000	0.14
Robert Hall			45,700	0.21
Gord Steblin			-	-
Notes:
	(1)	Percentages are based on 21,403,979 shares of common stock issued and outstanding as of the date of this Annual Report.

Stock Options

The following incentive stock options are currently outstanding to our directors and officers as of the date of this Annual Report:

Shares that may be Purchased Upon Exercise of Stock Options

Director or Officer		Number of Common Shares	Exercise Price ($)	Expiry Date
Tim Coupland		260,000	1.75	July 31, 2011
		340,000	1.00	July 2, 2014
		395,000	0.48	December 7, 2012
Brian Morrison		30,000	1.00	July 2, 2014
		65,000	0.48	December 7, 2012
Edward Burylo		50,000	1.00	July 2, 2014
		65,000	0.48	December 7, 2012
Stuart Rogers		35,000	1.75	July 31, 2011
		50,000	1.00	July 2, 2014
		65,000(1)	0.48	December 7, 2012
Robert Hall		35,000	1.75	July 31, 2011
		50,000	1.00	July 2, 2014
		65,000	0.48	December 7, 2012
Gord Steblin		50,000	1.00	July 2, 2014
		65,000	0.48	December 7, 2012
(1)	These options were issued to West Oak Capital Group, a private company owned by Stuart Rogers.

At the 2010 annual general meeting of our shareholders, held on February 8, 2010, our company’s stock option plan was proposed, and approved, and subsequently filed with the TSX-V.

We grant share options in accordance with the policies of the TSX Venture Exchange. Under the general guidelines of the TSX Venture Exchange, we may reserve up to 10% of our issued and outstanding shares to our employees, directors or consultants to purchase.

Our stock option plan provides for equity participation by eligible directors, officers, employees and consultants through the acquisition of common shares pursuant to the grant of options. Our board of directors administers the plan. Options may be granted to purchase common shares on terms that the directors may determine, subject to the limitations of the stock option plan and the requirements of the TSX-V. For a summary of the terms of the stock option plan, see “Item 6B.”

ITEM 7 - MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A.

Major Shareholders

We are a publicly-held corporation, with our common shares held by residents of Canada, the United States of America and other countries. As of the date of filing this Annual Report, we are authorized to issued an unlimited number of common shares without par value, of which 21,403,979 common shares are issued and outstanding and unlimited number of preferred shares without par value, of which none are issued and outstanding.

As of the date of this report, there are no shareholders known to us that are beneficial owners of more than 5% of our common shares except as set out herein.

Changes in Ownership Percentage

There were no significant changes over the last three years in the percentage of the issued share capital for the Company held by major shareholders, either directly or by virtue of ownership of our common shares.

Identity of Person or Group(1)			2010	2009	2008
Tim Coupland(3)			9.05%	<5%	<5%
Notes:
	(1)	Beneficial ownership is determined in accordance with the rules of the SEC and generally includes voting or investment power with respect to securities.  Shares of common stock subject to options or warrants currently exercisable, or exercisable within 60 days, are deemed outstanding for purposes of computing the percentage ownership of the person holding such option or warrants, but are not deemed outstanding for purposes of computing the percentage ownership of any other person.
	(2)	Percentages are based on in: (1) 2010:  21,403,979 shares of common stock issued and outstanding as of  March 29, 2011; (2)  2009:  21,403,979 shares of common stock issued and outstanding as of  March 29, 2010; and (3)  2008:  21,403,979 shares of common stock issued and outstanding as of  March 20, 2009; unless otherwise noted.
	(3)	Tim Coupland beneficially owns 2,026,517 common shares including  1,031,517 common shares and 995,000 common shares acquirable upon exercise of  outstanding stock options for a total of 9.47%.  Tim Coupland holds 768,485 shares directly, T8X Capital Ltd., of which Tim Coupland is a 100% owner, holds 263,032 share and 995,000 stock options.

There has not been a significant change in the ownership percentage held by any major shareholders during the past three years except as set out herein.

Voting Rights

Our major shareholders do not have any different voting rights than other shareholders.

Corporate or Foreign Government Ownership

We are not controlled directly or indirectly by any other corporation or any other foreign government or by any other natural or legal person, severally or jointly.

Geographic Breakdown of Shareholders

The following lists the geographical distribution of shareholders at February 28, 2011:

	Number of registered
Location	shareholders	Number of shares
Canada	12	21,271,585
United States	12	111,674
Other	3	20,720
Total	27	21,403,979

Shares registered in intermediaries are assumed to be held by residents of the same country in which the clearing-house is located.

Change of Control

There are no arrangements for which through their operation, at a subsequent date, may result in a change in our control.

CONTINGENCIES

We are aware of no contingencies or pending legal proceedings as of March 29, 2010.

OFF-BALANCE SHEET ARRANGEMENTS

We have no off-balance sheet arrangements that would require disclosure.

B.

Related Party Transactions

TRANSACTIONS WITH RELATED PARTIES

Our board of directors consists of Tim Coupland, Robert Hall, Brian Morrison, Edward Burylo and Stuart Rogers.  Tim Coupland is our President and Chief Executive Officer, Robert Hall is our Manager of Field Operations and  Gord Steblin is our Chief Financial Officer.  We paid or accrued amounts to related parties as follows:

	For the Year Ended November 30
	2010	2009	2008
Secretarial fees paid to an individual related to Mr. Tim Coupland	15,000	15,000	15,000
Management fees paid to a company controlled by Mr. Tim Coupland	50,000	50,000	50,000
Director fees paid to a company controlled by Mr. Robert  Hall	15,000	25,000	25,000
Director fees paid to Mr. Stuart Rogers	27,000	27,000	32,000
Director fees paid to Mr. Edward Burylo	27,000	10,000	-
Director fees paid to Mr. Brian Morrison	27,000	17,000	3,000
Accounting fees paid to a proprietorship controlled by Ms. Chantal Schutz	-	13,875	-
Accounting fees paid to a company controlled by Mr. Gord Steblin	76,000	59,001	-
Salaries and benefits paid to directors and/or officers of the Company	523,805	479,878	575,269
	$760,805	$696,754	$700,269

These transactions were in the normal course of operations and were measured at the exchange value which represented the amount of consideration established and agreed to by the related parties.

PROPOSED TRANSACTIONS

As is typical of the natural resource exploration and development industry, we are continually reviewing potential merger, acquisition, investment and joint venture transactions and opportunities that could enhance shareholder value.  

The amounts charged to us for the services provided have been determined by negotiation among the parties, and in certain cases, are covered by signed agreements. It is the position of management that these transactions were in the normal course of operations and were measured at the exchange value which represented the amount of consideration established and agreed to by the related parties.

Other than disclosed herein, no director or senior officer, and no associate or affiliate of the foregoing persons, and no insider has or has had any material interest, direct or indirect, in any transactions, or in any other proposed transaction, during the year ended November 30, 2010.

C.

Interests of Experts and Counsel

Not applicable.

ITEM 8 - FINANCIAL INFORMATION

A.

Consolidated Statements and Other Financial Information

Financial Statements

As required, we have included the following (see “Item 17”), as audited by an independent auditor and accompanied by an audit report, as of November 30, 2010:

·

Balance sheets as at November 30, 2010 and 2009;

·

Statements of loss, comprehensive loss and deficit for the fiscal years ended November 30, 2010, 2009, 2008 and cumulative from inception to November 30, 2010;

·

Statements of cash flows for the fiscal years ended November 30, 2010, 2009, 2008 and cumulative from inception to November 30, 2010;

·

Statements of changes in shareholders’ equity; and

·

Related notes and schedules.

Legal Proceedings

We are not involved in any litigation or legal proceedings and to our knowledge, no material legal proceedings involving us are to be initiated against us.

Dividends

We have never paid any dividends and do not intend to pay any dividends in the near future.

B.

Significant Changes

Since the fiscal period ended November 30, 2010, no changes have taken place which may materially affect the interpretation of our company’s financial statements.

ITEM 9 - THE OFFER AND LISTING

A.

Offer and Listing Details

Our common shares trade on the TSX-V under symbol “ASX”, on the OTCBB under symbol “ASXSF” and on the Frankfurt Exchange under symbol “QLD”. Our shares have traded on the TSX-V, and on its predecessor, the Alberta Stock Exchange, since December 5, 1997. The following table sets forth the high and low closing prices in Canadian funds of our common shares traded on the TSX-V and its predecessor:

Period		High		Low
December 1, 2005 to November 30, 2006	$	13.80	$	3.00
December 1, 2006 to November 30, 2007	$	13.10	$	2.90
December 1, 2007 to November 30, 2008	$	3.45	$	0.60
December 1, 2008 to November 30, 2009	$	1.30	$	0.50
December 1, 2009 to November 30, 2010	$	1.20	$	0.37
Period		High		Low
December 2008 to February 2009	$	1.00	$	0.50
March 2009 to May 2009	$	1.20	$	0.60
June 2009 to August 2009	$	1.30	$	0.65
September 2009 to November 2009	$	0.95	$	0.65
December 2009 to February 2010	$	1.20	$	0.70
March 2010 to May 2010	$	0.80	$	0.37
June 2010 to August 2010	$	0.43	$	0.38
September 2010 to November 2010	$	0.51	$	0.40

Period		High		Low
August 2010	$	0.43	$	0.40
September 2010	$	0.51	$	0.40
October 2010	$	0.50	$	0.43
November 2010	$	0.48	$	0.43
December 2010	$	0.58	$	0.44
January 2011	$	0.68	$	0.55
February 2011	$	0.70	$	0.62
March 2011	$	0.59	$	0.50
April 2011	$	0.57	$	0.46

Our common shares have been quoted for trading on the OTCBB since July 16, 2002; no trades in our common shares occurred on this quotation system until January 29, 2003. The following sets forth the high and low closing prices in United States funds of our common shares traded on the OTCBB since this date:

Period		High		Low
December 1, 2004 to November 30, 2005	US$	4.10	US$	0.60
December 1, 2005 to November 30, 2006	US$	12.25	US$	2.58
December 1, 2006 to November 30, 2007	US$	11.40	US$	2.80
December 1, 2007 to November 30, 2008	US$	3.50	US$	0.50
December 1, 2008 to November 30, 2009	US$	1.10	US$	0.40
December 1, 2009 to November 30, 2010	US$	1.20	US$	0.33

Period		High		Low
December 2008 to February 2009	US$	0.90	US$	0.40
March 2009 to May 2009	US$	1.05	US$	0.45
June 2009 to August 2009	US$	1.10	US$	0.50
September 2009 to November 2009	US$	0.90	US$	0.55
December 2009 to February 2010	US$	1.20	US$	0.60
March 2010 to May 2010	US$	0.80	US$	0.33
June 2010 to August 2010	US$	0.41	US$	0.35
September 2010 to November 2010	US$	0.49	US$	0.42

Period		High		Low
August 2010	US$	0.41	US$	0.37
September 2010	US$	0.49	US$	0.37
October 2010	US$	0.48	US$	0.42
November 2010	US$	0.47	US$	0.42
December 2010	US$	0.57	US$	0.43
January 2011	US$	0.68	US$	0.53
February 2011	US$	0.71	US$	0.63
March 2011	US$	0.64	US$	0.51
April 2011	US$	0.59	US$	0.47

B.

Plan of Distribution

Not applicable.

C.

Markets

Our common shares trade on the TSX-V under the symbol “ASX”, on the OTCBB under the symbol “ASXSF” and on the Frankfurt Exchange under the symbol “QLD”. Our shares have traded on the TSX-V and on its predecessor, the Alberta Stock Exchange, since December 5, 1997; the OTCBB since July 16, 2002.  However, no trades in our common shares occurred on the OTCBB market until January 29, 2003.

D.

Selling Shareholders

Not applicable.

E.

Dilution

Not applicable.

F.

Expenses of the Issue

Not applicable.

ITEM 10 - ADDITIONAL INFORMATION

A.

Share Capital

Not required, as this form 20-F filing is made as an Annual Report.

B.

Memorandum and Articles of Association

The information required by this Section was previously disclosed, along with our Certificate of Incorporation, Certificate of Amendment, Registration of Restated Articles, Bylaws and Articles of Association, all of which is hereby incorporated by reference, in our Form 20-F registration statement filed with the Securities and Exchange Commission on June 8, 2001.

C.

Material Contracts

We are a party to the following material contracts for the two years preceding publication of this Annual Report, all of which are referred to in the exhibits section of this Annual Report:

1.

Employment Agreement between Tim Coupland and the Company with respect to services in the capacity of President and Chief Executive Officer at an annual salary of $200,000 (filed as an exhibit to Form 20-F filed April 8, 2008);

2.

Financial Public Relations Service Agreement with Progressive IR Consultants Corp. and the Company dated November 4, 2009 with respect to services in the capacity of Public Relation Advisors for fees of $7,500 per month as filed as an exhibit to this Form 20-F.

D.

Exchange Controls

There is no law or governmental decree or regulation in Canada that restricts the export or import of capital, or affects the remittance of dividends, interest or other payments to a non-resident holder of Common Shares, other than withholding tax requirements. Any such remittances to United States residents are generally subject to withholding tax, however no such remittances are likely in the foreseeable future. See “Taxation”, below.

There is no limitation imposed by the laws of Canada or by our charter or other constituent documents on the right of a non-resident to hold or vote the Common Shares, other than as provided in theInvestment Canada Act (Canada) (the “Investment Act”). The following discussion summarizes the material features of the Investment Act for a non-resident who proposes to acquire a controlling number of our Common Shares.  It is general only, it is not a substitute for independent advice from an investor’s own advisor, and it does not anticipate statutory or regulatory amendments. We do not believe the Investment Act will have any effect on us or on our non-Canadian shareholders due to a number of factors including the nature of our operations and our relatively small capitalization.

The Investment Act generally prohibits implementation of a “reviewable” investment by an individual, government or agency thereof, corporation, partnership, trust or joint venture (each an “entity”) that is not a “Canadian” as defined in the Investment Act (a “non-Canadian”), unless after review the Director of Investments appointed by the minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. The size and nature of a proposed transaction may give rise to an obligation to notify the Director to seek an advance ruling. An investment in our Common Shares by a non-Canadian (other than a “WTO Investor” as that term is defined in the Investment Act and which term includes entities which are nationals of or are controlled by nationals of member states of the World Trade Organization) when we are not controlled by a WTO Investor, would be reviewable under the Investment Act if it was an investment to acquire control of us and the value of our assets, as determined in accordance with the regulations promulgated under the Investment Act, was over a certain figure, or if an order for review was made by the federal cabinet on the grounds that the investment related to Canada’s cultural heritage or national identity, regardless of the value of our assets. An investment in our Common Shares by a WTO Investor, or by a non-Canadian when we are controlled by a WTO Investor, would be reviewable under the Investment Act if it was an investment to acquire control of us and the value of our assets, as determined in accordance with the regulations promulgated under the Investment Act, was not less than a specified amount, which for 2010 exceeds CAD$299 million. A non-Canadian would acquire control of us for the purposes of the Investment Act if the non-Canadian acquired a majority of our Common Shares. The acquisition of less than a majority but one-third or more of our Common Shares would be presumed to be an acquisition of control of us unless it could be established that, on the acquisition, we were not controlled in fact by the acquiror through the ownership of our Common Shares.

E.

Taxation

Certain U.S. Federal Income Tax Considerations

The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership, and disposition of common shares.

This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of common shares.  In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including specific tax consequences to a U.S. Holder under an applicable tax treaty.  Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder.  Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local tax, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the “IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares.  This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary.  In addition, because the authorities on which this summary is based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the positions taken in this summary.

Scope of this Summary

Authorities

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, U.S. court decisions, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Canada-U.S. Tax Convention”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document.  Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary.  This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis.

U.S. Holders

For purposes of this summary, the term "U.S. Holder" means a beneficial owner of common shares that is for U.S. federal income tax purposes:

·

an individual who is a citizen or resident of the U.S.;

·

a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) organized under the laws of the U.S., any state thereof or the District of Columbia;

·

an estate whose income is subject to U.S. federal income taxation regardless of its source; or

·

a trust that (1) is subject to the primary supervision of a court within the U.S. and the control of one or more U.S. persons for all substantial decisions or (2) has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

Non-U.S. Holders

For purposes of this summary, a “non-U.S. Holder” is a beneficial owner of common shares that is not a U.S. Holder.  This summary does not address the U.S. federal income tax consequences to non-U.S. Holders arising from and relating to the acquisition, ownership, and disposition of common shares.  Accordingly, a non-U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local tax, and foreign tax consequences (including the potential application of and operation of any income tax treaties) relating to the acquisition, ownership, and disposition of common shares.

U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed

This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including the following U.S. Holders:  (a) U.S. Holders that are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) U.S. Holders that are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) U.S. Holders that are dealers in securities or currencies or U.S. Holders that are traders in securities that elect to apply a mark-to-market accounting method; (d) U.S. Holders that have a “functional currency” other than the U.S. dollar; (e) U.S. Holders that own common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) U.S. Holders that acquired common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) U.S. Holders that hold common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); (h) partnerships and other pass-through entities (and investors in such partnerships and entities); or (i) U.S. Holders that own or have owned  (directly, indirectly, or by attribution) 10% or more of the total combined voting power of the outstanding shares of the Company.  This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are (a) U.S. expatriates or former long-term residents of the U.S. subject to Section 877 of the Code, (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Tax Act; (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold common shares in connection with carrying on a business in Canada; (d) persons whose common shares constitute “taxable Canadian property” under the Tax Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Canada-U.S. Tax Convention.  U.S. Holders that are subject to special provisions under the Code, including U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local tax, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

If an entity that is classified as a partnership for U.S. federal income tax purposes holds common shares, the U.S. federal income tax consequences to such partnership and the partners of such partnership generally will depend on the activities of the partnership and the status of such partners.  Partners of entities that are classified as partnerships for U.S. federal income tax purposes should consult their own tax advisor regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of common shares.

Tax Consequences Not Addressed

This summary does not address the U.S. state and local, U.S. federal estate and gift, U.S. federal alternative minimum tax or foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of common shares.  Each U.S. Holder should consult its own tax advisor regarding the U.S. state and local, U.S. federal estate and gift, U.S. federal alternative minimum tax and foreign tax consequences of the acquisition, ownership, and disposition of common shares.

Passive Foreign Investment Company Rules

If the Company is considered a “passive foreign investment company” under the meaning of Section 1297 of the Code (a “PFIC”) at any time during a U.S. Holder’s holding period, the following sections will generally describe the U.S. federal income tax consequences to the U.S. Holder of the acquisition, ownership, and disposition of common shares.

PFIC Status of the Company

The Company generally will be a PFIC if, for a tax year, (a) 75% or more of the gross income of the Company for such tax year is passive income or (b) 50% or more of the value of our assets either produce passive income or are held for the production of passive income, based on the quarterly average of the fair market value of such assets.  “Gross income” generally means all revenues less the cost of goods sold, and “passive income” generally includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions.

Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all of a foreign corporation’s commodities are (a) stock in trade of such foreign corporation or other property of a kind which would properly be included in inventory of such foreign corporation, or property held by such foreign corporation primarily for sale to customers in the ordinary course of business, (b) property used in the trade or business of such foreign corporation that would be subject to the allowance for depreciation under Section 167 of the Code, or (c) supplies of a type regularly used or consumed by such foreign corporation in the ordinary course of its trade or business.

For purposes of the PFIC income test and asset test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other corporation and (b) received directly a proportionate share of the income of such other corporation.  In addition, for purposes of the PFIC income test and asset test described above, “passive income” does not include any interest, dividends, rents, or royalties that are received or accrued by the Company from a “related person” (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.

In addition, under certain attribution rules, if the Company is a PFIC, U.S. Holders will be deemed to own their proportionate share of any subsidiary of the Company which is also a PFIC (a ‘‘Subsidiary PFIC’’), and will be subject to U.S. federal income tax on their proportionate share of (i) a distribution on the shares of a Subsidiary PFIC and (ii) a disposition or deemed disposition  of shares of a Subsidiary PFIC, both as if such U.S. Holders directly held the shares of such Subsidiary PFIC.

The Company believes that it qualified as a PFIC during prior tax years.  However, no determination has been made regarding our PFIC status for the tax year ending November 30, 2010.  The determination of whether a corporation was, or will be, a PFIC for a tax year depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations.  In addition, whether a corporation will be a PFIC for any tax year depends on the assets and income of such corporation over the course of each such tax year and, as a result, cannot be predicted with certainty as of the date of this document.  Accordingly, there can be no assurance that the IRS will not challenge any determination made by the Company (or a Subsidiary PFIC) concerning its PFIC status.  Each U.S. Holder should consult its own tax advisor regarding the PFIC status of the Company and each Subsidiary PFIC.

Default PFIC Rules Under Section 1291 of the Code

If the Company is a PFIC, the U.S. federal income tax consequences to a U.S. Holder of the acquisition, ownership, and disposition of common shares will depend on whether such U.S. Holder makes an election to treat the Company as a “qualified electing fund” or “QEF” under Section 1295 of the Code (a “QEF Election”) or a mark-to-market election under Section 1296 of the Code (a “Mark-to-Market Election”).  A U.S. Holder that does not make either a QEF Election or a Mark-to-Market Election will be referred to in this summary as a “Non-Electing U.S. Holder.”

A Non-Electing U.S. Holder will be subject to the rules of Section 1291 of the Code with respect to (a) any gain recognized on the sale or other taxable disposition of common shares and (b) any excess distribution received on the common shares.  A distribution generally will be an “excess distribution” to the extent that such distribution (together with all other distributions received in the current tax year) exceeds 125% of the average distributions received during the three preceding tax years (or during a U.S. Holder’s holding period for the common shares, if shorter).

Under Section 1291 of the Code, any gain recognized on the sale or other taxable disposition of common shares, and any “excess distribution” received on common shares, must be ratably allocated to each day in a Non-Electing U.S. Holder’s holding period for the respective common shares.  The amount of any such gain or excess distribution allocated to the tax year of disposition or distribution of the excess distribution and to years before the entity became a PFIC, if any, would be taxed as ordinary income.  The amounts allocated to any other tax year would be subject to U.S. federal income tax at the highest tax applicable to ordinary income in each such year, and an interest charge would be imposed on the tax liability for each such year, calculated as if such tax liability had been due in each such year.  A Non-Electing U.S. Holder that is not a corporation must treat any such interest paid as “personal interest,” which is not deductible.

If the Company is a PFIC for any tax year during which a Non-Electing U.S. Holder holds common shares, the Company will continue to be treated as a PFIC with respect to such Non-Electing U.S. Holder, regardless of whether the Company ceases to be a PFIC in one or more subsequent tax years.  A Non-Electing U.S. Holder may terminate this deemed PFIC status by electing to recognize gain (which will be taxed under the rules of Section 1291 of the Code discussed above) as if such common shares were sold on the last day of the last tax year for which the Company was a PFIC.

QEF Election

A U.S. Holder that makes a QEF Election for the first tax year in which its holding period of its common shares begins, generally, will not be subject to the rules of Section 1291 of the Code discussed above with respect to its common shares.  However, a U.S. Holder that makes a QEF Election will be subject to U.S. federal income tax on such U.S. Holder’s pro rata share of (a) the net capital gain of the Company, which will be taxed as long-term capital gain to such U.S. Holder, and (b) and the ordinary earnings of the Company, which will be taxed as ordinary income to such U.S. Holder.  Generally, “net capital gain” is the excess of (a) net long-term capital gain over (b) net short-term capital loss, and “ordinary earnings” are the excess of (a) “earnings and profits” over (b) net capital gain.  A U.S. Holder that makes a QEF Election will be subject to U.S. federal income tax on such amounts for each tax year in which the Company is a PFIC, regardless of whether such amounts are actually distributed to such U.S. Holder by the Company.  However, for any tax year in which the Company is a PFIC and has no net income or gain, U.S. Holders that have made a QEF Election would not have any income inclusions as a result of the QEF Election.  If a U.S. Holder that made a QEF Election has an income inclusion, such a U.S. Holder may, subject to certain limitations, elect to defer payment of current U.S. federal income tax on such amounts, subject to an interest charge.  If such U.S. Holder is not a corporation, any such interest paid will be treated as “personal interest,” which is not deductible.

A U.S. Holder that makes a QEF Election generally (a) may receive a tax-free distribution from the Company to the extent that such distribution represents “earnings and profits” of the Company that were previously included in income by the U.S. Holder because of such QEF Election and (b) will adjust such U.S. Holder’s tax basis in the common shares to reflect the amount included in income or allowed as a tax-free distribution because of such QEF Election.  In addition, a U.S. Holder that makes a QEF Election generally will recognize capital gain or loss on the sale or other taxable disposition of common shares.

The procedure for making a QEF Election, and the U.S. federal income tax consequences of making a QEF Election, will depend on whether such QEF Election is timely.  A QEF Election will be treated as “timely” if such QEF Election is made for the first year in the U.S. Holder’s holding period for the common shares in which the Company was a PFIC.  A U.S. Holder may make a timely QEF Election by filing the appropriate QEF Election documents at the time such U.S. Holder files a U.S. federal income tax return for such year.

A QEF Election will apply to the tax year for which such QEF Election is made and to all subsequent tax years, unless such QEF Election is invalidated or terminated or the IRS consents to revocation of such QEF Election.  If a U.S. Holder makes a QEF Election and, in a subsequent tax year, the Company ceases to be a PFIC, the QEF Election will remain in effect (although it will not be applicable) during those tax years in which the Company is not a PFIC.  Accordingly, if the Company becomes a PFIC in another subsequent tax year, the QEF Election will be effective and the U.S. Holder will be subject to the QEF rules described above during any subsequent tax year in which the Company qualifies as a PFIC.

U.S. Holders should be aware that there can be no assurance that we will satisfy record keeping requirements that apply to a QEF, or that we will supply U.S. Holders with information that such U.S. Holders require to report under the QEF rules, in event that we are a PFIC and a U.S. Holder wishes to make a QEF Election.  Thus, US Holders may not be able to make a QEF Election with respect to their common shares.  Each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the availability of, and procedure for making, a QEF Election.  .

Mark-to-Market Election

A U.S. Holder may make a Mark-to-Market Election only if the common shares are marketable stock.  The common shares generally will be “marketable stock” if the common shares are regularly traded on (a) a national securities exchange that is registered with the Securities and Exchange Commission, (b) the national market system established pursuant to section 11A of the Securities and Exchange Act of 1934, or (c) a foreign securities exchange that is regulated or supervised by a governmental authority of the country in which the market is located, provided that (i) such foreign exchange has trading volume, listing, financial disclosure, and other requirements and the laws of the country in which such foreign exchange is located, together with the rules of such foreign exchange, ensure that such requirements are actually enforced and (ii) the rules of such foreign exchange ensure active trading of listed stocks.  If such stock is traded on such a qualified exchange or other market, such stock generally will be “regularly traded” for any calendar year during which such stock is traded, other than in de minimis quantities, on at least 15 days during each calendar quarter.

A U.S. Holder that makes a Mark-to-Market Election with respect to its common shares generally will not be subject to the rules of Section 1291 of the Code discussed above with respect to such common shares.  However, if a U.S. Holder does not make a Mark-to-Market Election beginning in the first tax year of such U.S. Holder’s holding period for the common shares or such U.S. Holder has not made a timely QEF Election, the rules of Section 1291 of the Code discussed above will apply to certain dispositions of, and distributions on, the common shares.

A U.S. Holder that makes a Mark-to-Market Election will include in ordinary income, for each tax year in which the Company is a PFIC, an amount equal to the excess, if any, of (a) the fair market value of the common shares, as of the close of such tax year over (b) such U.S. Holder’s tax basis in such common shares.  A U.S. Holder that makes a Mark-to-Market Election will be allowed a deduction in an amount equal to the excess, if any, of (i) such U.S. Holder’s adjusted tax basis in the common shares, over (ii) the fair market value of such common shares (but only to the extent of the net amount of previously included income as a result of the Mark-to-Market Election for prior tax years).

A U.S. Holder that makes a Mark-to-Market Election generally also will adjust such U.S. Holder’s tax basis in the common shares to reflect the amount included in gross income or allowed as a deduction because of such Mark-to-Market Election.  In addition, upon a sale or other taxable disposition of common shares, a U.S. Holder that makes a Mark-to-Market Election will recognize ordinary income or ordinary loss (not to exceed the excess, if any, of (a) the amount included in ordinary income because of such Mark-to-Market Election for prior tax years over (b) the amount allowed as a deduction because of such Mark-to-Market Election for prior tax years).

A Mark-to-Market Election applies to the tax year in which such Mark-to-Market Election is made and to each subsequent tax year, unless the common shares cease to be “marketable stock” or the IRS consents to revocation of such election.  Each U.S. Holder should consult its own tax advisor regarding the availability of, and procedure for making, a Mark-to-Market Election.

Although a U.S. Holder may be eligible to make a Mark-to-Market Election with respect to the common shares, no such election may be made with respect to the stock of any Subsidiary PFIC that a U.S. Holder is treated as owning, because such stock is not marketable.  Hence, the Mark-to-Market Election will not be effective to eliminate the interest charge described above with respect to deemed dispositions of Subsidiary PFIC stock or distributions from a Subsidiary PFIC.

Other PFIC Rules

Under Section 1291(f) of the Code, the IRS has issued proposed Treasury Regulations that, subject to certain exceptions, would cause a U.S. Holder that had not made a timely QEF Election to recognize gain (but not loss) upon certain transfers of common shares that would otherwise be tax-deferred (e.g., gifts and exchanges pursuant to corporate reorganizations).  However, the specific U.S. federal income tax consequences to a U.S. Holder may vary based on the manner in which common shares are transferred.

Certain additional adverse rules will apply with respect to a U.S. Holder if the Company is a PFIC, regardless of whether such U.S. Holder makes a QEF Election.  For example under Section 1298(b)(6) of the Code, a U.S. Holder that uses common shares as security for a loan will, except as may be provided in Treasury Regulations, be treated as having made a taxable disposition of such common shares.

Special rules also apply to the amount of foreign tax credit that a U.S. Holder may claim on a distribution from a PFIC.  Subject to such special rules, foreign taxes paid with respect to any distribution in respect of stock in a PFIC are generally eligible for the foreign tax credit.  The rules relating to distributions by a PFIC and their eligibility for the foreign tax credit are complicated, and a U.S. Holder should consult with their own tax advisor regarding the availability of the foreign tax credit with respect to distributions by a PFIC.

In addition, a U.S. Holder who acquires common shares from a decedent will not receive a “step up” in tax basis of such common shares to fair market value.

The PFIC rules are complex, and each U.S. Holder should consult its own tax advisor regarding the PFIC rules and how the PFIC rules may affect the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares.

U.S. Federal Income Tax Consequences of the Acquisition, Ownership, and Disposition of Common Shares

The following discussion is subject to the rules described above under the heading “Passive Foreign Investment Company Rules”..

General Taxation of Distributions

Subject to the PFIC rules discussed above, a U.S. Holder that receives a distribution, including a constructive distribution, with respect to a Common Share will be required to include the amount of such distribution in gross income as a dividend (without reduction for any Canadian income tax withheld from such distribution) to the extent of the current or accumulated “earnings and profits” of the Company, as computed for U.S. federal income tax purposes.  A dividend generally will be taxed to a U.S. Holder at ordinary income tax rates.  To the extent that a distribution exceeds the current and accumulated “earnings and profits” of the Company, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder's tax basis in the common shares and thereafter as gain from the sale or exchange of such common shares.  (See “ Sale or Other Taxable Disposition of common shares” below).  However, the Company may not maintain the calculations of earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder should therefore assume that any distribution by the Company with respect to the common shares will constitute ordinary dividend income.  Dividends received on common shares generally will not be eligible for the “dividends received deduction”.  

For the tax years beginning before January 1, 2013, a dividend paid by the Company to a U.S. Holder who is an individual, estate or trust, generally will be taxed at the preferential tax rates applicable to long-term capital gains if the Company is a “qualified foreign corporation” (QFC”) and certain holding period requirements for the Common Shares are met.  The cCompany generally will be a QFC as defined under Section 1(h)(11) of the Code if the Company is eligivle for the benefits of the Canada-U.S. Tax Convention or its shares are readily tradable on an established securities market in the U.S..  However, even if the Company satisfies one or more of these requirements, the Company will not be treated as a QFC if the Company is a PFIC for the tax year during which it pays a dividend or for the preceding tax year.  See the section below under the heading “Passive Foreign Investment Company Rules” above.

If a U.S. Holder is not eligible for the preferential tax rates discussed above, a dividend paid by the Company to a U.S. Holder generally will be taxed at ordinary income tax rates (and not at the preferential tax rates applicable to long-term capital gains).  The dividend rules are complex, and each U.S. Holder should consult its own tax advisory regarding the application of such rules.

Sale or Other Taxable Disposition of Common Shares

Subject to the PFIC rules discussed above, upon the sale or other taxable disposition of common shares, a U.S. Holder generally will recognize capital gain or loss in an amount equal to the difference between the amount of cash plus the fair market value of any property received and such U.S. Holder's tax basis in such common shares sold or otherwise disposed of.  Subject to the PFIC rules discussed above, gain or loss recognized on such sale or other disposition generally will be long-term capital gain or loss if, at the time of the sale or other disposition, the common shares have been held for more than one year.

Gain or loss recognized by a U.S. Holder on the sale or other taxable disposition of common shares generally will be treated as “U.S. source” for purposes of applying the U.S. foreign tax credit rules unless the gain is subject to tax in Canada and is resourced as “foreign source” under the Canada-U.S. Tax Convention and such U.S. Holder elects to treat such gain or loss as “foreign source.”

Preferential tax rates apply to long-term capital gain of a U.S. Holder that is an individual, estate, or trust.  There are currently no preferential tax rates for long-term capital gain of a U.S. Holder that is a corporation.  Deductions for capital losses are subject to significant limitations under the Code.

Receipt of Foreign Currency

The amount of any distribution paid to a U.S. Holder in foreign currency, or on the sale, exchange or other taxable disposition of common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time).  If the foreign currency received is not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt.  Any U.S. Holder who receives payment in foreign currency and engages in a subsequent conversion or other disposition of the foreign currency may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes.  Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.

Foreign Tax Credit

Subject to the PFIC rules discussed above, a U.S. Holder who pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on the common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax paid.  Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax.  This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.

Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income.  In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.”  In addition, this limitation is calculated separately with respect to specific categories of income.  Dividends paid by the Company generally will constitute “foreign source” income and generally will be categorized as “passive category income.”  The foreign tax credit rules are complex, and each U.S. Holder should consult its own tax advisor regarding the foreign tax credit rules.

Backup Withholding and Information Reporting

Under U.S. federal income tax law and Treasury regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation.  Penalties for failure to file certain of these information returns are substantial.  U.S. Holders should consult with their own tax advisors regarding the requirements of filing information returns, and, if applicable mark-to-market and QEF elections.

Payments made within the U.S. or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, common shares generally may be subject to information reporting and backup withholding tax, at the rate of 28%, (and increasing to 31% for payments made after December 31, 2012) if a U.S. Holder (a) fails to furnish such U.S.  Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax.  However, certain exempt persons, such as corporations, generally are excluded from these information reporting and backup withholding rules.  Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner.  Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.

Certain Canadian Federal Income Tax Consequences

The following discussion summarizes the principal Canadian federal income tax considerations generally applicable to a person who owns one or more common shares of the Company (the "Shareholder"), and who at all material times for the purposes of the Income Tax Act (Canada)  (the  "Canadian  Act") deals at arm's length with the Company,  holds all common shares solely as capital property, is a  non-resident  of Canada,  and does not, and is not deemed to, use or hold any Common  share in or in the course of  carrying  on  business  in  Canada.  It is assumed that the common shares will at all material times be listed on a stock exchange that is prescribed for the purposes of the Canadian Act.  

This summary is based on the current provisions of the Canadian Act, including the regulations  thereunder,  and the Canada-United States Income Tax Convention (1980) (the  "Treaty") as amended.  This summary takes into account all specific proposals  to amend the Canadian Act and the  regulations  thereunder  publicly announced  by the  government  of Canada to the date  hereof  and the  Company's understanding of the current published administrative and assessing practices of Canada Customs and Revenue  Agency.  It is assumed that all such amendments will be enacted substantially as currently proposed, and that there will be no other material change to any such law or practice, although no assurances can be given in these respects. Except to the extent otherwise expressly set out herein, this summary does not take into account any provincial, territorial or foreign income tax law or treaty.

This summary is not, and is not to be construed as, tax advice to any particular Shareholder. Each prospective and current Shareholder is urged to obtain independent advice as to the Canadian income tax consequences of an investment in common shares applicable to the Shareholder's particular circumstances.

A Shareholder generally will not be subject to tax pursuant to the Canadian Act on any capital gain realized by the Shareholder on a disposition of a Common share unless the Common share constitutes "taxable Canadian property" to the Shareholder for purposes of the Canadian Act and the Shareholder is not eligible for relief pursuant to an applicable bilateral tax treaty.  A Common share that is disposed of by a Shareholder will not constitute taxable Canadian property of the  Shareholder  provided  that the Common share is listed on a stock  exchange that is  prescribed  for the purposes of the  Canadian  Act (the  Toronto  Stock Exchange is so prescribed),  and that neither the  Shareholder,  nor one or more persons  with  whom  the  Shareholder  did not deal at  arm's  length,  alone or together at any time in the five years  immediately  preceding  the  disposition owned,  or owned any right to acquire,  25% or more of the issued  shares of any class of the capital  stock of the Company.  In addition,  the Treaty  generally will  exempt a  Shareholder  who is a  resident  of the  United  States  for the purposes of the Treaty, and who would otherwise be liable to pay Canadian income tax  in  respect  of  any  capital  gain  realized  by  the  Shareholder  on the disposition of a Common share,  from such  liability  provided that the value of the  Common  share is not  derived  principally  from real  property  (including resource property) situated in Canada or that the Shareholder does not have, and has not had within the 12-month period preceding the  disposition,  a "permanent establishment"  or "fixed  base," as those terms are defined for the purposes of the  Treaty,  available  to the Shareholder  in  Canada.  The Treaty may not be available to a  non-resident Shareholder that is a U.S. LLC, which is not subject to tax in the U.S. Any dividend on a Common share, including a stock dividend, paid or credited, or deemed to be paid or credited,  by the Company to a Shareholder  will be subject to  Canadian  withholding  tax at the  rate of 25% on the gross  amount  of the dividend, or such lesser rate as may be available under an applicable income tax treaty.  Pursuant to the Treaty, the rate of withholding tax applicable to a dividend paid on a Common share to a Shareholder who is a resident of the United States for the purposes of the Treaty will be reduced to 5% if the beneficial owner of the dividend is a company that owns at least 10% of the voting stock of the Company, and in any other case will be reduced to 15%, of the gross amount of the dividend.  It is Canada Customs and Revenue Agency’s position that the Treaty reductions are not available to a Shareholder that is a "limited liability company" resident in the United States. The Company will be required to withhold any such tax from the dividend, and remit the tax directly to Canada Customs and Revenue Agency for the account of the Shareholder.

ALL PROSPECTIVE INVESTORS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE SPECIFIC TAX CONSEQUENCES OF PURCHASING THE COMMON SHARES.

F.

Dividends and Paying Agents

Not applicable.

G.

Statement by Experts

Not applicable.

H.

Documents on Display

You may review a copy of our filings with the SEC, including exhibits and schedules filed with it, in the SEC's Public Reference Room at 100 F Street NE, Washington, D.C. 20549. You may call the SEC at 1-800-SEC-0330 or the Conventional Reading Rooms’ Headquarters Office at 212-551-8090 for further information on the public reference rooms. The SEC maintains a web site (www.sec.gov) that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC.

I.

Subsidiary Information

Not applicable.

ITEM 11 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

A.  Quantitative Information About Market Risk

Transaction Risk and Currency Risk Management

Our operations do not employ financial instruments or derivatives; and given that we keep our excess funds in high-grade short-term instruments, there are no significant or unusual financial market risks.

B.  Qualitative Information About Market Risk

Exchange Rate Sensitivity

A significant portion of our administrative operations and other operations are denominated in Canadian funds, there is little exposure to foreign exchange movements between the Canadian and international currencies.

We typically hold most of our funds in Canadian dollars and report the results of our operations in Canadian dollars and are therefore are not subject to any material exchange rate risk.

We do not hedge foreign currency risk, and it does not consider this exposure to be material in the context of its operations.

There has been virtually no difference in our operations due to the affect of foreign exchange rate fluctuation in the period ended November 30, 2010.

Interest Rate Risk and Equity Price Risk

We are primarily equity financed and do not have any long term debt and, therefore, do not believe that the interest rate market’s risk is material.

Commodity Price Risk

While the value of our resource properties, if any, can always be said to relate to the price of precious metals and the outlook for same, we do not have any operating mines and hence does not have any hedging or other commodity based operations risks respecting our business activities. We are exposed to market risk, primarily related to fluctuating prices in our common stock.  See “Risk Factors”.

ITEM 12 - DESCRIPTIONS OF SECURITIES OTHER THAN EQUITY SECURITIES

Not applicable.

PART II

ITEM 13 - DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

Not applicable.

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

A-D.

None.

E. Use of Proceeds

Not applicable.

ITEM 15 - CONTROLS AND PROCEDURES

A.    Disclosure Controls and Procedures  

At the end of the period covered by this annual report for the fiscal year ended November 30, 2010, an evaluation was carried out under the supervision of, and with the participation of, our management, including our Chief Executive Officer (CEO) and Chief Financial Officer (CFO), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act).  Based upon that evaluation, our CEO and CFO have concluded that the disclosure controls and procedures were effective to give reasonable assurance that the information required to be disclosed by us in reports that are filed or submitted under the Exchange Act are (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

B.    Management’s Annual Report on Internal Control over Financial Reporting  

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act.  A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles

A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.  It should be noted that a control system, no matter how well conceived or operated, can only provide reasonable assurance, not absolute assurance, that the objectives of the control system are met.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

Management, including the CEO and CFO, assessed the effectiveness of our internal control over financial reporting as of November 30, 2010.  In making this assessment, management used the criteria set forth in the Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).  Based on our assessment, management has concluded that, as of November 30, 2010, our internal control over financial reporting was effective and no material weaknesses in our internal control over financial reporting were discovered.

C.    Attestation Report of the Registered Public Accounting Firm

This Annual Report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, which permits the company to provide only management’s report in this Annual Report. The Dodd-Frank Act permits a “non-accelerated filer” to provide only management’s report on internal control over financial reporting in an Annual Report and omit an attestation report of the issuer’s registered public accounting firm regarding management’s report on internal control over financial reporting.

D.    Changes in Internal Control Over Financial Reporting

Based upon their evaluation of our controls, senior management of the Company have concluded that, there were no significant changes in our internal control over financial reporting or in other factors during our last fiscal year that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 16A - AUDIT COMMITTEE FINANCIAL EXPERT

Our Board of Directors has determined that Stuart Rogers, a member of our Audit Committee, is the Audit Committee financial expert and an independent director as defined in Item 16A of Form 20-F and section 803 of the NYSE AMEX Company Guide.

ITEM 16B - CODE OF ETHICS

We have adopted a written Code of Ethics that applies to all employees and executive officers, including our Chief Executive Officer and Chief Financial Officer.  A copy of the Code of Ethics is available on our website at www.alberta-star.com.

During the most recently completed fiscal year, we had neither: (a) amended our Code of Ethics; nor (b) granted any waiver (including any implicit waiver) form any provision of our Code of Ethics.

ITEM 16C - PRINCIPAL ACCOUNTANT FEES AND SERVICES

Fees and Services

James Stafford, Chartered Accountants, audited our financial statements for fiscal 2010 and 2009, and reviewed our first quarterly statement ended February 28, 2009.   The following is an aggregate of fees rendered during each of the years ended November 30, 2010 and 2009 for professional services rendered by our principal accountants:

	2010	2009
Audit fees - auditing of our annual financial statements and preparation of auditors’ report.	$75,759	$67,070
Audit-related fees - review of each of the quarterly financial statements.	-	12,881
Tax fees - preparation	0	20,439
All other fees – other services provided by our principal accountants.	2,003-	-
Total fees paid or accrued to our principal accountants	$77,762	$100,390

Pre-Approval Policies and Procedures

We have adopted certain policies and procedures intend to ensure our principal accountants will maintain objectivity and independence in their audit of our financial statements. To minimize relationships that could appear to impair the objectivity of our principal accountants, our audit committee has restricted the non-audit services that our principal accountants may provide to us primarily to tax services and review assurance services.

In general, we seek to obtain non-audit services from our principal accountants only when the services offered by our principal accountants are more effective or economical than services available from other service providers, and, to the extent possible, only after competitive bidding. These determinations are among the key practices adopted by the audit committee effective during fiscal 2010. The board has adopted policies and procedures for pre-approving work performed by our principal accountants.

After careful consideration, the audit committee of the board of directors has determined that payment of the above audit fees is in conformance with the independent status of our company’s principal independent accountants. Before engaging the auditors in additional services, the audit committee considers how these services will impact the entire engagement and independence factors.

The Audit Committee has pre-approved specifically identified non-audit related services, including tax compliance, review of tax returns, and documentation of processes and controls as submitted to the Audited Committee from time to time.

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

None.

ITEM 16E - PURCHASES OF EQUITY SECURITIES BY THE ISSUERS AND AFFILIATED PURCHASERS

We did not repurchase any common shares in the fiscal year ended November 30, 2010.

ITEM 16F – CHANGE IN CERTIFYING ACCOUNTANT

None.

ITEM 16G – CORPORATE GOVERNANCE

Not applicable.

PART III

ITEM 17 - FINANCIAL STATEMENTS

The financial statements appear on Pages F-1 through F-41 of this Annual Report and are incorporated herein by reference.  Our audited financial statements as prepared by our management and approved by the audit committee include:

·

our balance sheets as at November 30, 2010, and 2009;

·

the following statements for the fiscal years ended November 30, 2010, 2009, and 2008, as well as information from our inception to November 30, 2010:

·

statements of loss, comprehensive loss and deficit

·

statements of cash flows; and

·

statements of changes in shareholders’ equity for the fiscal years ended November 30, 2010, 2009 and 2008.

All of these were audited by our auditor, James Stafford, Chartered Accountants.

The financial statements are prepared in accordance with Canadian GAAP and are reconciled to US GAAP in note 19 to the financial statements.   All figures are expressed in Canadian dollars.

ITEM 18 - FINANCIAL STATEMENTS

We elected to provide financial statements pursuant to Item 17.

ITEM 19 - EXHIBITS

The following exhibits are included herein, except for the exhibits marked with a bracketed number, which are incorporated herein by reference.

Exhibit No.	Exhibit Title
1.1(1)	Certificate of Incorporation and Certificate of Amendment and Registration of Restated Articles
1.2(1)	Bylaws
1.3(1)	Articles of Association
4.1(3)	Stock Option Plan as approved annually without change by Shareholders
4.2*(3)	Employment Agreement dated March 30, 2007 between Alberta Star Development Corp. and Mr. Tim Coupland, President and CEO
4.3(3)	Financial Public Relations Service Agreement dated December 15, 2007 between Alberta Star Development Corp. and MI3 Communications Financieres Inc.
4.4(4)	Shareholder Rights Plan Agreement dated October 10, 2008 between Alberta Star Development Corp. and MI3 Computershare Trust Company of Canada
4.5(5)	Financial Public Relations Service Agreement dated November 4, 2009 between Alberta Star Development Corp. and Progressive IR Consultants Corp.
4.6	Agreement of Purchase and Sale made as of August 5, 2010 between Western Plains Petroleum Ltd. and Alberta Star Development Corp.
4.7	Asset Purchase Agreement made as of August 25, 2010 between Western Plains Petroleum Ltd. and Alberta Star Development Corp.
4.8	Sub-participation Agreement made as of October 14, 2010 between Arctic Hunter Uranium Inc. and Alberta Star Development Corp.
4.9	Joint Operating Agreement made as of August 5, 2010 between Western Plains Petroleum Ltd. and Alberta Star Development Corp.
4.10(6)	Statement of Reserve Data and Other Oil and Gas Information effective November 30, 2010
11.1(3)	Code of Ethics
12.1	Certification of Principal Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
12.2	Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
13.1	Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
15.2	Certificate of Consent by Auditor
15.3(2)	Technical Report on the Port Radium – Echo Bay Project dated April 21, 2006 and revised August 10, 2006 prepared by J. Fingler, M.Sc., P.Geo
*	Indicates management contract or compensatory plan or arrangement.
(1)	incorporated by reference from our Form 20-F that was filed with the commission on June 8, 2001.
(2)	incorporated by reference from our Form 6-K that was filed with the commission on August 30, 2006.
(3)	incorporated by reference from our Form 20-F that was filed with the commission on April 8, 2008.
(4)	incorporated by reference from our Form 20-F that was filed with the commission on March 24, 2009.
(5)	Incorporated by reference from our Form 20-F that was filed with the commission on April 12, 2010
(6)	Incorporated by reference from our Form 6-K that was filed with the Commission on  March 30, 2011.

SIGNATURE

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

	ALBERTA STAR DEVELOPMENT CORP.
Dated: May 16, 2011	By: /s/ Tim Coupland
	Tim Coupland, President

35

Alberta Star Development Corp.

(An Exploration Stage Company)

Financial Statements

(Expressed in Canadian Dollars)

30 November 2010

36

JAMES STAFFORD James Stafford, Inc. Chartered Accountants Suite 350 – 1111 Melville Street Vancouver, British Columbia Canada V6E 3V6 Telephone +1 604 669 0711 Facsimile +1 604 669 0754 www.jamesstafford.ca

Report of Independent Registered Chartered Accountants

To the Shareholders of

Alberta Star Development Corp.

We have audited the balance sheets of Alberta Star Development Corp. (an Exploration Stage Company) (the “Company”) as of 30 November 2010 and 2009, the related statements of loss, comprehensive loss and deficit and cash flows for the period from 6 September 1996 (Date of Inception) to 30 November 2010 and for each of the years in the three-year period ended 30 November 2010 and the statements of changes in shareholders’ equity for each of the years in the three-year period ended 30 November 2010.  These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States of America).  Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at 30 November 2010 and 2009 and the results of its operations and its cash flows for the period from 6 September 1996 (Date of Inception) to 30 November 2009 and for each of the years in the three-year period ended 30 November 2010 in accordance with Canadian generally accepted accounting principles.

/s/ James Stafford

Vancouver, Canada

Chartered Accountants

21 March 2011

Comments by Independent Registered Chartered Accountants on Canada – United States of America Reporting Differences

The standards of the Public Company Accounting Oversight Board (United States of America) require the addition of an explanatory paragraph (following the opinion paragraph) when the financial statements are affected by conditions and events that cast substantial doubt on the Company’s ability to continue as a going concern, such as those described in Note 1 of the financial statements.  Although we conducted our audits in accordance with both Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States of America), our report to the Shareholders, dated 21 March 2011, is expressed in accordance with Canadian reporting standards which do not permit a reference to such conditions and events in the report when these are adequately disclosed in the financial statements.

/s/ James Stafford

Vancouver, Canada

Chartered Accountants

21 March 2011

Alberta Star Development Corp.

(An Exploration Stage Company)

Balance Sheets

(Expressed in Canadian Dollars)

As at 30 November

	2010	2009
	$	$
Assets
Current
Cash and cash equivalents (Note 14)	9,456,219	14,700,318
Amounts receivable (Note 4)	247,030	125,865
Prepaid expenses	36,139	25,455
	9,739,388	14,851,638
Property, plant and equipment (Note 5)	3,866,517	373,084
	13,605,905	15,224,722
Liabilities
Current
Accounts payable and accrued liabilities (Notes 8 and 9)	1,713,640	1,718,884
Asset retirement obligations (Note 6)	352,780	-
	2,066,420	1,718,884
Shareholders’ equity
Share capital (Note 10)
Authorized
Unlimited number of preferred shares
Unlimited number of voting common shares
Issued and outstanding
2010 – 21,403,979 common shares
2009 – 21,403,979 common shares	37,397,902	37,397,902
Contributed surplus(Note 10)	13,231,208	13,190,903
Warrants(Note 10)	131,064	131,064
Deficit, accumulated during the exploration stage	(39,220,689)	(37,214,031)
	11,539,485	13,505,838
	13,605,905	15,224,722

Nature and Continuance of Operations(Note 1),Commitments and Other Obligations(Note 12),Reconciliation of Canadian and United States Generally Accepted Accounting Principles (Note 17) andSubsequent Events(Note 18)

On behalf of the Board:

“/s/ Tim Coupland”

Director

“/s/ Robert Hall”

Director

Tim Coupland

Robert Hall

 (1)

Alberta Star Development Corp.

(An Exploration Stage Company)

Statements of Loss, Comprehensive Loss and Deficit

(Expressed in Canadian Dollars)

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Petroleum revenue		371,265		371,265		-		-
Production costs
Accretion (Note 6)		7,550		7,550		-		-
Petroleum depletion, depreciation and amortization (Note 5)		162,722		162,722		-		-
Petroleum production and transportation		178,937		178,937		-		-
Petroleum royalties		44,129		44,129		-		-
Net petroleum income (loss)		(22,073)		(22,073)		-		-
Expenses
Mineral properties (Schedule 1)		31,556,822		324,641		1,313,613		3,612,962
General and administrative (Schedule 2)		20,285,997		1,912,074		2,322,116		3,644,015
Net loss before other items and income taxes		(51,864,892)		(2,258,788)		(3,635,729)		(7,256,977)
Other items
Interest income		3,049,894		34,269		166,287		767,768
Break fee (Note 7)		256,975		256,975		-		-
Foreign exchange loss		(39,114)		(39,114)		-		-
Gain on sale of available-for-sale securities		126,466		-		-		-
Write-down of available-for-sale securities		(10,000)		-		-		-
Write-off of property, plant and equipment		(12,517)		-		-		-
Net loss before income taxes		(48,493,188)		(2,006,658)		(3,469,442)		(6,489,209)
Future income tax recovery(Note 13)		9,833,756		-		104,590		-
Net loss for the period		(38,659,432)		(2,006,658)		(3,364,852)		(6,489,209)
Deficit, accumulated during the exploration stage, beginning of period		-		(37,214,031)		(33,849,179)		(27,359,970)
Adjustment for change in accounting policy		(561,257)		-		-		-
Deficit, accumulated during the exploration stage, end of period		(39,220,689)		(39,220,689)		(37,214,031)		(33,849,179)
Basic and diluted loss per share				(0.094)		(0.157)		(0.310)
Weighted average number of common shares outstanding				21,403,979		21,388,636		20,920,782
Other comprehensive income (loss)
Net loss for the period before other comprehensive income (loss)		(38,659,432)		(2,006,658)		(3,364,852)		(6,489,209)
Unrealized gain on available-for-sale securities		69,000		-		-		-
Realized gain on available-for-sale securities		(69,000)		-		-		-
Comprehensive loss for the period		(38,659,432)		(2,006,658)		(3,364,852)		(6,489,209)
Basic and diluted comprehensive loss per share				(0.094)		(0.157)		(0.310)

 (2)

Alberta Star Development Corp.

(An Exploration Stage Company)

Statements of Cash Flows

(Expressed in Canadian Dollars)

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Cash flows used in operating activities
Net loss for the period		(39,220,689)		(2,006,658)		(3,364,852)		(6,489,209)
Adjustments to reconcile loss to net cash used by operating activities
Acquisition of mineral property interests		1,241,000		-		-		-
Accretion		7,550		7,550		-		-
Amortization of property, plant and equipment		483,875		77,843		97,126		153,352
Petroleum depletion, depreciation and amortization		162,722		162,722		-		-
Gain on sale of available-for-sale securities		(126,466)		-		-		-
Financing fees		38,000		-		-		-
Future income tax recovery		(9,833,756)		-		(104,590)		-
Recovery of mineral property costs		(82,000)		-		-		-
Stock-based compensation		6,742,675		40,305		539,159		548,070
Write-down of available-for-sale securities		10,000		-		-		-
Write-off of property, plant and equipment		233,387		220,870		-		-
Gain on sale of mineral property interests		(16,565)		-		-		-
Changes in operating assets and liabilities
(Increase) decrease in amounts receivable		(247,030)		(121,165)		(64,960)		616,072
(Increase) decrease in prepaid expenses		(36,139)		(10,684)		(25,455)		-
Increase (decrease) in accounts payable and accrued liabilities		1,040,871		(5,244)		(53,849)		(593,310)
		(39,602,565)		(1,634,461)		(2,977,421)		(5,765,025)
Cash flows used in investing activities
Purchase of petroleum interests		(3,584,039)		(3,584,039)		-		-
Purchase of property, plant and equipment		(817,659)		(25,599)		(18,340)		(48,744)
Proceeds on sale of property, plant and equipment		428		-		-		-
Proceeds on sale of available-for-sale securities		215,031		-		-		-
		(4,186,239)		(3,609,638)		(18,340)		(48,744)
Cash flows from financing activities
Issuance of common shares for cash		5,612,822		-		-		-
Issuance of flow-through shares for cash		22,684,064		-		350,000		-
Issuance of warrants for cash		11,099,845		-		-		-
Warrants exercised		14,443,891		-		-		-
Options exercised		1,432,442		-		-		30,000
Share issuance costs		(2,028,041)		-		(21,497)		-
Share subscriptions received in advance		-		-		-		-
		53,245,023		-		328,503		30,000
Increase (decrease) in cash and cash equivalents		9,456,219		(5,244,099)		(2,667,258)		(5,783,769)
Cash and cash equivalents, beginning of period		-		14,700,318		17,367,576		23,151,345
Cash and cash equivalents, end of period		9,456,219		9,456,219		14,700,318		17,367,576

Supplemental Disclosures with Respect to Cash Flows(Note 14)

Alberta Star Development Corp.

(An Exploration Stage Company)

Statements of Changes in Shareholders’ Equity

(Expressed in Canadian Dollars)

	Number of shares issued		Share capital		Contributed surplus and share subscriptions received in advance		Warrants		Accumulated other comprehensive income		Deficit accumulated during the exploration  stage		Total shareholders’ equity
				$		$		$		$		$		$
Balance at 30 November 2007		20,907,312		38,000,821		9,215,360		2,902,233		-		(27,359,970)		22,758,444
Stock options exercised ($1.00 per share)		30,000		43,919		(13,919)		-		-		-		30,000
Warrants expired		-		-		2,508,552		(2,508,552)		-		-		-
Agent compensation warrants expired		-		-		393,681		(393,681)		-		-		-
Stock-based compensation		-		-		548,070		-		-		-		548,070
Provision for flow-through liability (Notes 8, 12 and 14)		-		(739,687)		-		-		-		-		(739,687)
Net loss for the year		-		-		-		-		-		(6,489,209)		(6,489,209)
Balance at 30 November 2008		20,937,312		37,305,053		12,651,744		-		-		(33,849,179)		16,107,618
Flow-through shares issued – cash ($0.75 per unit) (Note 10)		466,667		350,000		-		-		-		-		350,000
Warrants granted		-		(131,064)		-		131,064		-		-		-
Share issue costs – cash paid		-		(21,497)		-		-		-		-		(21,497)
Stock-based compensation (Note 11)		-		-		539,159		-		-		-		539,159
Provision for flow-through liability (Notes 8, 12 and 14)		-		(104,590)		-		-		-		-		(104,590)
Net loss for the year		-		-		-		-		-		(3,364,852)		(3,364,852)
Balance at 30 November 2009		21,403,979		37,397,902		13,190,903		131,064		-		(37,214,031)		13,505,838
Stock-based compensation (Note 11)		-		-		40,305		-		-		-		40,305
Net loss for the year		-		-		-		-		-		(2,006,658)		(2,006,658)
Balance at 30 November 2010		21,403,979		37,397,902		13,231,208		131,064		-		(39,220,689)		11,539,485

 (3)

Alberta Star Development Corp.

(An Exploration Stage Company)

Schedule 1 – Summary of Mineral Properties Expenditures

(Expressed in Canadian Dollars)

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Amortization		355,933		56,877		73,868		132,818
Assays and geochemical		610,679		125		1,097		147,952
Camp costs and field supplies		2,139,570		4,845		120,468		152,275
Claim maintenance and permitting		134,391		2,769		18,668		12,383
Community relations and government		240,027		-		19,153		74,485
Drilling		4,640,068		-		12,304		459,176
Equipment rental		261,492		-		-		5,528
Geology and engineering		1,531,453		27,257		99,875		389,404
Geophysics		19,643		-		-		16,643
Metallurgical studies		62,977		-		-		-
Orthophotography		224,973		-		-		-
Staking and line cutting		842,594		-		78,000		237,944
Surveying		1,813,919		-		-		-
Transportation and fuel		10,502,486		-		214,556		815,291
Wages, consulting and management fees		6,134,658		11,898		675,624		1,181,708
Write-offof field equipment		220,870		220,870		-		-
		29,735,733		324,641		1,313,613		3,625,607
Acquisition of mineral property interests(Notes 7 and 14)		2,831,197		-		-		-
Recovery of mineral property costs(Note 7)		(1,159,095)		-		-		(12,645)
Sales of mineral property interests (Note 7)		(71,565)		-		-		-
Write-off of mineral properties and related costs(Note 7)		220,552		-		-		-
		31,556,822		324,641		1,313,613		3,612,962

Details on Mineral Properties Expenditures(Note 7)

 (4)

Alberta Star Development Corp.

(An Exploration Stage Company)

Schedule 2 – General and Administrative Expenses

(Expressed in Canadian Dollars)

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Advertising and promotion		1,438,551		73,465		30,649		265,378
Amortization		127,941		20,966		23,258		20,534
Automotive		63,984		5,033		4,758		6,999
Bank charges and interest		28,444		965		1,195		3,896
Consulting fees		746,018		241,397		13,438		2,658
Directors fees (Note 9)		342,950		81,000		54,000		121,000
Filing and financing fees		749,721		87,997		153,211		119,881
Legal and accounting (Note 9)		1,998,033		259,616		332,372		349,567
Management fees (Note 9)		850,887		65,000		75,000		50,000
Meals and entertainment		356,872		52,020		78,346		68,989
Office and miscellaneous		850,683		64,404		81,910		136,414
Part XII.6 tax		1,274,716		-		7,392		711,124
Rent and utilities		315,271		50,063		67,199		50,017
Salaries and benefits (Note 9)		1,976,934		523,805		479,878		575,269
Secretarial fees (Note 9)		279,971		15,000		15,000		15,000
Stock-based compensation (Note 11)		6,742,675		40,305		539,159		548,070
Telephone and internet		112,740		14,769		15,843		26,736
Transfer fees and shareholder information		1,670,073		281,879		279,242		477,635
Travel		359,533		34,390		70,266		94,848
		20,285,997		1,912,074		2,322,116		3,644,015

 (5)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

1.

Nature and Continuance of Operations

Alberta Star Development Corp. (the “Company”) was incorporated under the laws of the province of Alberta on 6 September 1996 and is in the exploration stage.  

The Company is in the business of acquiring and exploring mineral and oil and gas properties.  The recoverability of the amounts expended by the Company on acquiring and exploring mineral and oil and gas properties is dependent upon the existence of economically recoverable reserves, the ability of the Company to complete the acquisition and/or development of the properties and upon future profitable production.

The Company’s financial statements as at 30 November 2010 and for the year then ended have been prepared on a going concern basis, which contemplates the realization of assets and the settlement of liabilities and commitments in the normal course of business.  The Company has a loss of $2,006,658 for the year ended 30 November 2010 (2009 - $3,364,852, 2008 - $6,489,209) and has working capital of $8,025,748 at 30 November 2010 (2009 - $13,132,754).

The Company had cash and cash equivalents of $9,456,219 at 30 November 2010 (2009 - $14,700,318), but management cannot provide assurance that the Company will ultimately achieve profitable operations or become cash flow positive, or raise additional debt and/or equity capital.  However, based on its prior demonstrated ability to raise capital, management believes that the Company’s capital resources should be adequate to continue operating and maintain its business strategy during fiscal 2011.  However, if the Company is unable to raise additional capital in the future, management expects that the Company will need to curtail operations, liquidate assets, seek additional capital on less favourable terms and/or pursue other remedial measures.  These financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

On 11 March 2010, the Company consolidated its share capital on a one new common share without par value for every five existing common shares without par value basis.  All common shares and per share amounts have been restated to give retroactive effect to the share consolidation (Note 10).

2.

Significant Accounting Policies

The accounting policies of the Company are in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”).  These policies conform, in all material respects, with accounting principles generally accepted in the United States of America (“United States GAAP”), except as discussed in Note 17. Outlined below are those policies considered particularly significant.

 (6)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Cash and cash equivalents

Cash and cash equivalents include highly liquid investments with original maturities of three months or less.

Property, plant and equipment

Property, plant and equipment are recorded at cost and are amortized over their estimated useful lives using the declining balance method at the following annual rates:

Computer equipment	30%
Computer software	100%
Furniture and fixtures	20%
Field equipment	20%
Office equipment	20%

Amortization of assets used in exploration is expensed to mineral properties expenditures.

Mineral properties and deferred exploration costs

Mineral exploration costs and option maintenance payments are expensed as incurred.  When it has been determined that a mineral property can be economically developed as a result of establishing proven and probable reserves, costs incurred prospectively to develop the property are capitalized as incurred and are depreciated using the unit-of-production depreciation method over the estimated life of the ore body based on proven and probable reserves.

Major development costs incurred after the commencement of production, are capitalized as incurred and are depreciated using the unit-of-production depreciation method based on proven and probable reserves.

Ongoing development expenditures to maintain production are charged to operations as incurred.

Mineral property, deferred exploration costs and option maintenance payments are currently charged to operations as incurred since the Company has not met the criteria for deferral of acquisition and development costs under Canadian GAAP.

Although the Company has taken steps to verify title to mineral properties in which it has an interest, according to the usual industry standards for the stage of exploration of such properties, these procedures do not guarantee the Company’s title.  Such properties may be subject to prior agreements or transfers and title may be affected by undetected defects.

 (7)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Revenue recognition and costs of goods sold

Revenue from the production of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process.

Revenue as reported represents the Company’s share and is presented before royalty payments to governments and other mineral interest owners.

Related costs of goods sold are comprised of production; transportation and blending; and depletion, depreciation and amortization expenses. These amounts have been separately presented in the statements of loss, comprehensive loss and deficit.

Petroleum and natural gas properties

The Company follows the full cost method of accounting for petroleum and natural gas operations whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized.  These costs include land acquisition costs, geological and geophysical expenses, the costs of drilling both productive and non-productive wells, directly related overhead and estimated abandonment costs.  Proceeds from the disposal of properties are deducted from the full cost pool without recognition of a gain or loss unless such a sale would significantly alter the rate of depletion and depreciation.

Depletion and depreciation

Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes before royalties in relation to total estimated proved reserves as determined annually by independent engineers and determined in accordance with National Instrument 51-101.  Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.

Calculations for depletion and depreciation of production equipment are based on total capitalized costs plus estimated future development costs of proved undeveloped reserves.  The costs of acquiring and evaluating unproved properties are excluded from depletion calculations.  These properties are assessed periodically to ascertain whether impairment has occurred.  When the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

Ceiling test

The Company reviews the carrying amount of its petroleum and natural gas properties relative to their recoverable amount at each annual balance sheet date or more frequently if circumstances or events indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash flow from the properties using proved reserves and expected future prices and costs. If the carrying amount of the properties exceeds their recoverable amount, an impairment loss is recognized in depletion and depreciation expense equal to the amount by which the carrying amount of the properties exceeds their fair value. Fair value is calculated as the cash flow from those properties using proved and probable reserve and expected future prices and costs, discounted at a risk-free interest rate.

 (8)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Asset retirement obligations

Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets. The Company recognizes the present value of an asset retirement obligation in the period in which it is incurred and when its fair value can be reasonably estimated. The estimated fair value of asset retirement costs are capitalized as part of the related long-lived asset and depreciated on the same basis as the underlying asset. The asset retirement obligation is adjusted for the passage of time, which is recognized as accretion expense, and for revisions to the timing or the amount of the estimated liability. Actual costs incurred are charged against the asset retirement obligation to the extent of the liability recorded. Differences between the actual costs incurred and the liability are recognized in earnings when reclamation of the field is completed.

Stock-based compensation

Effective 1 December 2002, the Company adopted, on a prospective basis, the provisions of the Canadian Institute of Chartered Accountants (“CICA”) Handbook Section 3870, “Stock-Based Compensation and Other Stock Based Payments”, which establishes standards for the recognition, measurement and disclosure of stock-based compensation and other stock-based payments to both employees and non-employees.  Section 3870 recommends that certain stock-based transactions, such as the grant of stock options, be accounted for at fair value.  The Company uses the Black-Scholes option pricing model to estimate the fair value of each stock option at the granted date.  Any consideration received from the exercise of stock options is credited to share capital.  This section is only applicable to transactions that occurred on or after 1 December 2002.

Loss per share

Basic loss per share is calculated based on the weighted average number of shares outstanding during the period.  The treasury stock method is used for determining the dilutive effect of options and warrants issued in calculating diluted earnings per share.  Under this method, the dilutive effect on loss per share is recognized on the use of the proceeds that could be obtained upon exercise of options, warrants and similar instruments.  It assumes that the proceeds would be used to purchase common shares at the average market price during the year.  For the periods presented, this calculation proved to be anti-dilutive.

Impairment of long-lived assets

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  An impairment loss would be recognized when the carrying amount of an asset exceeds the estimated undiscounted future cash flows expected to result from the use of the asset and its eventual disposition.  The amount of the impairment loss to be recorded is calculated by the excess of the assets carrying value over its fair value.  Fair value is determined using a discounted cash flow analysis.

 (9)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Flow-through common shares

The Company has financed a portion of its exploration activities through the issuance of flow-through shares, which transfers the income tax deductibility of exploration expenditures to the investor.  Proceeds received on the issue of such shares have been credited to share capital and the related exploration costs have been charged to exploration properties and deferred exploration expenditures.  

The Company follows the recommendations of the Emerging Issues Committee (“EIC”) of the CICA with respect to flow-through shares, as outlined in EIC 146, “Flow-through Shares”.  The application of EIC 146 requires the recognition of the foregone tax benefit on the date the Company renounces the tax credits associated with the exploration expenditures, provided there is reasonable assurance that the expenditures will be made.  The recommendations apply to all flow-through share transactions initiated after 19 March 2004.

Income taxes

Future income tax assets and liabilities are determined based on temporary differences between the accounting and the tax bases of the assets and liabilities and for loss carry forwards and are measured using the tax rates expected to apply when these differences reverse.  A valuation allowance is recorded against any future income tax asset if it is not more likely than not that the asset will be realized.  As at 30 November 2010, the Company’s net future income tax assets are fully offset by a valuation allowance.

Foreign currency translation

Transaction amounts denominated in foreign currencies are translated into functional currency at exchange rates prevailing at transaction dates.

Use of estimates

The preparation of financial statements in conformity with Canadian GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenditures during the reported period.  Actual results could differ from these estimates.

 (10)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Financial Instrument Standards

Financial Assets and Financial Liabilities

Financial assets and liabilities are initially recognized at fair value and are subsequently measured based on their classification as held-to-maturity, loans and receivables, available-for-sale or held-for-trading, as described below.  The classification is not changed subsequent to initial recognition.

Held-to-Maturity and Loans and Receivables

Financial instruments that have a fixed maturity date, where the Company intends and has the ability to hold to maturity are classified as held-to-maturity and measured at amortized cost using the effective interest rate method.  Loans and receivables are measured at amortized cost using the effective interest method.

Available-for-Sale

Financial assets classified as available-for-sale are carried at fair value (where determinable based on market prices of actively traded securities) with changes in fair value recorded in other comprehensive income.  Available-for-sale securities are written down to fair value through earnings whenever it is necessary to reflect an other-than-temporary impairment.  Transaction costs that are directly attributable to the acquisition or issue of a financial asset or financial liability are added to its fair value.

Held-for-Trading

Financial assets and financial liabilities that are purchased and incurred with the intention of generating profits in the near term are classified as held-for-trading.  These instruments are measured at fair value with the change in the fair value recognized in income.

Derivatives and Hedge Accounting

The Company does not hold or have any exposure to derivative instruments and accordingly is not impacted by CICA Handbook Section 3865, “Hedges”.

Comprehensive Income

Comprehensive income is composed of the Company’s earnings and other comprehensive income.  Other comprehensive income includes unrealized gains and losses on available-for-sale securities, foreign currency translation gains and losses on the net investment in self-sustaining operations and changes in the fair market value of derivative instruments designated as cash flow hedges, all net of income taxes.  Cumulative changes in other comprehensive income are included in accumulated other comprehensive income which is presented (if applicable) as a new category in shareholders’ equity.

 (11)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

International Financial Reporting Standards

In February 2008, the Accounting Standards Board confirmed that International Financial Reporting Standards (“IFRS”) will replace Canadian GAAP for publicly accountable enterprises for financial periods beginning on and after 1 January 2011. The Company’s first mandatory filing under IFRS, which will be the first quarter of 2012, will contain IFRS-compliant information on a comparative basis, as well as reconciliations for that quarter and as at the 1 December 2010 transition date.  

Comparative figures

Certain comparative figures have been adjusted to conform to the current year’s presentation.  

3.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, amounts receivable, and accounts payable.  The fair value of these financial instruments approximates their carrying values, due to their short-term maturity or capacity of prompt liquidation.

The following is a summary of the accounting model the Company elected to apply to each of its significant categories of financial instruments:

Cash and cash equivalents

Held-for-trading

Amounts receivable

Loans and receivables

Accounts payable

Other liabilities

The CICA Handbook Section 3862, “Financial Instruments – Disclosures” requires disclosure of a three-level hierarchy for fair value measurements based upon transparency of inputs to the valuation of financial instruments carried on the balance sheet at fair value.  The three levels are defined as follows:

Level 1:

inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2:

inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

Level 3:

inputs to the valuation methodology are unobservable and significant to the fair value measurement.

Cash and cash equivalents would be Level 1 fair value.

 (12)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

a)

Credit Risk

Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises primarily from the Company’s cash and cash equivalents and amounts receivable.  The Company manages its credit risk relating to cash and cash equivalents by dealing only with highly-rated Canadian financial institutions.  As at 30 November 2010, amounts receivable were comprised of Harmonized Sales Tax receivable of $34,675 (2009 - $15,810), interest earned on the Company’s redeemable short-term investment of $Nil (2009 - $110,055) and petroleum revenue receivable of $212,355 (2009 - $Nil).  As a result, credit risk is considered insignificant.

b)

Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due.  The Company manages liquidity risk by continuously monitoring actual and projected cash flows and matching the maturity profile of financial assets and liabilities.  As the Company’s financial instruments are substantially comprised of cash and cash equivalents, liquidity risk is considered insignificant.

c)

Currency Risk

The majority of the Company’s cash flows and financial assets and liabilities are denominated in Canadian dollars, which is the Company’s functional and reporting currency.  Foreign currency risk is limited to the portion of the Company’s business transactions denominated in currencies other than the Canadian dollar. The Company has cash and cash equivalents held in US dollars.

The Company’s objective in managing its foreign currency risk is to minimize its net exposures to foreign currency cash flows by holding most of its cash and cash equivalents in Canadian dollars.  The Company monitors and forecasts the values of net foreign currency cash flow and balance sheet exposures and from time to time could authorize the use of derivative financial instruments such as forward foreign exchange contracts to economically hedge a portion of foreign currency fluctuations.

The following tables provide an indication of the Company’s significant foreign currency exposures during the year ended 30 November 2010 and 2009:

	30 November 2010	30 November 2009
Cash and cash equivalents	US$ 1,501,979	US$ 1,250,066

The Company has not, to the date of these financial statements, entered into derivative instruments to offset the impact of foreign currency fluctuations.

A 1% change in Canadian/US foreign exchange rate at year end would have changed the net loss of the Company, assuming that all other variables remained constant, by approximately $15,020 for the year ended 30 November 2010.

 (13)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

d)

Interest Risk

The Company’s interest rate risk is primarily related to the Company’s cash and cash equivalents for which amounts were invested at interest rates in effect at the time of investment.  Changes in market interest rates affect the fair market value of the cash and cash equivalents.  However, as these investments come to maturity within a short period of time, the impact would likely not be significant.

A 1% change in short-term rates would have changed the interest income and net loss of the Company, assuming that all other variables remained constant, by approximately $343 for the year ended 30 November 2010.

e)

Commodity Price Risk

The Company is in the exploration stage and is not subject to commodity price risk.

1.

Amounts Receivable

Amounts receivable are non-interest bearing, unsecured and have settlement dates within one year.

	2010	2009
	$	$
Harmonized Sales Tax receivable	34,675	15,810
Interest receivable	-	110,055
Petroleum revenue receivable	212,355	-
	247,030	125,865

2.

Property, Plant and Equipment

	2010			2009
	Cost	Accumulated depletion, depreciation and amortization	Net book value	Cost	Accumulated depletion, depreciation and amortization	Net book value
	$	$	$	$	$	$
Petroleum and natural gas properties	3,951,989	162,722	3,789,267	-	-	-
Computer equipment	60,749	38,740	22,009	57,869	29,925	27,944
Computer software	86,947	86,947	-	86,947	86,947	-
Equipment	58,720	36,859	21,861	58,720	31,393	27,327
Field equipment	-	-	-	479,319	203,231	276,088
Furniture and fixtures	67,205	33,825	33,380	67,205	25,480	41,725
	4,225,610	359,093	3,866,517	750,060	376,976	373,084

On 9 August 2010, the Company closed an asset purchase with Western Plains Petroleum Ltd. (“Western Plains”) pursuant to which the Company acquired an undivided 50% interest in all of Western Plains’ oil and natural gas interests located in the Lloydminster/Maidstone areas of Saskatchewan and the Lloydminster area of Alberta (the “Western Plains Assets”) for the cash purchase price of $1.7 million, having an effective date of 1 July 2010. An asset retirement obligation of $220,682 has been recognized as part of the acquisition (Note 6).

On 26 August 2010, the Company completed a further oil & gas asset purchase with Western Plains pursuant to which the Company acquired an undivided 33.33% interest in thirteen (13) crown leases located in the Lloydminster heavy oil area of Alberta for a cash purchase price of $1.467 million, having an effective date of 1 July 2010. An asset retirement obligation of $124,548 has been recognized as part of the acquisition (Note 6).

On 15 October 2010, the Company announced it has entered into a sub-participation agreement with Arctic Hunter Uranium Inc. (“Arctic Hunter”), a company with directors in common. Under the agreement, Arctic Hunter has agreed to a 100% participation interest in two (2) test wells by 31 October 2010. The Company holds a 50% working interest in the Landrose, Saskatchewan assets which form part of the heavy oil assets acquired on 9 August 2010 from Western Plains. Arctic Hunter must pay 100% of the Company’s share of the cost to drill, complete and equip or abandon the test wells to earn 100% of the Company’s pre-farmout working interest in the Test Wells spacing unit subject to reserving unto the Company a 10% overriding royalty payable by Arctic Hunter on all petroleum and natural gas substances produced therefrom until payout. After payout, the Company shall have the option to either covert to a 25% working interest (being 50% of the Company’s pre-farmout 50% working interest) in the test wells spacing unit or remain in a gross overriding royalty position. Arctic Hunter has no option to drill post-earning wells under the sub-participation agreement.  Western Plains will be the operator of the test wells.

On 18 November 2010, the Company entered into a participation agreement with Sahara Energy Ltd. (“Sahara Energy”). Under the agreement, the Company has agreed to a 50% participation interest with Sahara Energy in the joint lands. The Company must pay 50% of the cost to drill, complete and equip or abandon the test wells to earn a 50% working interest in the test well spacing unit and joint lands subject to reserving unto Sahara Energy a 15% overriding royalty payable by the Company on all petroleum and natural gas substances produced therefrom until payout. After payout, Sahara Energy shall have the option to either convert to a 25% working interest (being 50% of Sahara Energy’s pre-farmout 50% working interest) in the test well spacing unit and joint lands or remain in a gross overriding royalty position.

On 19 November 2010, the Company entered into an agreement with Western Plains Petroleum Ltd. to acquire a 50% undivided interest each in petroleum and natural gas rights from Triwest Exploration Inc. for a purchase price of $41,510 each.

No general and administrative expenses were capitalized for the year ended 30 November 2010.  There is no unproven land excluded from the depletion calculation.  Future development costs of $888,679 were included in the depletion calculation.  

The Company performed the ceiling test at 30 November 2010 resulting in undiscounted cash flows from proved reserves and the undeveloped properties exceeding the carrying value of oil and gas assets.  No impairment in oil and gas assets was identified as at 30 November 2010.  

In calculation the ceiling test, the Company used a risk-free rate of 7% and benchmark prices adjusted for quality and transportation at 30 November 2010 as follows:

Year	Alberta Heavy Crude Oil ($Cdn/STB)	Saskatchewan Heavy Crude Oil ($Cdn/STB)
2010	66.52	72.44
2011	72.98	78.02
2012	75.65	80.88
2013	79.21	84.68
2014	81.88	87.53
2015	84.54	90.39
2016	86.32	92.29
2017	88.10	94.19
2018	89.88	96.09
2019	91.70	98.03
2020	93.55	100.01
Percentage increase each year after 2020	2.0%	2.0%

3.

Asset Retirement Obligations

The Company’s assets retirement obligations consist of abandonment and restoration costs related to its oil and natural gas properties. The present value of the estimated obligations is $352,780 (30 November 2009 - $Nil) using a discount rate at which cash flows have been discounted by 7%.

The undiscounted inflated abandonment and restoration cost obligation at 30 November 2010 is $817,827 (30 November 2009 - $Nil) and the estimated cash flows will occur between 2013 to 2038. An accretion expense component of $7,550 (30 November 2009 - $Nil) has been charged to operations to reflect an increase in the carrying amount of the asset retirement obligations and will be funded from general corporate resources at that time of the retirement.

 (14)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of petroleum and natural gas properties:

	30 November 2010	30 November 2009
	$	$
Asset retirement obligations, beginning of year	-	-
Liabilities acquired	345,230	-
Accretion	7,550	-
Asset retirement obligations, end of year	352,780	-

4.

Mineral Properties

Sterling Mining Company – Sunshine Silver Mine, Idaho, USA

During the year ended 30 November 2009, the Company entered into an acquisition agreement with Sterling Mining Company (“Sterling”) to acquire a 100% interest in Sterling and its assets and provide for financing of Sterling’s ongoing operations (the “Agreement”).  

On 21 April 2010, the Company announced that it was unsuccessful in its bid to acquire 100% of the shares of   Sterling and the Sunshine Mine Lease pursuant to a bankruptcy auction held on 21 April 2010.  As a result of the unsuccessful bid, the Company has confirmed that certain conditions contained in the Agreement with Sterling dated 17 November 2009 have not been satisfied.  As a result of the unsatisfied terms and conditions, the Company received its entire break fee of $256,975 (US$250,000) in accordance with the terms of the Agreement and the Second Amended Plan and Disclosure Statement filed by Sterling.

Expenditures related to the Sterling Mining property for the period ended 30 November 2010 consists of geology and engineering of $11,736 (2009 - $Nil, 2008 - $Nil, cumulative - $11,736).

 (15)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Contact Lake Property – Contact Lake, Northwest Territories

During the year ended 30 November 2005, the Company acquired a 100% undivided right, title and interest, subject to a1% net smelter return royalty (“NSR”), infive mineral claims, totaling 1,801.82 hectares (“ha”) (4,450.50 acres) located five miles southeast of Port Radium on Great Bear Lake, Northwest Territories (“NT”), for cash payments of $60,000 (paid) and 60,000 common shares (issued and valued at $72,000) of the Company (Note 14).  The Company may purchase the NSR for a one-time payment of $1,000,000.  The Company completed additional staking in the area in order to increase the project size to sixteen contiguous claims, totalling 10,563.76 ha (26,103.52 acres).  Collectively the properties are known as the Contact Lake Mineral Claims.

Expenditures related to the Contact Lake Mineral Claims can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Amortization		322,489		50,327		65,497		122,091
Assaying and geochemical		413,031		125		1,097		93,816
Camp costs and field supplies		1,554,662		4,845		120,468		141,074
Claim maintenance and permitting		88,613		826		260		4,544
Community relations and government		215,000		-		19,153		70,930
Drilling		3,318,148		-		12,304		105,994
Equipment rental		200,831		-		-		3,750
Geology and engineering		680,644		15,521		28,682		227,902
Geophysics		16,643		-		-		16,643
Orthophotography		199,451		-		-		-
Staking and line cutting		339,160		-		6,500		-
Surveying		1,473,493		-		-		-
Transportation and fuel		4,938,609		-		212,326		289,276
Wages, consulting and management fees		4,545,567		11,898		626,682		771,526
Write down of field equipment		209,831		209,831		-		-
		18,516,172		293,373		1,092,969		1,847,546
Acquisition of mineral property interests		132,000		-		-		-
		18,648,172		293,373		1,092,969		1,847,546

 (16)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Port Radium – Glacier Lake Property, Northwest Territories

During the year ended 30 November 2005, the Company acquired a 100% undivided right, title and interest, subject to a2%NSR, in four mineral claims, totaling 2,520.78 ha (6,229.00 acres) (the “Glacier Lake Mineral Claims”) located one mile east of Port Radium on Great Bear Lake, NT, for cash payments of $30,000 (paid) and 72,000 common shares (issued and valued at $72,000) of the Company (Note 14).  The Company may purchase one-half of the NSR for a one-time payment of $1,000,000.

Expenditures related to the Glacier Lake Mineral Claims can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Amortization		33,444		6,550		8,371		10,727
Assaying and geochemical		197,313		-		-		54,136
Camp costs and field supplies		383,489		-		-		1,178
Claim maintenance and permitting		20,648		1,050		6,227		6,241
Community relations and government		21,472		-		-		-
Drilling		758,681		-		-		-
Equipment rental		58,038		-		-		-
Geology and engineering		69,879		-		-		36,206
Metallurgical studies		62,977		-		-		-
Orthophotography		25,522		-		-		-
Staking and line cutting		88,335		-		-		-
Surveying		17,309		-		-		-
Transportation and fuel		5,029,890		-		-		344,031
Wages, consulting and management fees		840,723		-		-		159,905
Write down of field equipment		11,039		11,039		-		-
		7,618,759		18,639		14,598		612,424
Acquisition of mineral property interests		102,000		-		-		-
Recovery of mineral property costs		(603,750)		-		-		-
		7,117,009		18,639		14,598		612,424

 (17)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Port Radium – Crossfault Lake Property, Northwest Territories

During the year ended 30 November 2005, the Company acquired a 100% undivided right, title and interest, subject to a 2% NSR, in five mineral claims, totalling 1,820.56 ha (4,498.68 acres) (the “Port Radium – Crossfault Lake Mineral Claims”) located north of Port Radium on Great Bear Lake, NT, for cash payments of $60,000 (paid) and 90,000 common shares (issued and valued at $297,000) of the Company (Note 14).  The Company may purchase one-half of the NSR for a one-time payment of $1,000,000.

Expenditures related to the Port Radium – Crossfault Lake Mineral Claims for the year ended 30 November 2010 consists of claim maintenance and permitting of $Nil (2009 - $Nil, 2008 - $682, cumulative - $682), transportation and fuel of $Nil (2009 - $Nil, 2008 - $817, cumulative - $817), wages, consulting and management fees of $Nil (2009 - $Nil, 2008 - $16,258, cumulative - $16,258), acquisition of mineral property interests of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $357,000) and recovery of mineral property costs of $Nil (2009 - $Nil, 2008 - $12,645, cumulative - $12,645).

Port Radium – Eldorado Property, Northwest Territories

During the year ended 30 November 2005, the Company entered into a lease agreement with South Malartic Exploration Inc. to purchase a 50% undivided right, title and interest in three mineral claims, totalling 106.53 ha (263.13 acres) (the “Eldorado Uranium Mineral Claims”) located at Port Radium on Great Bear Lake, NT, for a cash payment of $20,000 (paid).

Expenditures related to the Eldorado Uranium Mineral Claims for the year ended 30 November 2010 consists of claim maintenance and permitting of $Nil (2009 - $526, 2008 - $Nil, cumulative - $1,052) and acquisition of mineral property interests of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $20,000).

North Contact Lake Mineral Claims – Great Bear Lake, Northwest Territories

During the year ended 30 November 2006, the Company acquired a 100% right, interest and title, subject to a 2% NSR, in eleven mineral claims (the “North Contact Lake Mineral Claims”), for cash payments of $75,000 and the issue of 50,000 common shares of the Company valued at $182,500 (Note 14).  The Company may purchase one-half of the NSR for a one-time payment of $1,000,000.  The North Contact Lake Mineral Claims are situated north of Contact Lake on Great Bear Lake approximately 680 km (423 miles) north of Yellowknife, NT, totaling 6,305.22 ha (15,580.48 acres).

Expenditures related to the North Contact Lake Mineral Claims for the year ended 30 November 2010 consists of camp costs and field supplies of $Nil (2009 - $Nil, 2008 - $1,034, cumulative - $1,034), drilling of $Nil (2009 - $Nil, 2008 - $353,182, cumulative - $353,182), transportation and fuel of $Nil (2009 - $Nil, 2008 - $9,606, cumulative - $9,606), wages, consulting and management fees of $Nil (2009 - $Nil, 2008 - $13,012, cumulative - $13,012) and acquisition of mineral property interests of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $257,500).

 (18)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Eldorado South IOCG & Uranium Project, Northwest Territories

During the year ended 30 November 2007, the Company staked sixteen claims (the “Eldorado South Uranium Mineral Claims”) and four additional claims (the “Eldorado West Uranium Mineral Claims”) located ten miles south of the Eldorado uranium mine on the east side of Great Bear Lake, NT and 680 km (423 miles) north of the city of Yellowknife, NT, collectively known as the Eldorado South Uranium Project.

During the year ended 30 November 2009, fourteen claims were allowed to lapse.  The Eldorado South Uranium Project now consists of sixteen mineral claims totaling 11,281.85 ha (27,878.62 acres).

Expenditures related to the Eldorado South Uranium Project can be summarized as follows:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
Exploration operating expenses
Camp costs and field supplies		27,967		-		-		8,989
Claim maintenance and permitting		17,153		-		10,762		916
Community relations and government		3,555		-		-		3,555
Equipment rental		2,623		-		-		1,778
Geology and engineering		301,883		-		71,193		118,858
Geophysics		3,000		-		-		-
Staking and line cutting		415,099		-		71,500		237,944
Transportation and fuel		176,011		-		2,230		171,561
Wages, consulting and management fees		278,323		-		48,942		210,381
		1,225,614		-		204,627		753,982

Longtom Property – Longtom Lake, Northwest Territories

The Company holds a 50% undivided interest subject to a 2% NSR, totaling 361.38 ha (892.61 acres), in the Longtom Property (the “Longtom Property”) located about 350 km northwest of Yellowknife, NT.  The Longtom Property is registered 100% in the name of the Company.

The Company has the right to acquire the remaining 50% interest in the Longtom Property (the “Longtom Option”) for $315,000 payable either in cash or50% ($157,500) in cash and 50% in common shares of the Company.  The deemed price of the Company’s shares issued on the exercise of the Longtom Option would be the average TSX Venture Exchange closing market price of its common shares on the five trading days immediately preceding and the five trading days immediately following the date that the option is exercised. The Company is compelled to exercise the Longtom Option: 1) within 90 days from the date it has incurred $5,000,000 in exploration expenditures on the Longtom Property; or 2) at the date the Company advises the optionor in writing that it will complete the Longtom Option to purchase the remaining 50% interest in the Longtom Property.

 (19)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

The Company has the right to enter into joint venture or option agreements related to the Longtom Property with third parties prior to the exercise of the Longtom Option.

In 2003, the Company entered into a Letter of Intent (the “Letter of Intent”) with Fronteer Development Group Inc. (“Fronteer”).  On 26 October 2006, Fronteer earned its 75% interest in the Longtom Property by paying the Company $15,000 cash (received) and spending an aggregate of $500,000 (incurred) on exploration expenditures over three years.

Expenditures related to the Longtom Property for the year ended 30 November 2010 consists of assaying and geochemical of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $335), camp costs and field supplies of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $147,024), claim maintenance and permitting of $893 (2009 - $893, 2008 - $Nil, cumulative - $3,572), drilling of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $210,057), geology and engineering of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $418,998), transportation and fuel of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $322,529), wages, consulting and management fees of $Nil (2009 - $Nil, 2008 - $10,626, cumulative - $200,899), recovery of mineral property costs of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $52,497), sale of mineral property interests of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $55,000) and write-off of mineral properties and related costs of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $220,552).

Longtom Property (Target 1) – Longtom Lake, Northwest Territories

During the year ended 30 November 2003, the Company acquired a 50% interest in a 710.67 ha (1,756.10 acres) mineral property located in the Longtom Lake area of the Northwest Territories for cash proceeds of $15,000 and 40,000 common shares of the Company valued at $56,000 (Note 14).

During the year ended 30 November 2010, the Company has not done any work recently and has not budgeted for any in 2011.

Expenditures related to the Longtom Property Target 1 for the year ended 30 November 2010 consists of geology and engineering of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $2,103), wages, consulting and management fees of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $21,648), acquisition of mineral property interests of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $71,000) and recovery of mineral property costs of $Nil (2009 - $Nil, 2008 - $Nil, cumulative - $3,530).

 (20)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Recovery of Mineral Property Costs

Recovery of Mineral Property Costs consists mainly of amounts paid to the Company under existing option agreements and camp rental fees paid to the Company:

	Cumulative amounts from inception to 30 November 2010		For the year ended 30 November 2010		For the year ended 30 November 2009		For the year ended 30 November 2008
		$		$		$		$
General cash payments related to mineral property option agreements		45,000		-		-		-
Cash reimbursements of mineral property expenditures related to mineral properties		1,032,095		-		-		12,645
Shares received – 200,000 common shares of Max Resource Corp. (Note 14)		82,000		-		-		-
		1,159,095		-		-		12,645

5.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are non-interest bearing, unsecured and have settlement dates within one year.

Included in the accounts payable and accrued liabilities at 30 November 2010 is $639,445 (2009 - $639,893, 2008 - $685,941) related to Part XII.6 tax on funds raised by the Company on flow-through share offerings Note 12).

Included in the accounts payable and accrued liabilities at 30 November 2010 is $739,687 (2009 - $739,687 2008 - $739,687) related to the estimated costs to the Company for amending its flow-through filings (Notes 12 and 14).

 (21)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

6.

Related Parties Transactions

During the year ended 30 November 2010, the Company entered into the following transactions with related parties:

i.

Paid or accrued secretarial fees of $15,000 (2009 - $15,000, 2008 - $15,000) to an individual related to a director of the Company.  

ii.

Paid or accrued accounting fees of $76,000 (2009 – $59,001, 2008 - $Nil) to a company controlled by the chief financial officer of the Company.  

iii.

Paid or accrued accounting fees of $Nil (2009 - $13,875, 2008 - $Nil) to a company controlled by the former chief financial officer of the Company.

iv.

Paid or accrued management fees of $50,000 (2009 - $50,000, 2008 - $50,000) to a company controlled by a director of the Company.  

v.

Paid or accrued management fees of $15,000 (2009 - $25,000, 2008 - $Nil) to a company controlled by a director of the Company.

vi.

Paid or accrued directors fees of $27,000 (2009 - $27,000, 2008 - $32,000) to a company controlled by a director of the Company.

vii.

Paid or accrued directors fees of $Nil (2009 - $Nil, 2008 - $25,000) to a company controlled by a director of the Company.  

viii.

Paid or accrued directors fees of $27,000 (2009 - $17,000, 2008 - $3,000) to a director of the Company.

ix.

Paid or accrued directors fees of $27,000 (2009 - $10,000, 2008 - $Nil) to a director of the Company.

x.

Paid or accrued salaries and benefits of $523,805 (2009 - $479,878, 2008 - $575,269) to employees who are directors and/or officers of the Company.

Included in accounts payable and accrued liabilities as at 30 November 2010 is $831 (2009 - $Nil) payable to a director of the Company.

Included in accounts payable and accrued liabilities as at 30 November 2010 is $125,241 (2009 - $Nil) payable to a company related to the Company by way of management and directors in common.

The amounts charged to the Company for the services provided have been determined by negotiation among the parties and in certain cases, are covered by signed agreements.  It is the position of the management of the Company that these transactions were in the normal course of operations and were measured at the exchange value which represented the amount of consideration established and agreed to by the related parties.

 (22)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

1.

Share Capital

Authorized share capital consists of an unlimited number of voting common shares.  Authorized share capital also consists of an unlimited number of preferred shares, to be issued in series, with the directors being authorized to determine the designation, rights, privileges, restrictions and conditions attached to all of the preferred shares.

On 11 March 2010, the Company consolidated its share capital on a one new common share without par value for every five existing common shares without par value basis.  All common shares and per share amounts have been restated to give retroactive effect to the share consolidation (Note 1).

Share capital transactions of the Company during the years ended 30 November 2010 and 2009 are summarized as follows:

i.

During the year ended 30 November 2010, a total of 575,000 stock options with an exercise price of $4.25 per share expired.

ii.

During the year ended 30 November 2010, a total of 145,000 stock options with an exercise price of $1.75 per share were cancelled.  

iii.

During the year ended 30 November 2010, a total of 20,000 stock options with an exercise price of $5.00 per share were cancelled.

iv.

During the year ended 30 November 2010, a total of 120,000 stock options with an exercise price of $1.00 per share were cancelled.

v.

On 4 November 2009, the Company issued 100,000 stock options to consultants of the Company with an exercise price of $1.00 per share.  The 100,000 options vest in four equal quarters starting 4 March 2010.  All options in this series expire 3 November 2014 (Note 11).

vi.

On 3 July 2009, the Company issued 790,000 stock options to directors, officers, employees and consultants of the Company with an exercise price of $1.00 per share.  A total of 720,000 options vested immediately upon issuance and the remaining 70,000 options vest in four equal quarters starting 3 November 2009.  All options in this series expire 2 July 2014 (Note 11).

vii.

On 12 December 2008, the Company issued 466,667 units at a price of $0.75 per unit for total proceeds of $350,000. Each unit consists of one flow-through common share and one non flow-through share purchase warrant.  Each whole share purchase warrant entitles the holder to purchase an additional common share at a price of $0.90 up to 12 December 2010 (Note 18).

viii.

During the year ended 30 November 2009, a total of 480,000 stock options with an exercise price of $3.00 per share expired.  

ix.

During the year ended 30 November 2009, a total of 65,000 stock options with an exercise price of $4.25 per share were cancelled.  

x.

During the year ended 30 November 2009, a total of 125,000 stock options with an exercise price of $1.75 per share were cancelled.  

 (23)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Stock options

The Company grants share options in accordance with the policies of the TSX Venture Exchange.  Under the general guidelines of the TSX Venture Exchange, the Company may reserve up to 10% of its issued and outstanding shares for its employees, directors or consultants to purchase shares of the Company.  The exercise price for options granted under the plan will not be less than the market price of the common shares less applicable discounts permitted by the TSX Venture Exchange and options will be exercisable for a term of up to five years, subject to earlier termination in the event of death or the cessation of services.

The following incentive stock options were outstanding at 30 November 2010:

	Exercise price	Number of options	Remaining contractual life (years)
	$
Options	1.75	410,000	0.67
	1.00	670,000	3.59
	1.00	100,000	3.93
		1,180,000

The following is a summary of stock option activities during the years ended 30 November 2010 and 2009:

	Number of options	Weighted average exercise price
		$
Outstanding and exercisable at 1 December 2008	1,182,000	3.00
Granted	890,000	1.00
Exercised	-	-
Expired / Cancelled	(670,000)	2.90
Outstanding and exercisable at 30 November 2009	2,040,000	2.15
Weighted average fair value of options granted during the year		0.70

 (24)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

	Number of options	Weighted average exercise price
		$
Outstanding and exercisable at 1 December 2009	2,040,000	2.15
Granted	-	-
Exercised	-	-
Expired / Cancelled	(860,000)	3.32
Outstanding and exercisable at 30 November 2010	1,180,000	1.26
Weighted average fair value of options granted during the year		-

Warrants

The following share purchase warrants were outstanding at 30 November 2010:

	Exercise price	Number of warrants	Remaining contractual life (years)
	$
Warrants	0.90	466,667	0.03

The following is a summary of warrant activities during the years ended 30 November 2010 and 2009:

	Number of warrants	Weighted average exercise price
		$
Outstanding and exercisable at 1 December 2008	-	-
Granted	466,667	0.90
Exercised	-	-
Expired	-	-
Outstanding and exercisable at 30 November 2009	466,667	0.90
Weighted average fair value of warrants granted during the year		0.28

 (25)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

	Number of warrants	Weighted average exercise price
		$
Outstanding and exercisable at 1 December 2009	466,667	0.90
Granted	-	-
Exercised	-	-
Expired	-	-
Outstanding and exercisable at 30 November 2010	466,667	0.90
Weighted average fair value of warrants granted during the year		-

The weighted average grant date fair value of warrants issued during the year ended 30 November 2010, amounted to $Nil per warrant (2009 - $0.28 per warrant).  The fair value of each warrant granted was determined using the Black-Scholes option pricing model and the following weighted average assumptions:

	2010	2009	2008
Risk free interest rate	-	0.78%	-
Expected life	-	2.0 years	-
Annualized volatility	-	108.25%	-
Expected dividends	-	-	-

1.

Stock-Based Compensation

During the year ended 30 November 2009, the Company granted 100,000 stock options to consultants of the Company to purchase common shares of the Company for proceeds of $1.00 per common share expiring 3 November 2014.  A total of 100,000 of these stock options vest on the following dates (Note 10):

Vesting Date	Number of options
4 March 2010	25,000
4 June 2010	25,000
4 September 2010	25,000
4 December 2010	25,000
	100,000

 (26)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

During the year ended 30 November 2009, the Company granted 790,000 stock options to employees, directors and consultants of the Company to purchase common shares of the Company for proceeds of $1.00 per common share expiring 2 July 2014.  A total of 720,000 of these stock options vested on the grant date of 3 July 2009.  A total of 70,000 of these stock options granted to consultants of the Company vest on the following dates (Note 10):

Vesting Date	Number of options
3 November 2009	17,500
3 February 2010	17,500
3 May 2010 (cancelled 31 March 2010)	17,500
3 August 2010 (cancelled 31 March 2010)	17,500
	70,000

The fair value of the options which vested in the year, estimated using the Black-Scholes model, was $40,305 (30 November 2009 - $539,159).  This amount has been expensed as stock-based compensation with a corresponding increase in contributed surplus.

The following assumptions were used for the Black-Scholes valuation of stock options granted and vested during the year:

	2010	2009	2008
Risk free interest rate	2.52%	2.29%	2.86%
Expected life	5.0 years	4.7 years	3.0 years
Annualized volatility	105.75%	107.04%	100.99%
Expected dividends	-	-	-

Effective 10 October 2008, the Board of Directors has approved and adopted a shareholders rights plan (the “Rights Plan”) subject to shareholder and regulatory approval which was received on 3 February 2009.  The Rights Plan extends the minimum expiry period for a takeover bid to 60 days and requires a bid to remain open for an additional 10 business days after an offeror publicly announces it has received tenders for more than 50% of the Company’s voting shares.  The principle purpose of the Rights Plan is to ensure that all shareholders will be treated equally and fairly in the event of a bid for control of the Company through an acquisition of its common shares.  It is designed to provide the Company shareholders with sufficient time to properly consider a takeover bid without undue time constraints.  In addition, it will provide the board with additional time for review and consideration of unsolicited takeover bids, and if necessary, for the consideration of alternatives.

 (27)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

2.

Commitments and Other Obligations

i.

On 1 April 2006, the Company entered into a five year lease for premises with the following lease payments to the expiration of the lease on 1 March 2011:

	$
2011  (expired in 1 March 2011)	10,725
2012	-
2013	-
2014	-
2015	-
Total	10,725

ii.

The Company has certain obligations related to the amendments of its flow-through filings (Notes 8 and 14).

1.

Income Taxes

Provision for income taxes

The provision for (recovery of) income taxes differs from the amount that would have resulted by applying Canadian federal and provincial statutory tax rates of 28.63% (2009 – 30.08%, 2008 – 31.00%).

	2010	2009	2008
	$	$	$
Loss before income taxes	(2,006,658)	(3,469,442)	(6,489,209)
Expected income tax recovery	574,406	1,043,724	2,011,655
Non-deductible items	(18,983)	(115,949)	(283,098)
Change in enacted rates	(264,370)	(446,140)	(31,083)
Change in valuation allowance	(291,053)	(377,045)	(1,697,474)
Future income tax recovery	-	104,590	-

 (28)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

Future tax balances

The tax effects of temporary differences that give rise to future income tax assets and liabilities are as follows:

	2010	2009	2008
	$	$	$
Non-capital loss carryforwards	1,677,760	1,328,038	761,624
Plant, property and equipment	47,723	19,979	(6,955)
Mineral properties	1,440,084	1,548,106	1,661,935
Share issue costs	3,225	69,811	172,286
Asset retirement obligations	88,195	-	-
	3,256,987	2,965,934	2,588,890
Less: valuation allowance	(3,256,987)	(2,965,934)	(2,588,890)
Future tax assets (liabilities)	-	-	-

The Company has non-capital losses for Canadian tax purposes of approximately $6,711,040 available to offset against taxable income in future years, which, if unutilized, will expire as follows:

Year	Amount
2026	672,083
2027	-
2028	2,495,893
2029	1,870,522
2030	1,672,542
	6,711,040

Additionally, the Company has approximately $9,367,096 of Canadian resource-related deductions as at 30 November 2010 which, under certain circumstances, may be utilized to reduce taxable income of future years.  The potential income tax benefits of these losses have been offset by a full valuation allowance.

During the year ended 30 November 2010, the Company renounced the tax benefits of a total of Nil flow-through common shares (2009 - 466,667, 2008 - Nil) resulting in an income tax recovery of $Nil (2008 - $104,590, 2008 - $Nil).  The flow-through agreements require the Company to renounce certain tax deductions for Canadian exploration expenditures incurred on the Company’s mineral properties to the flow-through participants.

 (29)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

2.

Supplemental Disclosures with Respect to Cash Flows

Cash and cash equivalents comprise the following:

	2010	2009
	$	$
Cash on hand and balance in bank	2,901,643	3,378,568
Short term deposits(i)	5,012,644	10,000,000
US$ account(ii)	1,541,932	1,321,750
	9,456,219	14,700,318

(i)

Short term deposits include investments that are cashable after 30 days without penalty, with interest rate guarantees extending up to one year.

(ii)

$1,541,932 (US$ 1,501,979) (2009 - $1,321,750 (US$ 1,250,066)) held in a US $ bank account.

	2010	2009	2008
	$	$	$
Cash paid during the year for interest	-	-	-
Cash paid during the year for income taxes	-	-	-

During the year ended 30 November 2008, the Company has accrued a charge against capital stock and recorded a payable amount of $739,687 as the estimated costs to the Company for amending its flow-through filings (Notes 8 and 12).  

During the year ended 30 November 2006, the Company issued 40,045 common shares valued at $252,751 and 407,384 warrants valued at $1,015,191 for agent services rendered.

During the year ended 30 November 2006, the Company issued 50,000 common shares valued at $182,500 for the acquisition of the mineral property interests (Note 7).

During the year ended 30 November 2005, the Company issued 262,715 common shares valued at $303,074 and 530,357 warrants valued at $1,027,318 for agent services rendered.

During the year ended 30 November 2005, the Company issued 352,000 common shares valued at $599,000 for the acquisition of the mineral property interests (Note 7).

During the year ended 30 November 2004, the Company issued 44,166 common shares valued at $49,153 and warrants valued at $140,214 for agent services rendered.

During the year ended 30 November 2004, the Company issued 30,000 common shares valued at $30,000 for the acquisition of the mineral property interests (Note 7).

 (30)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

During the year ended 30 November 2004, the Company received 200,000 common shares of Max Resource Corp. valued at $82,000 as payment under a mineral property option agreement (Note 7).

During the year ended 30 November 2003, the Company issued 20,000 common shares valued at $23,000 for financing fees and 140,000 warrants valued at $58,478 for agent services rendered.

During the year ended 30 November 2003, the Company issued 90,000 common shares valued at $112,500 for the acquisition of the mineral property interests (Note 7).

On 21 January 2003, the Company sold its interest in the Harrison Lake Property to Candorado for proceeds of 40,000 shares of Candorado valued at $16,565.  These shares were sold for proceeds of $16,565 on the same date.

During the year ended 30 November 2000, the Company issued 26,767 common shares valued at $66,918 for the settlement of debt.

3.

Segmented Information

The Company’s business activity is acquiring and exploring mineral and oil and gas properties. These activities are carried out in Canada, specifically British Columbia, Alberta, Saskatchewan and Northwest Territories.

The breakdown by geographic area for the year ended 30 November 2010 is as follows:

	British Columbia	Alberta / Saskatchewan	Northwest Territories	Total
	$	$	$	$
Net income (loss)	(1,659,944)	(22,073)	(324,641)	(2,006,658)
Current assets	9,739,388	-	-	9,739,388
Property, plant and equipment	77,250	3,789,267	-	3,866,517
Total assets	9,816,638	3,789,267	-	13,605,905

The breakdown by geographic area for the year ended 30 November 2009 is as follows:

	British Columbia	Alberta / Saskatchewan	Northwest Territories	Total
	$	$	$	$
Net income (loss)	(2,051,239)	-	(1,313,613)	(3,364,852)
Current assets	14,851,638	-	-	14,851,638
Property, plant and equipment	96,996	-	276,088	373,084
Total assets	14,948,634	-	276,088	15,224,722

 (31)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

4.

Capital Management

The capital structure of the Company consists of equity attributable to common shareholders, comprising of issued capital, contributed surplus, warrants and deficit.  The Company’s objectives when managing capital are to: (i) preserve capital, (ii) obtain the best available net return, and (iii) maintain liquidity.

The Company manages the capital structure and makes adjustments to it in light of changes in economic condition and the risk characteristics of the underlying assets.  To maintain or adjust the capital structure, the Company may attempt to issue new shares, issue new debt, acquire or dispose of assets or adjust the amount of cash and cash equivalents and investments.

Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Company, is reasonable.  There were no changes in the Company’s approach to capital management during the year ended 30 November 2010.  The Company is not subject to externally imposed capital requirements and does not have exposure to asset-backed commercial paper or similar products.

5.

Reconciliation of Canadian and United States Generally Accepted Accounting Principles

The financial statements of the Company have been prepared in accordance with Canadian GAAP.  The United States Securities and Exchange Commission (“SEC”) requires that financial statements of foreign companies contain a reconciliation presenting the statements on the basis of accounting principles generally accepted in the United States of America (“US GAAP”).  Any differences in accounting principles as they pertain to the accompanying financial statements are not material, except as follows:

i.

Flow-through Shares

Under Canadian GAAP, when the flow-through shares are issued they are recorded at their face value.  When the entity acquires assets, the carrying value of the assets may exceed the tax basis as a result of the enterprise renouncing the related tax deductions to the investors.  The tax effect of this temporary difference is recorded as a reduction in share capital and an increase in deferred tax liability.

Under United States GAAP, when the flow-through shares are issued, the proceeds related to the issuance of the flow through shares are allocated between the offering of shares and the sale of tax benefits.  A balance of the proceeds equal to the excess of the price paid for the flow-through shares by the investor over the quoted market price is recorded as a liability.  The remaining proceeds are recognized as an increase in share capital.  The liability is reversed when the tax benefits are renounced to the investor and a deferred tax liability is recognized at that time.  Income tax expense is the difference between the amount of the deferred tax liability and the liability recognized on issuance.  

Under both Canadian and United States GAAP, to the extent that the Company has available tax pools for which a full valuation allowance has been provided, any deferred tax liability is recognized in earnings as a reduction in the valuation allowance at the time of renunciation of the flow-through shares.  

 (32)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

ii.

Stock-based Compensation

On 1 December 2006, the Company adopted Accounting Standards Codification (the “Codification” or “ASC”) 718, “Compensation – Stock Compensation” using the modified prospective method, which requires the Company to record compensation expense over the vesting period for all awards granted after the date of adoption.  As the Company had previously applied the fair value method of accounting for stock-based compensation under Canadian GAAP since 1 December 2002, the adoption of ASC 718 did not result in any significant differences between Canadian and US GAAP with respect to stock-based compensation expense in 2010.  

Prior to 1 December 2002, the Company accounted for stock options under Canadian GAAP as capital transactions when the options were recognized.  Effective 1 December 2002, the Company began accounting for stock option expense on a prospective basis under Canadian GAAP following the fair value method of accounting for stock options.  The Company’s reported increase of $189,176 in both share capital and deficit as at 30 November 2010 and 2009 is the result of the difference in accounting for stock options under Canadian GAAP and United States GAAP prior to 1 December 2002.

iii.

Full Cost Accounting

Under Canadian GAAP, a ceiling test is applied to review the carrying amount of its petroleum and natural gas properties relative to their recoverable amount.  The recoverable amount is calculated as the undiscounted cash flow from the properties using proved reserves and expected future prices and costs.  If the carrying amount of the properties exceeds their recoverable amount, an impairment loss is recognized in depletion and depreciation expense equal to the amount by which the carrying amount of the properties exceeds their fair value.  Fair value is calculated as the cash flow from those properties using proved and probable reserve and expected future prices and costs, discounted at a risk-free interest rate.  

Under US GAAP, a similar ceiling test is performed to ensure the carrying amount of petroleum and natural gas properties, net of deferred income taxes, does not exceed an amount equal to the sum, net of applicable income taxes, of the present value, discounted at 10 percent, of the estimated future net revenues calculated on the basis of the estimated value of future production from proved reserves using an average price based upon the prior 12-month period, less related estimated future development and production costs, plus unimpaired unproved property costs.

For both Canadian and US GAAP purposes, the Company has not recognized an impairment loss during the years ended 30 November 2010, 2009 and 2008 and, as a result, the depletion base of unamortized capitalized costs is the same for both Canadian and US GAAP purposes.

iv.

The above differences between Canadian and US GAAP had no impact on the reported assets and liabilities of the Company.

 (33)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

v.

The impact of the above differences between Canadian and US GAAP on loss for the period is as follows:

	30 November 2010	30 November 2009	30 November 2008
	$	$	$
Net loss under Canadian GAAP	(2,006,658)	(3,364,852)	(6,489,209)
Income tax expense on flow-through shares (Note 17(i))	-	(34,590)	-
Net loss under US GAAP	(2,006,658)	(3,399,442)	(6,489,209)
Other comprehensive income (loss)	-	-	-
Comprehensive loss under US GAAP	(2,006,658)	(3,399,442)	(6,489,209)
Loss per share, basic and diluted	(0.094)	(0.159)	(0.310)
Comprehensive loss per share, basic and diluted	(0.094)	(0.159)	(0.310)

vi.

vi.

The impact of the above differences between Canadian and US GAAP on deficit, share capital and contributed surplus, as reported, is as follows:

	30 November 2010	30 November 2009
	$	$
Deficit under Canadian GAAP	(39,220,689)	(37,214,031)
Flow-through shares (Note 17(i))	(9,407,456)	(9,407,456)
Stock-based compensation (Note 17(ii))	(189,176)	(189,176)
Deficit under US GAAP	(48,817,321)	(46,810,663)

	30 November 2010	30 November 2009
	$	$
Share capital and contributed surplus under Canadian GAAP	50,760,174	50,719,869
Flow-through shares (Note 17(i))	9,407,456	9,407,456
Stock-based compensation (Note 17(ii))	189,176	189,176
Share capital and contributed surplus under US GAAP	60,356,806	60,316,501

vii.

The above differences between Canadian and US GAAP had no impact on the statements of cash flows.

 (34)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

viii.

New Accounting Pronouncements

In January 2009, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting”, amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K and bringing full-cost accounting rules into alignment with the revised disclosure requirements.  The new rules include changes to the pricing used to estimate reserves, the ability to include non-traditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves.  In April 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (ASU) No. 2010-14, “Accounting for Extractive Activities – Oil & Gas, Amendments to Paragraph 932-10-S99-1”, to align the guidance in US GAAP with the changes the SEC made in December 2008.  The final rules are effective for registration statements filed on or after January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009.  The adoption of ASU 2010-14 did not have any material impact on the Company’s financial position, results of operations or cash flows.

In January 2010, the FASB issued ASU No. 2010-03, “Extractive Activities – Oil and Gas (Topic 932) – Oil and Gas Reserve Estimation and Disclosures”.  ASU 2010-03 improves the reserve estimation and disclosure requirements by (1) updating the reserve estimation requirements for changes in practice and technology that have occurred over the last several decades, (2) expanding the disclosure requirements for equity method investments.  ASU 2010-03 is effective for annual reporting periods ending on or after 31 December 2009.  However, an entity that becomes subject to the disclosure because of the change to the definition oil- and gas- producing activities may elect to provide those disclosures in annual periods beginning after 31 December 2009.  Early adoption is not permitted.  The adoption of ASU 2010-03 did not have any material impact on the Company’s financial position, results of operations or cash flows.  

In March 2010, the FASB issued ASU No. 2010-11, "Derivatives and Hedging (Topic 815): Scope Exception Related to Embedded Credit Derivatives" (codified within ASC 815 - Derivatives and Hedging). ASU 2010-11 improves disclosures originally required under Statement of Financial Accounting Standards No. 161. ASU 2010-11 is effective for interim and annual periods beginning after 15 June 2010. The adoption of ASU 2010-11 is not expected to have any material impact on the Company’s financial position, results of operations or cash flows.

In April 2010, the FASB issued ASU No. 2010-17, "Revenue Recognition - Milestone Method (Topic 605): Milestone Method of Revenue Recognition" (codified within ASC 605 - Revenue Recognition). ASU 2010-17 provides guidance on defining a milestone and determining when it may be appropriate to apply the milestone method of revenue recognition for research or development transactions. ASU 2010-17 is effective for interim and annual periods beginning after 15 June 2010. The adoption of ASU 2010-17 is not expected to have any material impact on the Company's financial position, results of operations or cash flows.

 (35)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

6.

Subsequent Events

The following subsequent events occurred from the date of the year ended 30 November 2010 to the date the annual financial statements were available to be issued on 21 March 2011:

i.

On 6 December 2010, the Company acquired petroleum and natural gas rights on a 160 acre parcel of undeveloped lands in the Lloydminster heavy oil region from the Saskatchewan Crown Land Sale.

ii.

On 8 December 2010, the Company granted 910,000 stock options to directors, officers, employees and consultants of the Company with an exercise price of $0.48 per share expiring 7 December 2012.

iii.

On 12 December 2010, a total of 466,667 share purchase warrants with an exercise price of $0.90 per share expired.

iv.

On 8 March 2011, the Company established a $1.1 million credit facility agreement with a Canadian chartered bank, consisting of a revolving operating facility of $800,000 with an interest rate of bank prime plus 1.5%, and a non-revolving acquisition and development facility of $300,000 with an interest rate of bank prime plus 2.0%.  The Company has not yet drawn on either credit facility.

 (36)

ALBERTA STAR DEVELOPMENT CORP.

(An Exploration Stage Company)

Notes to Financial Statements

(Expressed in Canadian Dollars

30 November, 2010

SIGNATURE

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

	ALBERTA STAR DEVELOPMENT CORP.
Dated: May 16, 2011	By: /s/ Tim Coupland
	Tim Coupland, President

 (37)