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UNITED STATES 
  SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 20-F
  [   ] REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934OR
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For fiscal year ended November 30, 2012 OR[   ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from ____ to ______ OR[   ] SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934Date 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) Stuart Rogers, CEO Alberta Star Development Corp. 506 – 675 West Hastings Street Vancouver, British Columbia V6B 1N2 Canada Tel: (604) 488-0860 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: NoneSecurities 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: NoneIndicate 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, 2012


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Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [   ] No [ X ]If this report is an annual or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes [   ] No [ X ]Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [   ]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 [   ] No [   ]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 [   ]

   Accelerated filer [   ]

   Non-accelerated filer [ X ]
  Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
  U.S. GAAP [   ]

   International Reporting Standards as issued

   [ X ]

   Other [   ]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 [   ]

   Item 18 [   ]If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [   ]  No [ X ]


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

   3CAUTIONARY NOTE TO U.S. INVESTORS REGARDING OIL AND GAS PRODUCTION AND RESERVES

   3GLOSSARY OF MINING TERMS

   4GLOSSARY OF OIL AND GAS TERMS

   7CONVERSION TABLE

   9CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

   9PART I

   11ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS.

   11ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE.

   11ITEM 3. KEY INFORMATION.

   11ITEM 4. INFORMATION ON THE COMPANY

   29ITEM 4A - UNRESOLVED STAFF COMMENTS

   86ITEM 5 - OPERATING AND FINANCIAL REVIEW AND PROSPECTS

   86ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

   99ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

   105ITEM 8. FINANCIAL INFORMATION

   108ITEM 9. THE OFFER AND LISTING

   108ITEM 10. ADDITIONAL INFORMATION

   110ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

   119ITEM 12. DESCRIPTIONS OF SECURITIES OTHER THAN EQUITY SECURITIES

   119PART II

   120ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

   120ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS.

   120ITEM 15. CONTROLS AND PROCEDURES.

   120ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

   121ITEM 16B. CODE OF ETHICS

   121ITEM 16C - PRINCIPAL ACCOUNTANT FEES AND SERVICES

   121ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

   122ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUERS AND AFFILIATED PURCHASERS.

   122ITEM 16F. CHANGE IN CERTIFYING ACCOUNTANT.

   122ITEM 16G. CORPORATE GOVERNANCE.

   122ITEM 16H. MINE SAFETY DISCLOSURE.

   122PART III

   123ITEM 17 - FINANCIAL STATEMENTS

   123ITEM 18 - FINANCIAL STATEMENTS

   123ITEM 19 - EXHIBITS

   123SIGNATURE

   125


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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. CAUTIONARY NOTE TO U.S. INVESTORS REGARDING OIL AND GAS PRODUCTION AND RESERVES The Company incorporates additional information with respect to production and reserves which is either not generally included or prohibited under SEC rules and practices in the United States. The Company 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 Company also follows the Canadian practice of using forecast prices and costs when it estimates its reserves. However, the Company 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 Company 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, 3


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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. 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
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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

   A geophysical method used to map and mathematically model underground faultSurvey

   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

   Fluids that 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.Igneous Rock

   A type of rock formed through the cooling and solidification of magma or lava. It can be formed below the surface as intrusive rocks or on the surface as extrusive rocks.Illite

   Illite is a layered alumino-silicate clay that is formed from hydrothermal environments.Induced Polarization

   A geophysical survey method which measures the electrochemical properties of rocks.(IP)

   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

   Period of time in the Earth’s history between 250 to 65 million years ago.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.
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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

   Period of time in the Earth’s history between 580 to 360 million years ago.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, thorium, polonium, 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.
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GLOSSARY OF OIL AND GAS TERMS  AECO

   Intra-Alberta Nova Inventory Transfer Price (NIT net price of natural gas)AIT

   After Income TaxAPO

   After PayoutARTC

   Alberta Royalty Tax CreditAPPO

   After Project PayoutBbl

   BarrelBbls

   BarrelsBbl/d

   Barrels per dayBOE *

   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 equivalentBIT

   Before Income TaxBOE/D

   Barrels of oil equivalent per day *BOPD

   Barrels per dayBPO

   Before PayoutEffective Date

   The date for which the Present Value of the future cash flows and reserve categories are establishedEOR

   Enhanced Oil RecoveryFH

   Freehold RoyaltyGOR (scf/STB)

   Gas-Oil Ratio (standard cubic feet of solution gas per stock tank barrel of oilGORR

   Gross overriding royaltyGJ

   GigajoulesGJ/d

   Gigajoules per dayGRP

   Gas Reference PriceLSD

   Legal subdivision - commonly used by the oil and gas industry as a precise way of locating wells, pipelines, and facilities within one-square mile sections of landM$

   Thousands of dollarsmKB

   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 equivalentMM$

   Millions of dollarsMbbls

   Thousand barrelsMcf

   1,000 cubic feetMcf/d

   1,000 cubic feet per dayMMcf

   1,000,000 cubic feetMmbtu

   Million British thermal unitsMMbtu

   One Million British Thermal UnitsMSTB

   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, 1974NGLs

   Natural gas liquidsNYMEX

   New York Mercantile ExchangePayout

   The point at which a participant’s original capital investment is recovered from its net revenueP&NG

   Petroleum and Natural GasPsia

   Pounds per square inch absoluteRaw Gas

   Natural gas as it is produced from the reservoir prior to processing.Rge

   RangeSec

   SectionSS 1/150 (5%-15%) Oil

   Sliding scale Royalty – a varying gross overriding royalty based on monthly production. Percentage is calculated as 1-150thof monthly production with a minimum percentage of 5% and a maximum of 15%.Twp

   Township$US

   United States DollarWI

   Working interestWTI

   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. 7


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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 or proved reserves

   Proven or 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
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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 Unit2.47 acres

   1 hectare

   0.4047 hectares

   1 acre3.28 feet

   1 meter

   0.3048 meters

   1 foot0.62 miles

   1 kilometer

   1.609 kilometers

   1 mile0.032 ounces (troy)

   1 gram

   31.1 grams

   1 ounce (troy)1.102 tons (short)

   1 tonne

   0.907 tonnes

   1 ton0.029 ounces (troy)/ton

   1 gram/tonne

   34.28 grams/tonne

   1 ounce (troy/ton)6.29 Barrels (Bbl)

   1 Cubic meters

   0.159 cubic metres

   1 barrel (Bbl)3.281 feet

   1 metre

   0.3048 metres

   1 foot0.035 Mcf

   1 cubic metre

   28.2 cubic metres

   1 Mcf0.949 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; 9


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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; andother 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. 10


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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. The following table summarizes selected financial data pertaining to operations of the Company for each of the two most recently completed fiscal years ended November 30. The 2012 and 2011 information set forth below should be read in conjunction with the audited financial statements, prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), and related notes. The 2011 information has been adjusted in accordance with IFRS, and therefore, may differ from the 2011 information previously published in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). All amounts within this Annual Report are in Canadian dollars, unless otherwise indicated. Fiscal Year Ended November 302012

   2011IFRS

   IFRSPetroleum revenue

   $2,422,266

   $2,331,217Production costs

   $3,281,624

   $2,372,361Net petroleum income (loss)

   ($859,358)

   ($41,144)Net operating revenue

   1,919,454

   1,905,957Loss from operations

   ($3,475,613)

   ($1,726,357)Loss from continuing operations

   ($3,475,613)

   ($1,726,357)Comprehensive loss for the year

   ($3,475,613)

   ($1,726,357)Loss from operations per share

   ($0.162)

   ($0.081)Loss from continuing operations per share

   ($0.162)

   ($0.081)Total assets

   $8,638,833

   $12,089,062Net assets

   $6,566,907

   $9,892,798Capital stock, contributed surplus and warrants

   $61,301,809

   $61,152,087Number of shares

   21,403,979

   21,403,979Dividends per common share

   Nil

   NilDiluted net loss per share

   ($0.162)

   ($0.081)
 11


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Pursuant to SEC Release No. 33-8567 “First-Time Application of International Financial Reporting Standards,” the Company is only required to include selected financial data prepared in compliance with IFRS extracted or derived from the financial statements for the years ended November 30, 2012 and 2011 (earlier periods are not required to be included). Furthermore, pursuant to SEC Release No. 33-8879 “Acceptance of Foreign Private Issuers of Financial Statements Prepared in Accordance with International Reporting Standards Without Reconciliation to U.S. GAAP”, the Company includes selected financial data prepared in compliance with IFRS without reconciliation to U.S. GAAP. NON-GAAP MEASURES We disclose several financial measures in this Annual Report 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 December 1, 2010, we adopted the following accounting policy to account for our petroleum and natural gas 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 and comprehensive loss. Petroleum and natural gas properties Effective December 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. Depletion and depreciation of petroleum and natural gas properties Effective December 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 and probable 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 and probable reserves. The costs of acquiring and evaluating unproved properties are excluded 12


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from depletion calculations. These properties are assessed periodically to ascertain whether impairment has occurred. If there is objective evidence that the property is considered to be impaired, the carrying amount of the asset is reduced to its recoverable amount, with the amount of the loss recognized in profit or loss. Ceiling Test Effective December 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 discounted cash flow from the properties using proved and probable reserves and expected future prices and costs. If the carrying amount of the properties exceeds their recoverable amount, an impairment loss is recognized 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 to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. International Financial Reporting Standards In February 2008, 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 GAAP to IFRS is December 1, 2011, with an effective transition date of December 1, 2010 for financial statements prepared on a comparative basis. The Company has prepared its financial statements in accordance with IFRS issued by the International Accounting Standards Board and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). 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 March 18, 2013, the exchange rate in effect for US dollars exchanged for Canadian dollars, expressed in terms of US dollars was $1.0223. This exchange rate is based on the noon buying rates of the Bank of Canada, as obtained from the website www.bankofcanada.ca. For the past five fiscal years ended November 30, 2012, and for the six month period between September 1, 2012 and February 28, 2013, the following exchange rates were in effect for US dollars exchanged for Canadian dollars, calculated in the same manner as above: Period

   

   AverageYear ended November 30, 2008

   $

   1.0469Year ended November 30, 2009

   $

   1.1565Year ended November 30, 2010

   $

   1.0345Year ended November 30, 2011

   $

   0.9879Year ended November 30, 2012

   $

   1.0023Period

   

   Low

   

   

   HighMonth ended September 30, 2012

   $

   1.0099

   

   $

   1.0299Month ended October 31, 2012

   $

   0.9996

   

   $

   1.0243Month ended November 30, 2012

   $

   0.9972

   

   $

   1.0074Month ended December 31, 2012

   $

   1.0048

   

   $

   1.0162Month ended January 31, 2013

   $

   0.9923

   

   $

   1.0164Month ended February 28, 2013

   $

   0.9723

   

   $

   1.0040
 13


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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 a comprehensive list of all the risks we face. There may also be 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 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 (i) deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities, (ii) operational problems affecting such pipelines and facilities and (iii) 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. Oil and natural gas prices may be volatile and can be subject to fluctuation. Oil and natural gas may fluctuate in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty. 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. 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. 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, current political tensions in the Middle East including tensions among Israel, Iran and the United States 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 14


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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. Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success 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 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 we 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 with a view to development. Moreover, even if properties are identified, management may determine that current economic conditions, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. There is no assurance that we will discover or acquire further commercial quantities of oil and natural gas. 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 encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations, 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 we consider 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. 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. 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. We anticipate making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future and if our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs. 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 15


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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. 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. There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL 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, natural gas and NGL 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, natural gas and NGL 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 we intend 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. 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 United States 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 it estimates its reserves. However, we separately estimate our reserves using prices and costs held 16


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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 probable reserves, as well as contingent resources in filings we have made with the SEC. 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. We manage a variety of projects in the conduct of our oil and gas business which contain numerous project risks. 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; andthe regulation of the oil and natural gas industry by various levels of government and governmental agencies. Because of these factors, we may 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. We enter into hedging transactions that may or may not lead to financial benefit. 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 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. We may not be able to obtain necessary drilling equipment. 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. We are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. 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 17


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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. We are subject to 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. We are subject to evolving regulations related to 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 Actand 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". We are subject to environmental regulations pursuant to a variety of federal, provincial and local laws and regulations. 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, 18


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development or exploration activities or otherwise have a material adverse effect on our business, financial condition, results of operations and prospects. We are in a highly competitive industry with companies that have greater resources. 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. 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. We cannot be certain that we have title to our 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. 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. Our properties are held in the form of licences and leases and working interests in licences and leases some of which could expire or terminate. 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. We may fail 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 19


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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. We depend on other companies to operate our assets. 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 is 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; andPotential 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 20


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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 we 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. 21


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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 in the exploration and development of certain ores. 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; andCapital 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. 22


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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 report 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. 23


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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. Uranium, precious metals and base metals prices are also 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. 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. 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 effect 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 our directors, officers, consultants and us. 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. 24


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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 Our Business We may be subject to aboriginal claims on our properties. 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. Passive Foreign Investment Company (“PFIC”) Status Has Possible Adverse Tax Consequences for U.S. Investors Current holders of and potential investors in our common shares who are U.S. taxpayers should be aware that Alberta Star believes that it qualified as a passive foreign investment company (“PFIC”) for the tax year ended November 30, 2009 and during prior tax years and that no determination has been made regarding Alberta Star’s PFIC status for the tax years ended November 30, 2010, 2011 and 2012. 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 makes a 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. However, U.S. shareholders should be aware that there can be no assurance that Alberta Star will satisfy record keeping requirements that apply to a qualified electing fund, or that Alberta Star will supply U.S. shareholders with information that such U.S. shareholders require to report under the QEF election rules, in the event that Alberta Star is a PFIC and a U.S. shareholder wishes to make a QEF election. Thus, U.S. shareholders may not be able to make a QEF election with respect to their common shares. 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. This paragraph is qualified in its entirety by the discussion below under the heading “Taxation—Certain United States 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, 2012, we incurred losses determined 25


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under IFRS totalling $54,734,902. 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 and begin production of our mineral claims, and therefore we will need to obtain additional financing in order to complete our business plan. As of November 30, 2012, we had $6,997,109 in cash on hand. Cash on hand at the date of filing this Annual Report is approximately $6,950,000. Our business plan calls for significant expenses in connection with the exploration and development 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 Chief Executive Officer (“CEO”), Stuart Rogers. Investors must be willing to rely to a significant extent on their discretion and judgment. 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. 26


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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, Belgium and Costa Rica, 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 (the “Exchange Act”). 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 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. We are subject to the volatility and uncertainty of recent market events and 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; andthe devaluation and volatility of global stock markets may impact the valuation of our equity securities. 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, including junior mining and oil and gas companies. These disruptions could, among other things, make it more difficult for the Company to obtain, or increase its cost of obtaining, capital and financing for its operations. Access to additional capital may not be available to the Company on terms acceptable to it, or at all. These factors could also have a material adverse effect on our financial condition and results of operations. Further, as a result of on-going global financial conditions, numerous financial institutions have gone into bankruptcy or have been rescued by government authorities. As such, the Company is subject to the risk of loss of its deposits with financial institutions that hold the Company’s cash. 27


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We may finance acquisitions through the 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. We may not be able to manage our 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. 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 SEC 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 28


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on broker-dealers who sell to persons other than established customers and "accredited investors". The term "accredited investor" refers generally to the categories of investors that satisfies Rule 501(a) under the Securities Act. 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 April 5, 2013, there are currently options outstanding to purchase an additional 1,575,000 common shares which upon exercise would result in a total of 22,978,979 common 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 $0.26 and a low of $0.17 during the twelve month period ended November 30, 2012. 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.
 We were incorporated under the name “Alberta Star Mining Corp.” pursuant to the Business 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. 29


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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 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 Energy 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 2012 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". 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. 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 we are 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 30


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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 dollar WTI reference price, transportation costs, US dollar/Canadian dollar exchange rates and the supply/demand situation of particular crude oil quality streams during the year. The prices 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 remained stable during 2012, the price differential between heavy and light crude oil increased during the year primarily due to a transportation disruption resulting from the maintenance shut-down of a pipeline that carries Canadian crude oil to refineries in the US Midwest. 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, we believe 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. 31


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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 32


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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 33


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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. 34


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On December 9, 2010, the Government of Saskatchewan enacted the Freehold Oil and Gas Production Tax Act, 2010which replaces the existing Freehold Oil and Gas Production Tax Actand 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, 2002providing 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, 2002providing 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, 2002providing 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, 2002treating 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, 2005providing 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, 2005providing 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 Wellsgranting "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; andRoyalty/Tax Incentive Volumes for Horizontal Gas Wells drilled on or after June 1, 2010 and before April 1, 2013providing 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. 35


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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. The Alberta 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. 36


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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 committed 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 Actcame 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. Although the intention was for draft regulations for the implementation of the Updated Action Plan to become binding on January 1, 2010, the only regulations announced pertain to carbon dioxide emissions from coal-fired generation of electricity (which regulations were finalized in the summer of 2012). Further, representatives of 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 GHG emissions regulation. As a result, it is unclear to what extent implementation of the proposals contained in the Updated Action Plan will occur. 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 specifying that it would issue final regulations by May 26, 2012 and, with respect to refineries, specifying that it will issue proposed regulations by December 10, 2011 and finalized regulations by November 10, 2012. The EPA did not meet the December 10, 2011 or November 10, 2012 deadline nor did it specify a new deadline for issuing the standards. It is expected that these standards will not be issued until after the EPA completes proposed GHG performance standards for the power sector, with strict greenhouse gas emission standards on new power plants being proposed in March 2012. While it is expected that this rule could encourage building new natural gas power plants rather than coal plants, the actual effect of the new rule is not yet readily quantifiable. 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 Actwhich 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 Regulationmake 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 37


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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 carbon dioxide 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. 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. As at our year end, fiscal 2012, we did not have an interest in any facilities in Alberta that emit more than 100,000 tonnes of carbon dioxide equivalent per year. 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. 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 mineral exploration interests that also 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. 38


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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 significant 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 39


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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. 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.  40


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41


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Lloydminster Alberta Maidstone 42


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Maidstone Landrose 43


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Lloydminster Nordic, Alberta  44


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Hillmond 45


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Alberta Western Plains Properties Lloydminster The Western Plains Properties - Lloydminster are located in close proximity to the city of Lloydminster in east central Alberta and include 10 LSD’s in Township 49 Range 1W4, LSD 13-12-50-03W4 and LSD 7-36-48-4W4 comprising 440 gross (220 net acres) acres of land with 1 producing and 5 shut-in heavy oil wells. The active well produces medium-heavy crude from the Sparky formation, which on a combined basis produced at an average rate of 10 bbls/day (5 bbls/day gross company share) during the past year. 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 50% working interest in the Lloydminster - Western Plains on or about August 6, 2010 under the Western Plains Agreement. 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. Western Plains Nordic - Blackfoot Properties The Western Plains Nordic-Blackfoot property is comprised of 26 LSD’s of land located in close proximity to the city of Lloydminster in east central Alberta in Township 50 Ranges 1 and 2W4. When the Company acquired the property in August 2010, it contained 9 active wells and 5 standing cased (drilled and cased but not completed) wells. The active wells produce medium-heavy crude from the Sparky formation. During the past year, the property produced at an average rate of 99 bbls/day (33 bbls/day gross company share) from various wells of which produced intermittently during the period. 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. Work on the Property No significant work was done on these properties during the year. 46


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47


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Saskatchewan Landrose The Landrose property is located in close proximity to the city of Lloydminster in west central Saskatchewan and includes various interests in a total of 5 active oil wells located in Section 06 of Township 50-25-W3M. During the past year, the Company drilled and completed 1 well in section 6-12-50-26W3. Further, the Company acquired the shut-in well 22/13-06-050-25W3 and 40 acre spacing unit and performed a successful work-over on and re-establishing production from the well. The wells in section 06-050-25W3 produce from the McLaren and Waseca formations. Total gross production from the wells was 21,009 barrels of medium heavy crude oil (57 bopd) during the past year. 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. Western Plains is the property operator. Production is subject to 4thtier Crown Royalties. A detailed description of the wells and interests is presented in Table 2. Acquisition and Ownership We acquired our interest in this property on or about August 6, 2010 under the Western Plains Agreement and subsequently entered into a sub-participation agreement with Arctic Hunter dated October 15, 2010. Under the agreement, Arctic Hunter had agreed to participate with us in two test wells. Under the agreement, Arctic Hunter paid 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) working interest (W.I.) of 50%, reserving to Alberta 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 test well spacing units or remain in a gross overriding royalty position. One of the test wells paid out within the first year of production and we elected to convert the override to a working interest position in those wells/spacing units. . On November 18, 2011, the Company entered into another sub-participation agreement with Arctic Hunter. Under the agreement, Arctic Hunter agreed to participate with the Company in the drilling of one test well. Arctic Hunter must pay 50% of the Company’s share of the cost to drill, complete and equip or abandon the test well to earn a 25% working interest in the well. We currently hold a GORR interest in 1 well, 25% WI in 2 wells and 50% working interests in two oil wells in section 6 and 25% WI in 1 well at 6-12-050-26W3. 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 40m 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, 2012, the property consisted of 4 active oil wells with Alberta Star having a 50% working interest in 160 acres of land in this area. Current production is approximately 15 bopd (8 bopd gross company share) from 2 active wells which produce medium-heavy oil from the McLaren/Waseca formations. 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. 48


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Production Total production from the 12 wells in the area currently averages 103 bbl/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, 2012, the property consisted of 1 well completed in the Waseca formation and is currently shut-in. Hillmond The Hillmond property is located in close proximity to the city of Lloydminster in east central Saskatchewan in township 06-51-25-W3. As of November 30, 2012, the property consisted of 1 Sparky formation oil well with Alberta Star having a 50% working interest in 40.25 acres of land in this area. The single well produced medium-heavy oil from the Sparky formations on an intermittent basis during the past year and is currently shut in. 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, Neilburg, Aberfelty and Lashburn which contain 5 wells, all of which are non-producing or shut in. Wells As at November 30, 2012, we had an interest in 12 gross (4.92 net) producing and 29 gross (11.83 net) non producing oil and natural gas well/entities and 0 gross (0 net) service wells as follows: Table 1Location

   PRODUCING

   NON-PRODUCING

   SERVICEWELLSOil

   Natural Gas

   Oil

   Natural GasGross(1)

   Net(2)

   Gross(1)

   Net(2)

   Gross(1)

   Net(2)

   Gross(1)

   Net(2)

   Gross(1)

   Net(2)Alberta

   3

   1.17

   0

   0

   18

   6.83

   0

   0

   0

   0Saskatchewan

   9

   3.75

   0

   0

   11

   5.00

   0

   0

   0

   0TOTAL

   12

   4.92

   0

   0

   29

   11.83

   0

   0

   0

   0
 A detailed description of the wells and interests are set out below. Well#

   Property

   Well UWID

   Zone Produced

   Interest Held1

   Western Plains

   00/05-20-049-01W4M/0

   Sparky

   50% WI2

   Western Plains

   02/12-20-049-01W4M/0

   Lloydminster

   50% WI3

   Western Plains

   02/12-22-049-01W4M/0

   Sparky

   50% WI4

   Western Plains

   00/16-22-049-01W4M/0

   Sparky

   50% WI5

   Western Plains

   02/07-36-048-04W4M/0

   Sparky

   50% WI6

   Western Plains

   00/13-12-050-03W4M/0

   Sparky

   50% WI1

   Blackfoot

   02/10-22-050-02W4M/0

   Lloydminster

   33 1/3% WI2

   Blackfoot

   00/09-22-050-02W4M/0

   Sparky

   33 1/3% WI3

   Blackfoot

   00/12-14-050-02W4M/0

   Sparky

   33 1/3% WI4

   Blackfoot

   02/12-14-050-02W4M/0

   Sparky

   33 1/3% WI5

   Blackfoot

   00/13-14-050-02W4M/0

   Sparky

   33 1/3% WI6

   Blackfoot

   00/16-06-050-01W4M/0

   Sparky

   33 1/3% WI7

   Blackfoot

   02/10-22-050-0-W4M/0

   Sparky

   33 1/3% WI8

   Blackfoot

   02/15-14-050-02W4M/0

   Sparky

   33 1/3% WI9

   Blackfoot

   00/15-06-050-01W4M/0

   Sparky

   33 1/3% WI10

   Blackfoot

   03/12-14-050-02W4M/0

   Sparky

   33 1/3% WI11

   Blackfoot

   00/04-24-050-02W4M/0

   Sparky

   33 1/3% WI12

   Blackfoot

   00/10-06-050-01W4M/0

   Sparky

   33 1/3% WI13

   Blackfoot

   00/06-24-050-02W4M/0

   Sparky

   33 1/3% WI14

   Blackfoot

   02/03-11-050-02W4M/0

   Sparky

   33 1/3% WI15

   Blackfoot

   03/03-11-050-02W4M/0

   Sparky

   33 1/3% WI
 49


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1

   Landrose

   31/05-06-050-25W3M/0

   McLaren

   50% WI2

   Landrose

   31/06-06-050-25W3M/0

   McLaren

   50% WI3

   Landrose

   31/11-06-050-25W3M/0

   McLaren

   10% GORR/ Conv. to 25% WI4

   Landrose

   31/12-06-050-25W3M/0

   McLaren

   25% WI5

   Landrose

   22/13-06-050-25W3M/0

   McLaren

   50% WI6

   Landrose

   31/13-06-050-25W3M/0

   McLaren

   50%WI (Drilled March 2012)7

   Landrose

   31/14-06-050-25W3M/0

   McLaren

   25% WI8

   Landrose

   11/16-06-050-25W3M/0

   McLaren

   50% WI9

   Landrose

   11/06-12-050-26W3M/0

   Lloydminster

   25% WI1

   Maidstone

   11/10-01-048-24W3M/0

   Sparky

   50% WI2

   Maidstone

   11/15-01-048-24W3M/0

   Sparky

   50% WI3

   Maidstone

   11/16-01-048-24W3M/0

   Sparky

   50% WI4

   Maidstone

   11/09-01-048-24W3M/0

   Sparky

   50% WIDee Valley

   14-32-048-22 W3M

   Sparky

   50% WIHillmond

   13-06-051-25 W3M

   Sparky

   50% WICeltic

   01-06-052-23 W3M

   Sparky

   50% WINeilburg

   02-18-045-25 W3M

   Sparky

   50% WIAberfelty

   16-12-050-27 W3M

   Sparky

   50% WILashburn NW

   13-045-25 W3M

   Sparky

   50% WILashburn NE

   13-045-25 W3M

   Sparky

   50% WI
 Acres As at November 2012, we had the following developed and undeveloped gross and nets acres: Gross DevelopedAcres

   Net DevelopedAcres

   Gross Un-DevelopedAcres

   Net Un-DevelopedAcresSaskatchewan

   3083.9

   1271.4

   1383.8

   678.3Alberta

   4902.6

   1949.7

   1739.6

   842.6TOTAL

   7986.5

   3221.1

   3123.4

   1520.9
 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 12 gross wells (4.92 net), including 0 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”. 50


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Category

   Constant Pricing (M$)Proved 0%

   Proved 10%

   Proved PlusProbable 0%

   Proved PlusProbable NPV 10%Wells with reserves assigned(1)

   154.6

   119.3

   167.3

   115.3Wells with no reserves assigned and facilities(2)

   0

   0

   0

   0Total abandonment and reclamation cost provision

   154.6

   119.3

   167.3

   115.3Portion forecast to be paid during the next three years

   110.9

   89.6

   39.0

   32.4
 Notes: (1)

   Abandonment and reclamation costs were estimated by Petrotech and included in the Petrotech 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 (Undeveloped Acreage) 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, 2012, we had estimated income tax deductions of approximately $18,809,782 available to reduce future taxable income. We did not incur current income taxes in 2012. 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, 2012: Nature of Cost

   Property Acquisitions and Capital ExpendituresAmount(M$)Property Acquisition CostsProved

   0Unproved

   0Exploration Costs

   8.006Development Costs

   422.605Total

   430.611
 Exploration and Development Activities The following table summarizes the results of oil and gas exploration and development activities in Canada during the financial years ended November 30, 2012, 2011 and 2010: 2010

   2011

   2012Wells Completed in Canada

   Gross

   Net

   Gross

   Net

   Gross

   NetDevelopmentOil

   Nil

   Nil

   6

   2.83

   2

   0.75Unsuccessful

   Nil

   Nil

   Nil

   Nil

   Nil

   NilService

   Nil

   Nil

   Nil

   Nil

   Nil

   NilExploratoryOil

   Nil

   Nil

   Nil

   Nil

   Nil

   NilUnsuccessful

   Nil

   Nil

   Nil

   Nil

   Nil

   NilService

   Nil

   Nil

   Nil

   Nil

   Nil

   NilTotal

   Nil

   Nil

   6

   2.83

   2

   0.75
 51


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The Company drilled 2 wells and completed several work overs in 2012. We do not plan to spend any significant funds on exploration and development of our oil assets in 2013. 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: Product

   2012Year

   Q4

   Q3

   Q2

   Q1Heavy Oil (Bbl/d)

   2012

   84

   107

   124

   96Total (BOE/d)

   2012

   84

   107

   124

   96Product

   2011Year

   Q4

   Q3

   Q2

   Q1Heavy Oil (Bbl/d)

   2011

   113

   97

   86

   91Total (BOE/d)

   2011

   113

   97

   86

   91Product

   2010Year

   Q4

   Q3

   Q2

   Q1Heavy 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. Category

   

   2012Year

   Q4

   Q3

   Q2

   Q1Selling PricesHeavy Oil ($/Bbl)

   2012

   67.64

   58.30

   60.13

   73.91RoyaltiesHeavy Oil ($/Bbl)

   2012

   12.25

   12.04

   13.44

   15.73Production Expenses(1)Heavy Oil ($/Bbl)

   2012

   31.23

   23.71

   29.44

   35.78Operating NetbacksHeavy Oil ($/Bbl)

   2012

   24.16

   22.58

   17.25

   22.40Total (BOE/d)

   

   84

   107

   124

   96
  Category

   

   2011Year

   Q4

   Q3

   Q2

   Q1Selling PricesHeavy Oil ($/Bbl)

   2011

   68.50

   59.21

   71.21

   58.97RoyaltiesHeavy Oil ($/Bbl)

   2011

   13.51

   10.86

   13.18

   10.23Production Expenses(1)Heavy Oil ($/Bbl)

   2011

   24.44

   27.31

   21.27

   25.50Operating NetbacksHeavy Oil ($/Bbl)

   2011

   30.59

   21.64

   37.69

   27.02Total (BOE/d)

   

   113

   97

   86

   91
 52


---

Category

   

   2010Year

   Q4

   Q3Selling PricesHeavy Oil ($/Bbl)

   2010

   64.39

   56.83RoyaltiesHeavy Oil ($/Bbl)

   2010

   6.75

   7.78Production Expenses(2)Heavy Oil ($/Bbl)

   2010

   43.64

   29.22Operating NetbacksHeavy Oil ($/Bbl)

   2010

   $14.00

   $18.83Total (BOE/d)

   

   55

   23
 Notes: (1)

   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 approximate production volumes for the financial year ended November 30, 2012 for each product type: Field

   Heavy Oil(Bbl/d)AlbertaLloydminster

   38Total Alberta

   38SaskatchewanLandrose

   57Maidstone

   8OtherTotal Saskatchewan

   65Total

   103
 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, 2012, estimated using constant 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 Petrotech Engineering Ltd. ("Petrotech") as an independent qualified reserves evaluator, to a report evaluating our reserves data entitled “Evaluation of the Interests of Alberta Star Development Corp. Lloydminster Area of Alberta & Saskatchewan (Effective Date November 30, 2012)”(the “Petrotech Report”), effective November 30, 2012, and dated March 19, 2013. 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 53


---

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 probable reserves, in this Annual Report. The statement of reserves data and other oil and gas information set forth below (the "Statement") is dated March 19, 2013. The effective date of the Statement is November 30, 2012 and the preparation date of the Statement is March 19, 2013. Disclosure of Reserves Data The reserves data set forth below (the "Reserves Data") is based upon an evaluation by Petrotech with an effective date of November 30, 2012 contained in a report of Petrotech dated March 19, 2013 (the "Petrotech 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 constant price and cost assumptions. We engaged Petrotech 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. 54


---

SUMMARY OF OIL AND GAS RESERVESas of November 30, 2012CONSTANT PRICES AND COSTSReserves Category

   ReservesLight and MediumOil

   **Heavy Oil**

   **Natural Gas(1)**

   **Natural GasLiquids**

   **Coalbed Methane**Gross(MSTB)

   **Net(MSTB)**

   **Gross(MSTB)**

   **Net
     (MSTB)**

   **Gross
     (MMscf)**

   **Net(MMscf)**

   **Gross(Mbbl)**

   **Net(Mbbl)**

   **Gross(MMscf)**

   **Net
       (MMscf)**PROVEDDeveloped Producing

   0

   0

   35.5

   33.1

   0

   0

   0

   0

   0

   0Developed Non-Producing

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0Undeveloped

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0TOTAL PROVED

   0

   0

   35.5

   33.1

   0

   0

   0

   0

   0

   0PROBABLEDeveloped

   0

   0

   21.9

   19.8

   0

   0

   0

   0

   0

   0TOTAL PROVED PLUSPROBABLE

   0

   0

   57.4

   52.9

   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 REVENUEas of November 30, 2012Reserves Category

   Net Present Values of Future Net RevenueBefore Income TaxDiscounted at

   After Income TaxDiscounted at0%/yr$M

   5%/yr.$M

   10%/yr.$M

   15%/yr.$M

   20%/yr.$M

   0%/yr$M

   5%/yr.$M

   10%/yr.$M

   15%/yr.$M

   20%/yr.$MPROVEDDeveloped Producing

   812.3

   751.6

   698.5

   651.3

   609.5

   812.3

   751.6

   698.5

   651.3

   609.5Developed Non-Producing

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0Undeveloped

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0TOTAL PROVED

   812.3

   751.6

   698.5

   651.3

   609.5

   812.3

   751.6

   698.5

   651.3

   609.5TOTAL PROBABLE

   756.7

   663.0

   585.7

   521.6

   467.7

   756.7

   663.0

   585.7

   521.6

   467.7TOTAL PROVED +PROBABLE

   1,569.0

   1,414.6

   1,284.2

   1,172.9

   1,077.2

   

   1,414.6

   1,284.2

   1,172.9

   1,077.2
  TOTAL FUTURE NET REVENUE (UNDISCOUNTED)As of November 30, 2012CONSTANT PRICES AND COSTSReserves Category

   Revenue(M$)

   Royalties(M$)

   **Operating**Costs(M$)

   **Development**Costs(M$)

   WellAbandonment**Reclamation**and Costs(M$)

   FutureNetRevenueBeforeIncomeTaxes(M$)

   FutureIncomeTaxes andExpenses(M$)

   FutureNetRevenueAfterDeductingIncomeTaxes(M$)PROVEDDevelopedProducing

   2,308.4

   260.3

   1,081.3

   0

   154.6

   812.2

   0

   812.6DevelopedNon-Producing

   0

   0

   0

   0

   0

   0

   0

   0Undeveloped

   0

   0

   0

   0

   0

   0

   0

   0TOTALPROVED

   2,308.4

   260.3

   1,081.3

   0

   154.6

   812.2

   0

   812.6Probable

   1,424.3

   188.0

   466.6

   0

   12.7

   756.9

   0

   756.9TOTALPROVED PLUSPROBABLE

   3,732.7

   448.3

   1,547.9

   0

   167.3

   1,569.1

   0

   1,569.1
 55


---

FUTURE NET REVENUE BY PRODUCTION GROUPas of November 30, 2012CONSTANT PRICES AND COSTSRESERVESCATEGORY

   PRODUCTION GROUP

   FUTURE NETREVENUEBEFOREINCOME TAXES(discounted at10%/year)(M$)

   FUTURE NETREVENUE BEFOREINCOME TAXES(discounted at10%/year)($/MCF)($/BBL)PROVED

   Light and Medium Oil (including solution gas and associated by products)

   0

   0Heavy Oil (including solution gas and other associated by products)

   698.5

   19.68Natural Gas (including associated by-products but excluding solution gas and by-products from oil wells)

   0

   0Coalbed Methane (including associated by-products)

   0

   0Non-Conventional Oil & Gas Activities (excluding coalbed methane)

   0

   0Total

   698.5

   19.68PROVED PLUSPROBABLE

   Light and Medium Oil (including solution gas and associated by products)

   0

   0Heavy Oil (including solution gas and associated by-products)

   1,284.2

   22.37Natural Gas (including associated by-products but excluding solution gas and by-products from oil wells)

   0

   0Coalbed Methane (including associated by-products)

   0

   0Non-Conventional Oil & Gas Activities (excluding coalbed methane)

   0

   0Total

   1,284.2

   22.37
 56


---

PRICING ASSUMPTIONS Petrotech employed the following pricing, exchange rate and inflation rate assumptions in estimating our reserves data using forecast prices and costs as of January 1, 2012. Inflation

   Heavy Crude Oil Proxy(12° API) at Hardisty ThenCurrent

   Heavy CrudeOil Proxy(12° API) atHardistyThen Current

   Heavy CrudeOil Proxy(12° API) atHardistyThen CurrentYear

   %

   $Cdn/bbl

   $Cdn/bbl

   $Cdn/bbl2008

   0

   74.94

   74.94

   74.942009

   0

   54.46

   54.46

   54.462010

   0

   60.76

   60.76

   60.762011

   0

   67.64

   67.64

   67.642012

   0

   63.87Lloydminster

   MaidstoneQ1 2013

   0

   55.10

   68.26

   64.94Q2 2013

   0

   61.39

   68.26

   64.94Q3 2013

   0

   62.66

   68.26

   64.94Q4 2013

   0

   64.54

   68.26

   64.942013

   0

   62.27

   68.26

   64.942014

   0

   70.70

   68.26

   64.942015

   0

   74.51

   68.26

   64.942016

   0

   74.51

   68.26

   64.942017

   0

   74.51

   68.26

   64.94
 Notes: [1]

   Adjusted based on average Alberta price received by Alberta Star for 2012[2]

   Adjusted based on average Saskatchewan price received by Alberta Star for 2012 Our weighted average realized sales price for heavy oil during the fiscal year ended November 30, 2012 were $68.26 /bbl for the Lloydminster Field in Alberta and $64.94/bbl for the Maidstone Field in Saskatchewan. Reserves Reconciliation The following tables set forth a reconciliation of our total gross proved, probable and proved plus probable reserves as at November 30, 2012 against such reserves as at November 30, 2011 based on constant price and cost assumptions: 57


---

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 ProvedPlus Probable(MMcf)November 30, 2011

   0

   0

   0

   16

   5

   21

   0

   0

   0Acquisitions

   

   

   

   0

   0

   0Discoveries

   0

   0

   0

   0

   0

   0

   0

   0

   0Dispositions

   0

   0

   0

   0

   0

   0

   0

   0

   0Extensions and Improved Recovery

   0

   0

   0

   57.1

   16.9

   74.0

   0

   0

   0Technical Revisions(2)

   0

   0

   0

   0

   0

   0

   0

   0

   0Economic Factors

   0

   0

   0

   0

   0

   0

   0

   0

   0Gross Production

   0

   0

   0

   (37.6)

   0

   (37.6)

   0

   0

   0November 30, 2012

   0

   0

   0

   35.5

   21.9

   57.4

   0

   0

   0
 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 that were first attributed and booked in each of our most recent three financial years ending on the date of the Petrotech Report, and in the aggregate, before that time: TOTAL CORPORATIONTIMEPERIOD

   LIGHT AND MEDIUMOIL(Mbbl)

   HEAVY OIL(Mbbl)

   NATURAL GASLIQUIDS(Mbbl)

   NATURAL GAS(Mmcf)

   COAL BEDMETHANE(Mmcf)PROVED

   PROBABLE

   PROVED

   PROBABLE

   PROVED

   PROBABLE

   PROVED

   PROBABLE

   PROVED

   PROBABLEA*

   B*

   A*

   B*

   A*

   B*

   A*

   B*

   A*

   B*

   A*

   B*

   A*

   B*

   A*

   B*

   A*

   B*

   A*

   B*2012

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   02011

   0

   0

   0

   0

   19.6

   0

   18.8

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   02010

   0

   0

   0

   0

   47

   47

   343

   343

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0

   0Prior to2010

   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 During the fiscal year ended November 30, 2012, proved undeveloped reserves decreased by 19.6 Mbbl to nil, with all 19.6 Mbbl going from undeveloped reserves to developed reserves. The Company had capital expenditures of $nil in the fiscal year ended November 30, 2012 related to the conversion of proved undeveloped reserves to developed reserves. Production Estimates The following tables disclose the estimated average daily production for 2012 for each product type associated with the first year of the gross proved reserves and gross probable reserves reported in the Petrotech Report effective November 30, 2012, based on constant prices and costs: 58


---

Corporation

   Light/MediumOil(Bbl/d)

   Heavy Oil(Bbl/d)

   Natural Gas(1)(Mcf/d)

   Natural GasLiquids(Bbl/d)

   Coal-BedMethane(Mcf/d)

   Combined(BOE/d)ProvedDeveloped Producing

   -

   44

   -

   -

   -

   44Developed Non-Producing and

   -

   -

   -

   -

   -

   -UndevelopedTotal Proved

   -

   44

   -

   -

   -

   44Probable

   -

   36

   -

   -

   -

   36Total Proved Plus Probable

   -

   80

   -

   -

   -

  80
 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 Petrotech, 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”. Controls over Reserve Estimates Our policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate our oil and gas reserves quantities and present values in compliance with the SEC’s regulations. Compliance in reserves bookings is the responsibility of our Board of Directors. Our controls over reserve estimates included retaining Petrotech as our independent petroleum and geological engineering firm. We provided information about our oil and gas properties, including production profiles, prices and costs, to Petrotech and they prepare their own estimates of the reserves attributable to our properties. All of the information regarding reserves in this Annual Report is derived from the Technical Report prepared by Petrotech. The Board of Directors meets with management, including the Chief Operating Officer to discuss matters and policies including those related to reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control or the control of the reserve engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve or cash flow estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors, such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors, such as an increase or decrease in product prices that renders production of such reserves more or less economic, may justify revision of such estimates. Accordingly, reserve estimates could be different from the quantities of oil and gas that are ultimately recovered. Estimated reserves shown for the producing properties have been projected on the basis of the extrapolation of performance data. All of the completions have extensive production histories and provide substantial data with respect to performance trends. In some cases the information suggests that recent well intervention work has been performed. In such cases we have considered prior historical performance in estimating future reserves. Technologies used to determine Proved Reserve Estimate A variety of methodologies are used by Petrotech to determine our proved reserve estimates. These methodologies are consistent with the requirements of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). These COGE requires that reserves be assigned only to known hydrocarbon accumulations 59


---

that have been penetrated by a well bore. Confirmation of a hydrocarbon accumulation is done by a production or formation test. The process of reserve estimation falls into three broad methodologies: volumetric, material balance and decline analysis. Volumetric methods involve the calculation of reservoir rock volume, the hydrocarbons in place in that rock volume, and the estimation of the portion of the hydrocarbons in place that ultimately will be recovered. Material balance methods of reserves estimation involve the analysis of pressure behavior as reservoir fluids are withdrawn. Production decline analysis methods of reserves estimation involve the analysis of production behavior as reservoir fluids are withdrawn. The principal methodologies employed for estimation of our reserves are decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields. 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 constant prices and costs: Year

   CanadaProved Reserves(M$)

   Proved Plus ProbableReserves(M$)2012

   nil

   nil2013

   nil

   nil2014

   nil

   nil2015

   nil

   nilRemaining Years

   nil

   nilTotal Undiscounted

   nil

   nil
 We do not plan to spend any significant funds on exploration and development of our oil assets in 2013. We estimate that our internally generated cash flow is sufficient to fund any future development costs. 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 the issuance of equity, 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, 2012, and, if applicable, November 30, 2011 and 2010. 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. 60


---

Figures 1&2 61


---

Eldorado-Contact Lake Area Geological Setting Regional GeologyAdapted 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 62


---

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). 63


---

Figure 3   64


---

Figure 4   65


---

Local Geology Adapted from Hoffman & McGlynn, 1977; Hildebrand, 1981; Reardon, 1992; Robinson & Ohmoto, 1971. The geology of the Eldorada-Contact Lake area, as shown in Figure 5, has been compiled from mapping completed by Hildebrand, 1981, and Reardon, 1992. Figure 5   66


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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 2012 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 work was done in 2012 and no further work is planned for the 2013 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: DrillingTrenchingSinking shaftsGeochemical and geophysical investigation made on the ground or by aircraftSurveyor claims must be proved by the surveyor generalWork 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. 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 67


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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. 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 10,563.78 ha (26,103.57 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. 68


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A summary of our claims can be found below: Name
        
        Tag Number
        
        Size (ha)BEN 1
        
        F91861
        
        1,003.30BEN 2
        
        F91862
        
        752.47BON 1
        
        F91863
        
        1,003.30BON 2
        
        F91864
        
        1,003.30BON 3
        
        F91865
        
        1,003.30COBALT 1
        
        F91852
        
        1,045.10COBALT 2
        
        F91853
        
        1,045.10COBALT 3
        
        F91854
        
        418.04COBALT 4
        
        F91855
        
        250.82COBALT 5
        
        F91856
        
        752.47COBALT 6
        
        F91857
        
        522.55Lease # 4748
        
        
        
        554.82Lease # 4749
        
        
        
        533.38Lease # 4750
        
        
        
        346.01Lease # 4751
        
        
        
        227.03Lease # 4752
        
        
        
        102.7910,563.78
  69


---

Figure 6   70


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Our expenditures related to the Contact Lake Mineral Claims can be summarized as follows: For the year
        
        
        
        For the year
        
        
        
        For the yearended
        
        
        
        ended
        
        
        
        endedNovember 30,
        
        
        
        November 30,
        
        
        
        November 30,2012
        
        
        
        2011
        
        
        
        2010$
        
        
        
        $
        
        
        
        $Exploration operating expensesAmortization
        
        -
        
        
        
        -
        
        
        
        50,327Assaying and geochemical
        
        -
        
        
        
        -
        
        
        
        125Camp costs and field supplies
        
        1,575
        
        
        
        3,200
        
        
        
        4,845Claim maintenance and permitting
        
        5,134
        
        
        
        4,874
        
        
        
        826Geology and engineering
        
        -
        
        
        
        -
        
        
        
        15,521Wages, consulting and management fees
        
        -
        
        
        
        -
        
        
        
        11,898Write down of field equipment
        
        -
        
        
        
        -
        
        
        
        209,8316,709
        
        
        
        8,074
        
        
        
        293,373
 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 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. No work is planned for this property in 2013. 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. No work is planned on this property in 2013. 71


---

A summary of our claims can be found below: Name
        
        Size (ha)Lease # 4815
        
        843.77Lease # 4816
        
        104.81Lease # 4817
        
        872.50Lease # 4818
        
        699.702,520.78
 Figure 8   72


---

Our expenditures related to the Port Radium – Glacier Lake Mineral Leases can be summarized as follows: For the year
        
        
        
        For the year
        
        
        
        For the yearended
        
        
        
        ended
        
        
        
        endedNovember 30,
        
        
        
        November 30,
        
        
        
        November 30,2012
        
        
        
        2011
        
        
        
        2010$
        
        
        
        $
        
        
        
        $Exploration operating expensesAmortization
        
        -
        
        
        
        -
        
        
        
        6,550Claim maintenance and permitting
        
        6,227
        
        
        
        6,227
        
        
        
        1,050Write down of field equipment
        
        -
        
        
        
        -
        
        
        
        11,0396,227
        
        
        
        6,227
        
        
        
        18,639
 73


---

Figure 9   74


---

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. During the year ended November 30, 2012 and up to April 5, 2013, five claims were allowed to lapse. The Eldorado South Uranium Project now consists of eleven (11) mineral claims totalling 9,045.35 ha (22,351.96 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 intend 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 2013. 75


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A summary of our claims can be found below: Name
        
        Tag Number
        
        Size (ha)PR 2
        
        K06182
        
        1,045.10PR 3
        
        K06183
        
        1,045.10PR 4
        
        K06194
        
        1,045.10PR 5
        
        K06195
        
        1,045.10PR 8
        
        K06198
        
        1,045.10PR 9
        
        K06199
        
        1,045.10PR 11
        
        K06201
        
        480.77PR 12
        
        K06202
        
        1,045.10PR 13
        
        K06203
        
        1,045.10PR 15
        
        K06205
        
        41.80PR 19
        
        K06209
        
        161.989,045.35
  76


---

Figure 10   77


---

We did not incur any expenditures related to the Eldorado South Uranium Project over the past three fiscal years. 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 1,789.22 ha (4,421.24 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). No work is planned on this property in 2013. A summary of our claims can be found below: Name
        
        Tag Number
        
        Size (ha)GOSSAN 1
        
        F91851
        
        418.04GOSSAN 2
        
        F91858
        
        418.04CROSS
        
        F91458
        
        2.10RAD 1
        
        F91859
        
        627.06RAD 2
        
        F91860
        
        323.981,789.22
 We did not incur any expenditures related to the Crossfault Lake Property over the past three fiscal years. 78


---

Figure 11   79


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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. No work is planned on this property in 2013. A summary of our claims can be found below: Name
        
        Tag Number
        
        Size (ha)ELDORADO
        
        Lease # 3032
        
        30.32ELDORADO
        
        Lease # 3033
        
        44.81ELDORADO
        
        Lease # 3034
        
        31.40106.53
 Our expenditures related to the Eldorado Uranium Mineral Claims can be summarized as follows: For the year
        
        
        
        For the year
        
        
        
        For the yearended
        
        
        
        ended
        
        
        
        endedNovember 30,
        
        
        
        November 30,
        
        
        
        November 30,2012
        
        
        
        2011
        
        
        
        2010$
        
        
        
        $
        
        
        
        $Exploration operating expenseClaim maintenance and permitting
        
        526
        
        
        
        526
        
        
        
        -526
        
        
        
        526
        
        
        
        -
 80


---

Figure 12   81


---

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 6,305.51 ha (15,581.20 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. No work is planned on this property in 2013. A summary of our claims can be found below: Name
        
        Tag Number
        
        Size (ha)EC 1
        
        F98661
        
        250.82EC 2
        
        F98662
        
        940.59EC 3
        
        F98663
        
        940.59EC 4
        
        F98664
        
        587.35EC 5
        
        F98665
        
        55.60EC 6
        
        F98666
        
        192.30EC 7
        
        F98667
        
        477.82EC 8
        
        F98668
        
        1,045.10EC 9
        
        F98669
        
        1,045.10EC 10
        
        F98670
        
        731.57EC 24
        
        F98369
        
        38.676,305.51
 We did not incur any expenditures related to the North Contact Lake Mineral Claims over the past three fiscal years. 82


---

Figure 13   83


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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 or 50% ($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. No work is planned on this property in 2013. We consider this property immaterial to the Company. We hold the following mineral lease claim at Longtom: Claim Name
        Tag Number
        Size (ha)DAMP
        Mineral Lease # 3759
        355.34
 84


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Figure 14   85


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Our expenditures related to the Longtom Property are summarized as follows: For the year
        
        
        
        For the year
        
        
        
        For the yearended
        
        
        
        ended
        
        
        
        endedNovember 30,
        
        
        
        November 30,
        
        
        
        November 30,2012
        
        
        
        2011
        
        
        
        2010$
        
        
        
        $
        
        
        
        $Exploration operating expensesClaim maintenance and permitting
        
        893
        
        
        
        893
        
        
        
        893893
        
        
        
        893
        
        
        
        893
 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 totaling 1200m) and 1997 (4 holes by Mongolia Gold Resources totaling 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. 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 with respect to our mineral properties, we have had no operating revenue during the years ended November 30, 2009, and 2008. 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 mining interests and provides us with a 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 two years ended November 30, 2012 and 2011 should be read in conjunction with the financial statements and the related notes included in Item 18. This section contains ‘forward-looking statements”. See “Cautionary Note on Forward-Looking Statements”. Summary of Significant Accounting Policies The preparation of the Company’s financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of the financial statements and reported amounts of income and expenses during the reporting period. Estimates and assumptions are continuously evaluated and are based on management’s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates. Areas requiring a significant degree of estimation and judgment relate to the recoverability of the carrying value of petroleum and natural gas assets, fair value measurements for financial instruments and share-based payments, the recognition and valuation of provisions for decommissioning liabilities, the recoverability and measurement of deferred tax assets and liabilities and ability to continue as a going concern. Actual results may differ from those estimates and judgments. 86


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Cash and cash equivalents Cash and cash equivalents include highly liquid investments with original maturities of three months or less. Property, plant and equipment Items of property, plant and equipment, which include petroleum and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, net of reversals. Development and production assets are grouped into cash generating units for impairment testing. When significant parts of an item of property, plant and equipment, including petroleum and natural gas interests, have different useful lives, they are accounted for as separate items. Gains and losses on the disposal of an item of property, plant and equipment, including petroleum and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net in profit or loss. Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as petroleum and natural gas development and production assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized petroleum and natural gas assets generally represent costs incurred in developing proven and/or probable reserves and bringing on or enhancing production from such reserves. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of oil and gas properties are recognized in profit or loss as incurred. The net carrying value of petroleum and natural gas development and production assets is depreciated using the unit of production method by reference to the ratio of production in the year to the related proven and probable reserves, including estimated future development costs. Future development costs are estimated taking into account the level of development required to bring reserves into production. These estimates are reviewed by independent reserve engineers at least annually. Changes in estimates such as quantities of proved and probable reserves that affect unit-of-production calculations are applied on a prospective basis. Other items of property, plant and equipment are depreciated over their estimated useful lives using the declining balance method at the following annual rates with half the rate applied in year of acquisition: Computer equipment
        30%Computer software
        100%Furniture and fixtures
        20%Equipment
        20%
 Exploration and evaluation properties Exploration and evaluation expenditures include the costs of acquiring licenses, costs associated with exploration and evaluation activity, and the fair value (at acquisition date) of exploration and evaluation assets acquired in a business combination. Exploration and evaluation expenditures are capitalized. Costs incurred before the Company has obtained the legal rights to explore an area are recognized in profit or loss. Option payments received are treated as a reduction of the carrying value of the related property and deferred costs until the receipts are in excess of costs incurred, at which time they are credited to income. Option payments are at the discretion of the optionee, and accordingly, are recorded on a cash basis. Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Once the technical feasibility and commercial viability of the extraction of mineral resources in an area of interest are demonstrable, exploration and evaluation assets attributable to that area of interest are first tested for impairment and then reclassified to mining property and development assets within property, plant and equipment. Recoverability of the carrying amount of any exploration and evaluation assets is dependent on successful development and commercial exploitation, or alternatively, sale of the respective areas of interest. 87


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Revenue recognition Petroleum and natural gas revenues are recorded when title passes, the amount is determinable and collection is reasonably assured. Decommissioning, restoration and similar liabilities The Company recognizes provisions for statutory, contractual, constructive or legal obligations associated with the reclamation of mineral properties and retirement of long-term assets, when those obligations result from the acquisition, construction, development or normal operation of the assets. The net present value of future cost estimates arising from the decommissioning of plant, site restoration work and other similar retirement activities is added to the carrying amount of the related asset, and depreciated on the same basis as the related asset, along with a corresponding increase in the provision in the period incurred. Discount rates using a pre-tax rate that reflect the current market assessments of the time value of money are used to calculate the net present value. The Company’s estimates of reclamation costs could change as a result of changes in regulatory requirements, discount rates and assumptions regarding the amount and timing of the future expenditures. These changes are recorded directly to the related asset with a corresponding entry to the provision. Changes in the net present value, excluding changes in the Company’s estimates of reclamation costs, are charged to profit or loss for the period. The net present value of reclamation costs arising from subsequent site damage that is incurred on an ongoing basis during production are charged to profit or loss in the period incurred. The costs of reclamation projects that were included in the provision are recorded against the provision as incurred. The costs to prevent and control environmental impacts at specific properties are capitalized in accordance with the Company’s accounting policy for exploration and evaluation properties. Share-based payments Share-based payments to employees are measured at the fair value of the instruments issued and recognized over the vesting periods. Share-based payments to non-employees are measured at the fair value of goods or services received or the fair value of the equity instruments issued, if it is determined the fair value of the goods or services cannot be reliably measured, and are recorded at the date the goods or services are received. The corresponding amount is recorded to contributed surplus. The fair value of options, as determined using the Black-Scholes Option Pricing Model which incorporates all market vesting conditions. The number of shares and options expected to vest is reviewed and adjusted at the end of each reporting period such that the amount recognized for services received as consideration for the equity instruments granted shall be based on the number of equity instruments that will eventually vest. Flow-through shares Any premium received by the Company on the issuance of flow-through shares is initially recorded as a liability and included in trade and other payables. Upon renouncement by the Company of the tax benefits associated with the related expenditures, a deferred tax liability is recognized and the flow-through liability will be reversed. To the extent that suitable deferred tax assets are available, the Company will reduce the deferred tax liability and record a deferred tax recovery. Taxation Deferred tax is provided, using the liability method, on all temporary differences at the balance sheet date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilized. Such deferred tax assets and liabilities are not recognized if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit. The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on the tax rates that have been enacted or substantively enacted at the reporting date. 88


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Foreign currency translation The Company’s reporting currency and the functional currency of all of its operations is the Canadian dollar as this is the principal currency of the economic environment in which they operate. Foreign currency transactions are translated into functional currency using the exchange rates prevailing at the date of the transaction. Foreign currency monetary items are translated at the period-end exchange rate. Non-monetary items measured at historical cost continue to be carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at the exchange rate at the date when fair values were determined. Exchange differences arising on the translation of monetary items or on settlement of monetary items are recognized in profit or loss in the period in which they arise, except where deferred in equity as a qualifying cash flow or net investment hedge. Exchange differences arising on the translation of non-monetary items are recognized in other comprehensive income in the statement of comprehensive income to the extent that gains and losses arising on those non-monetary items are also recognized in other comprehensive income. Where the non-monetary gain or loss is recognized in profit or loss, the exchange component is also recognized in profit or loss. Loss per share Basic per share amounts are calculated by dividing the profit or loss attributable to shareholders of the Company by the weighted average number of shares outstanding during the period. Diluted per share amounts are determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of all dilutive potential common shares, which consist of share purchase warrants and stock options. Financial assets Financial assets are classified as financial assets at fair value through profit or loss (“FVTPL”), held-to-maturity, loans and receivables, available-for-sale financial assets, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The Company determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value. The subsequent measurement of financial assets depends on their classification as follows: Financial assets at FVTPL Financial assets are classified as held for trading and are included in this category if acquired principally for the purpose of selling in the short term or if so designated by management. Derivatives, other than those designated as effective hedging instruments, are also categorized as held for trading. These assets are carried at fair value with gains or losses recognized in profit or loss. Transaction costs associated with financial assets at FVTPL are expensed as incurred. Cash and cash equivalents are included in this category of financial assets. Held-to-maturity and loans and receivables Held-to-maturity and loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the financial asset classified in this category are derecognized or impaired, as well as through the amortization process. Transaction costs are included in the initial carrying amount of the asset. Trade and other receivables is classified as loans and receivables. Available-for-sale Available-for-sale financial assets are those non-derivative financial assets that are not classified as loans and receivables. After initial recognition, available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income. Accumulated changes in fair value are recorded as a separate component of equity until the investment is derecognized or impaired. Transaction costs are included in the initial carrying amount of the asset. The fair value is determined by reference to bid prices at the close of business on the reporting date. Where there is no active market, fair value is determined using valuation techniques. Where fair value cannot be reliably measured, assets are carried at cost. 89


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Derivatives designated as hedging instruments in an effective hedge The Company does not hold or have any exposure to derivative instruments. Financial liabilities Financial liabilities are classified as financial liabilities at FVTPL, derivatives designated as hedging instruments in an effective hedge, or as financial liabilities measured at amortized cost, as appropriate. The Company determines the classification of its financial liabilities at initial recognition. The measurement of financial liabilities depends on their classification, as follows: Financial liabilities at FVTPL Financial liabilities at FVTPL has two subcategories, including financial liabilities held for trading and those designated by management on initial recognition. Transaction costs on financial liabilities at FVTPL are expensed as incurred. These liabilities are carried at fair value with gains or losses recognized in profit or loss. Financial liabilities measured at amortized cost All other financial liabilities are initially recognized at fair value, net of transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized respectively in interest, other revenues and finance costs. Trade payables are included in this category of financial liabilities. Derivatives designated as hedging instruments in an effective hedge The Company does not hold or have any exposure to derivative instruments. Impairment of financial assets Financial assets, other than financial assets at FVTPL, are assessed for indicators of impairment at each period end. Assets carried at amortized cost If there is objective evidence that an impairment loss on assets carried at amortized cost have been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in profit or loss. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed to the extent that the carrying value of the asset does not exceed what the amortized cost would have been had the impairment not been recognized. Any subsequent reversal of an impairment loss is recognized in profit or loss. Available-for-sale If an available-for-sale financial asset is impaired, the cumulative loss previously recognized in equity is transferred to profit or loss. Any subsequent recovery in the fair value of the asset is recognized within other comprehensive income. Derecognition of financial assets and liabilities Financial assets are derecognized when the rights to receive cash flows from the assets expire or, the financial assets are transferred and the Company has transferred substantially all the risks and rewards of ownership of the financial assets. On derecognition of a financial asset, the difference between the asset’s carrying amount and the sum of the consideration received and receivable and the cumulative gain or loss that had been recognized directly in equity is recognized in profit or loss. For financial liabilities, they are derecognized when the obligation specified in the relevant contract is discharged, cancelled or expires. The difference between the carrying amount of the financial liability derecognized and the consideration paid and payable is recognized in profit or loss. 90


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Impairment of non-financial assets The carrying amount of the Company’s assets is reviewed for an indication of impairment at the end of each reporting period. If an indication of impairment exists, the Company makes an estimate of the asset’s recoverable amount. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Recoverable amount of an asset group is the higher of its fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount. Impairment losses are recognized in profit or loss. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation, if no impairment loss had been recognized. Related party transactions Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also considered to be related if they are subject to common control, related parties may be individuals or corporate entities. A transaction is considered to be a related party transaction when there is a transfer of resources or obligations between related parties. Joint Arrangements Substantially all of the Company’s petroleum and natural gas exploration and development activities involve jointly controlled assets; accordingly, the financial statements reflect only the Company’s share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS Initial adoption of IFRS The Company’s audited financial statements as at and for the years ended November 30, 2012 have been prepared in accordance with IFRS as issued by the IASB. Previously, the Company prepared its 2011 annual financial statements in accordance with Canadian GAAP. IFRS 1 requires the consistent and retrospective application of IFRS accounting policies as at and for the year ended November 30, 2011 and an opening Statement of Financial Position as at December 1, 2010 (the “Transition Date”). To assist with the transition, the provisions of IFRS 1 allows for certain mandatory and optional exemptions for first-time adopters to alleviate the full retrospective application of IFRS. The Company has elected to apply the following relevant exemptions: Share-based payments -IFRS 1 encourages, but does not require, first-time adopters to apply IFRS 2 ‘Share-based Payment’ to equity instruments that were granted on or before 7 November 2002, or equity instruments that were granted subsequent to 7 November 2002 and vested before the Transition Date. The Company elected not to apply IFRS 2 to equity instruments that vested prior to the Transition Date. This resulted in no difference in share-based payments as at the Transition Date and for the year ended 30 November 2011. Full cost accounting -IFRS 1 provides an exemption for entities that have used the full cost method of accounting under Canadian GAAP. The Company elected to measure oil and gas assets at the Transition Date on the following basis: Exploration and evaluation assets at the amount determined under Canadian GAAP; and 91


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Assets in the development or production phases at the amount determined for the cost center under Canadian GAAP, allocated to the cost center’s underlying assets pro rata using reserve values as at the Transition Date. An impairment test was completed for each cash-generating unit as at the Transition Date and no impairment loss was recorded. Decommissioning Liabilities -IFRS 1 requires entities that have taken advantage of the full cost accounting election to measure their decommissioning liabilities on transition under IAS 37, “Provision, Contingent Liabilities and Contingent Assets” and to treat any difference between this amount and the amount recognized under Canadian GAAP as an adjustment to retained earnings or deficit. Mandatory exception to full retrospective application Estimates- In accordance with IFRS 1, the Company’s estimates under IFRS at the date of transition to IFRS must be consistent with estimates made for the same date under Canadian GAAP unless there is objective evidence that those estimates were in error. The estimates previously made by the Company under Canadian GAAP were not revised for application of IFRS. Differences between Canadian GAAP and IFRS Full cost accounting -The Company reclassified $210,260 which represents the deferred costs related to unproven petroleum and natural gas properties to exploration and evaluation properties from property, plant and equipment as at the Transition Date. As at 30 November 2011, the Company reclassified $729,515 to exploration and evaluation properties. Depletion and depreciation -Under Canadian GAAP, the full cost pool was depleted as one unit on a unit-of-production basis over proven reserves. Under IFRS, the Company depletes petroleum and natural gas interests on a unit-of-production basis over proven plus probable reserves. In addition, depletion is calculated at an individual component level. The change in accounting policy related to depletion and depreciation resulted in a decrease in depletion, depreciation and amortization and a corresponding increase in property, plant and equipment of $744,259 for the year ended 30 November 2011. Decommissioning liabilities -Under Canadian GAAP, decommissioning liabilities were discounted at a credit adjusted risk-free rate of 7%. Under IFRS, the estimated cash flow to abandon and remediate the wells and facilities has been discounted at a risk-free rate of 4% at the Transition Date. Upon transition to IFRS, this resulted in a $136,400 increase in the decommissioning liabilities with a corresponding increase in deficit. Under IFRS, the decommissioning liability is discounted at the end of each reporting period at the current risk-free discount rate. As at 30 November 2011, the Company re-measured the liabilities which resulted in a further difference of $37,974 recorded as a reduction in decommissioning liabilities with offsetting entry to property, plant and equipment. The accretion expense related to the decommissioning liabilities decreased by $5,345 for the year ended 30 November 2011 under IFRS compared to Canadian GAAP. Accretion expense is included in finance costs under IFRS. Flow-through shares -Flow-through shares are a unique Canadian tax incentive which is the subject of specific guidance under Canadian GAAP. Under Canadian GAAP, the Company accounted for the issue of flow-through shares in accordance with the provisions of the Canadian Institute of Chartered Accountants (the “CICA”) Emerging Issues Committee Abstract 146 ‘Flow-through Shares’. At the time of issue, the funds received are recorded as share capital. At the time of the filing of the renunciation of the qualifying flow-through expenditures to investors, the Company recorded a deferred tax liability with a charge directly to shareholders’ equity. Also under Canadian GAAP, a portion of the deferred tax assets that were not recognized in previous years, due to the recording of a valuation allowance, are recognized as a recovery of income taxes. IFRS does not contain explicit guidance pertaining to this tax incentive. Therefore, the Company has adopted a policy whereby the premium paid for flow-through shares in excess of the market value of the shares without the flow-through features at the time of issue is initially recorded as a flow-through liability. Upon renunciation by the Company of the tax benefits associated with the related expenditures, a deferred tax liability is recognized and the flow-through liability is reversed, with any difference recorded as deferred tax expense. A portion of the deferred tax assets that were not recognized in previous years, due to the recording of a valuation allowance, will reduce the deferred tax liability and be recorded as a deferred tax recovery. The change in accounting policy related to flow-through shares resulted in an increase in share capital and a corresponding 92


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increase in deficit of $9,436,156 as at the Transition Date. Further, the indemnification loss of $739,687 recorded as a reduction in share capital under Canadian GAAP has been reclassified as deferred tax expense under IFRS. Exploration and evaluation properties -Under Canadian GAAP, the Company expensed mineral acquisition and exploration and evaluation costs on an individual property basis until the viability of a property is determined. Under IFRS, the Company elected to capitalize mineral exploration and evaluation costs as incurred until it has been determined that a resource property can be economically developed as a result of establishing proven and probable reserves. The Company elected to test for impairment upon adoption of IFRS. The change in accounting policy related to exploration and evaluation costs resulted in an increase in exploration and evaluation properties of $15,720 and was subsequently written down during the year ended 30 November 2011. 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 financial assets and financial liabilities at amortized cost is determined in accordance with generally accepted pricing models based on discounted cash flow analysis or using prices from observable current market transactions. The Company considers that the carrying amount of all its financial assets and financial liabilities recognized at amortized cost in the financial statements approximates their fair value due to the demand nature or short term maturity of these instruments. Exchange 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’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 financial position 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 Company has not, to the date of these financial statements, entered into derivative instruments to offset the impact of foreign currency fluctuations. Interest Rate 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 $58,128 for the year ended 30 November 2012. 93


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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 trade receivables. 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 2012, trade receivables were comprised of GST/HST receivable of $9,202 (30 November 2011 -$25,951), petroleum revenue receivable of $164,709 (30 November 2011 - $209,538), and interest receivable of $216 (30 November 2011 - $Nil). As a result, credit risk is considered insignificant. 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. A. Operating Results. The following discussion and analysis should be read in conjunction with the Company’s audited financial statements and related notes thereto included herein. The Company’s audited financial statements have been prepared in accordance with IFRS. As at November 30, 2012, we had working capital of $5,714,151 under IFRS, inclusive of $6,997,109 of cash and cash equivalents. Cash and cash equivalents at the date of this Annual Report are approximately $6,950,000 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. The following table is from December 1, 2010 to November 30, 2012. The following tables summarize selected financial data for the Company for each of the two most recently completed financial years. The 2012 and 2011 information set forth below was extracted from and should be read in conjunction with the audited financial statements, prepared in accordance with IFRS as issued by the IASB, and related notes. FINANCIAL AND OPERATING SUMMARYOPERATIONS BY QUARTER (December 1, 2010 to November 30, 2012) All production is conventionalheavy oilQ4
        Q3
        Q2
        Q1
        Q4
        Q3
        Q2
        Q1Production and per share
        2012
        2012
        2012
        2012
        2011
        2011
        2011
        2011Production - total barrels
        7,617
        9,848
        11,445
        8,723
        10,266
        8,942
        7,989
        8,230Production - bbls/ day
        84
        107
        124
        96
        113
        97
        86
        91Heavy oil revenue
        515,190
        574,153
        687,383
        644,714
        703,223
        529,441
        568,888
        485,285Royalty income
        -
        22
        804
        -
        454
        5,401
        7,451
        31,074Royalties
        (93,283)
        (118,548)
        (153,780)
        (137,201)
        (138,666)
        (97,113)
        (105,260)
        (84,221)Production & transportation
        (237,868)
        (233,394)
        (336,981)
        (312,074)
        (250,907)
        (244,205)
        (169,902)
        (209,849)Operating net back
        184,039
        222,233
        197,426
        195,439
        314,104
        193,524
        301,177
        222,289General and administrative
        (246,537)
        (483,287)
        (216,690)
        (363,491)
        (425,578)
        (372,088)
        (368,335)
        (598,470)Corporate net back
        (62,498)
        (261,054)
        (19,264)
        (168,052)
        (111,474)
        (178,564)
        (67,158)
        (376,181)Depletion, accretion & amortization
        (315,926)
        (459,785)
        (527,139)
        (355,645)
        (325,382)
        (294,729)
        (224,329)
        (227,798)Write-downs
        (1,320,579)
        (450)
        (835)
        (11,651)
        (2,594)
        1,356
        (9,058)
        (5,424)Other (expenses) revenue
        29,427
        (61,664)
        85,801
        (26,299)
        68,004
        91,599
        6,652
        (71,277)Income (loss) for the period
        (1,669,576)
        (782,953)
        (461,437)
        (561,647)
        (371,446)
        (380,338)
        (293,893)
        (680,680)Basic and diluted income (loss) per share
        (0.078)
        (0.037)
        (0.022)
        (0.026)
        (0.017)
        (0.018)
        (0.014)
        (0.032)Royalties as % of petroleum revenue
        18
        21
        22
        21
        20
        17
        17
        11Per bbl analysis
        Per bbl
        Per bbl
        Per bbl
        Per bbl
        Per bbl
        Per bbl
        Per bbl
        Per bblHeavy oil revenue
        67.64
        58.30
        60.13
        73.91
        68.50
        59.21
        71.21
        58.97Royalty income
        -
        -
        0.07
        -
        0.04
        0.60
        0.93
        3.78Royalties
        (12.25)
        (12.04)
        (13.44)
        (15.73)
        (13.51)
        (10.86)
        (13.18)
        (10.23)Production and transportation
        (31.23)
        (23.71)
        (29.44)
        (35.78)
        (24.44)
        (27.31)
        (21.27)
        (25.50)
 94


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Operating net back
        24.16
        22.58
        17.25
        22.40
        30.59
        21.64
        37.69
        27.02General and administrative
        (32.37)
        (49.09)
        (18.93)
        (41.67)
        (41.46)
        (41.61)
        (46.11)
        (72.72)Corporate net back
        (8.21)
        (26.51)
        (1.68)
        (19.27)
        (10.87)
        (19.97)
        (8.42)
        (45.70)Depletion, accretion & amortization
        (41.48)
        (46.71)
        (46.06)
        (40.77)
        (31.70)
        (32.96)
        (28.08)
        (27.68)Write-downs
        (173.37)
        (0.05)
        (0.07)
        (1.34)
        (0.25)
        0.15
        (1.13)
        (0.66)Other (expenses) revenue
        3.86
        (6.26)
        7.50
        (3.01)
        6.62
        10.24
        0.83
        (8.66)Income (loss) for the period
        (219.20)
        (79.53)
        (40.31)
        (64.39)
        (36.20)
        (42.54)
        (36.80)
        (82.70)Funds (invested in) petroleum and mineral properties
        (3,664)
        (41,177)
        (263,042)
        (24,732)
        (280,688)
        (417,291)
        (6,125)
        (525,000)
 FINANCIAL AND OPERATING SUMMARYBALANCE SHEET Q4
        Q3
        Q2
        Q1
        Q4
        Q3
        Q2
        Q12012
        2012
        2012
        2012
        2011
        2011
        2011
        2011Net cash
        6,997,109
        6,950,171
        7,428,567
        7,655,139
        7,780,441
        8,041,687
        8,422,503
        8,717,027Total assets
        8,638,833
        10,192,055
        10,990,054
        11,457,905
        12,089,062
        12,387,748
        12,650,886
        13,102,221Total liabilities
        2,071,926
        2,030,149
        2,059,805
        2,067,182
        2,196,264
        1,987,307
        1,886,819
        2,033,175Shareholders’ equity
        6,566,907
        8,161,906
        8,930,249
        9,390,723
        9,892,798
        10,400,441
        10,874,067
        11,069,046SHARESBasic outstanding
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979Weighted average
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
        21,403,979
 RESULTS OF OPERATIONS – YEAR ENDED NOVEMBER 30, 2012 The Company’s net and comprehensive loss for the year ended November 30, 2012 was $3,475,613 or $0.162 per share compared to a net and comprehensive loss of $1,726,357 or $0.081 per share for the year ended November 30, 2011. The significant changes during the current fiscal period compared to the same period a year prior are as follows: Advertising and promotion expenses decreased to $21,521 during the year ended November 30, 2012 from the $135,152 incurred during the same period a year prior. The decrease in advertising and promotion is primarily attributable to a decrease in advertising costs and news release dissemination fees. Consulting fees decreased to $73,284 for the year ended November 30, 2012 from $182,825 for the year ended November 30, 2011. The decrease in consulting fees period over period is due mainly to a decrease in the number of consultants used by the Company. Director fees increased to $26,000 for the year ended November 30, 2012 from $3,000 for the year ended November 30, 2011. The increase in director fees was due to implementation of a policy of compensating the directors for their service effective May 1, 2012. Filing and financing fees increased to $62,014 for the year ended November 30, 2012 from $53,090 for the year ended November 30, 2011. The increase in costs is attributed to a general increase in fees associated with regulatory authorities. Legal and accounting fees decreased to $237,408 for the year ended November 30, 2012, from $304,831 for the year ended November 30, 2011. The decrease in legal and accounting fees from the previous year was mainly due to a reduction in legal fees paid to the Company’s legal counsels in Alberta, British Columbia and the Northwest Territories for the Company’s Annual General Meeting, and other general corporate matters. Management fees increased to $47,500 for the year ended November 30, 2012 from $Nil for the year ended November 30, 2011. The increase is due to the interim CEO billing his services under management fees instead of salaries effective July 11, 2012. Office and miscellaneous expenses for the year ended November 30, 2012 were reduced to $36,892 as compared to $48,693 in the prior year. The current year office expenses were less due to a reduction in office overhead associated with the exploration programs and an effort to reduce costs. 95


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Salaries and benefits for the year ended November 30, 2012 were reduced to $474,224 as compared to $524,015 for the year ended November 30, 2011. The current year salaries include severance of $204,167 that was paid to the former President upon his resignation on July 10, 2012. Stock-based compensation expense totalling $149,722, a non-cash item, was incurred during the year ended November 30, 2012 on the granting of 1,425,000 stock options that vested during the period as compared to $216,070 for the year ended November 30, 2011. Transfer fees and shareholder information costs were reduced to $47,300 for the year ended November 30, 2012 from $118,674 for the year ended November 30, 2011. The decrease in transfer fees and shareholder information costs period over period is due mainly to a decrease in the number of consultants used for the Company’s investor relations and corporate development activities. Travel expenses decreased to $17,757 during the year ended November 30, 2012 from $44,125 during the same period a year prior. This was due to decreased travel expenditures to the Companies working interest partner’s Lloydminster, Alberta office during the year. Interest income increased to $70,621 for the year ended November 30, 2012, compared to $63,373 during the same period a year prior primarily due to higher interest rates being paid on deposits during the current year. There was an unrealized foreign exchange loss of $41,778 (2011 - $6,263) for the year ended November 30, 2012 based primarily on the valuation of US$1,532,611 held in U.S. funds. This loss resulted as the Canadian dollar increased in value compared to the US dollar. There was a capital gain of $18,518 resulting from the sale of exploration camp equipment that was written off in the prior year. SELECTED ANNUAL INFORMATION The following tables summarize selected financial data for the Company for each of the two most recently completed financial years. The information set forth below was extracted from and should be read in conjunction with the audited financial statements, prepared in accordance with IFRS as issued by the IASB, and related notes. The 2011 information has been adjusted in accordance with IFRS, and therefore, may differ from the 2011 information previously published in accordance with Canadian GAAP. For the Year Ended November 30Item
        2012
        2011Total Revenue
        $2,422,266
        $2,331,217Total (Loss) from Continuing Operations
        ($3,475,613)
        ($1,726,357)Operating basic and diluted (Loss) per Share
        ($0.162)
        ($0.081)Net (Loss) in Total
        ($3,475,613)
        ($1,726,357)Net basic and diluted (Loss) per Share
        ($0.162)
        ($0.081)Total Assets
        $8,638,833
        $12,089,062Total Long Term Financial Liabilities
        Nil
        NilCash Dividends Declared per Share
        Nil
        Nil
 Pursuant to SEC Release No. 33-8567 “First-Time Application of International Financial Reporting Standards,” the Company is only required to include selected financial data prepared in compliance with IFRS extracted or derived from the financial statements for the years ended November 30, 2012 and 2011 (earlier periods are not required to be included). Furthermore, pursuant to SEC Release No. 33-8879 “Acceptance of Foreign Private Issuers of Financial Statements Prepared in Accordance with International Reporting Standards Without Reconciliation to U.S. GAAP”, the Company includes selected financial data prepared in compliance with IFRS without reconciliation to U.S. GAAP. Year ended November 30, 2012 compared to year ended November 30, 2011 Under IFRS, we incurred a net loss and comprehensive loss of $3,475,613 during fiscal 2012 from the $1,726,357 incurred during fiscal 2011 primarily due to the following: The Company received an operating net back of $799,137 but after 96


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deducting $1,658,495 in oil and gas depletion and depreciation, a net petroleum loss of $859,358 was realized. The net loss in the 2012 fiscal year over 2011 can also be primarily attributed to a write-down of $1,333,515 on its mineral properties and oil and gas assets. This loss was partially offset by an increase in interest income during fiscal 2012 to $70,621 from $63,373 earned during the prior fiscal period and a capital gain of $18,518 on the sale of office and camp equipment. The loss was also comprised of general and administration expenses for the year ended November 30, 2012 of $1,310,005, as compared to $1,764,471 in the comparable period of 2011, a decrease of $454,466. There were notable decreases in the areas of advertising and promotion expenses (2012 - $21,521, 2011 - $135,152), consulting fees (2012 – $73,284, 2011 -$182,825), legal and accounting (2012 – $237,408, 2011 - $304,831), share-based payments (2012 - $149,722, 2011 -$216,070), transfer fees and shareholder information (2012 - $47,300, 2011 - $118,674), travel (2012 - $17,757, 2011 -$44,125) and salaries and benefits (2012 - $474,224, 2011 - $524,015). There were several increases in the areas of director fees (2012 – $26,000, 2011 - $3,000), filing and financing fees (2012 - $62,014, 2011 - $53,090) and management fees (2012 - $47,500, 2011 - $Nil). B.
        Liquidity and Capital Resources.
 General Since incorporation, we have financed our operations almost exclusively through the sale of common shares to investors. Part of our business is mining exploration and development and we have no producing mineral resource properties that generate operating income or cash flow 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 2012. 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. Currently, we have oil and gas operating revenues but we rely primarily on existing cash and equity financing to fund our exploration and administrative costs. We expect to rely upon our 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 requirement and our access to additional capital may not be available on terms acceptable to us or at all. 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. Our strong cash position will allow financial flexibility. 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 redeemable Canadian Guaranteed Investment Certificates with a Canadian Chartered Bank and Canadian Credit Union. 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, 2012, the Company had cash and cash equivalents of $6,997,109 and working capital of $5,714,151 as compared to $7,780,441 of cash and cash equivalents and working capital of $6,386,262 at November 30, 2011. The reduction in cash and cash equivalents of $783,332 was due to cash used in operations of $469,235 and $318,260 that was used to acquire an interest in oil and gas resource properties. Total assets at November 30, 2012 decreased to $8,638,833 under IFRS from $12,089,062 at November 30, 2011, primarily as a result of writing down certain oil and gas property assets. As of the date of this report, we have cash and cash equivalents of approximately $6,950,000. We believe that this is sufficient to fund our currently planned exploration and administrative budget through the balance of fiscal 2013. We do not plan to fund any significant exploration and development activities for 2012. The budget may include facilities investments, primarily in Saskatchewan which will optimize new production while improving existing production 97


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efficiencies. Financing Activities 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, 2012, a total of 750,000 stock options with an exercise price of $0.20 per share were granted with an expiry date of October 12, 2015.ii.
      During the year ended 30 November, 2012, a total of 150,000 stock options with an exercise price of $0.165 per share were granted with an expiry date of July 10, 2015.iii.
      During the year ended 30 November, 2012, a total of 420,000 stock options with an exercise price of $1.00 per share, a total of 460,000 stock options with an exercise price of $0.48 per share and a total of 100,000 stock options with an exercise price of $0.21 per share were cancelled.iv.
      During the year ended 30 November, 2012, a total of 50,000 stock options with an exercise price of $0.25 per share were granted with an expiry date of January 31, 2014. These options vest in four equal quarters starting February 1, 2012.v.
      During the year ended 30 November, 2012, a total of 475,000 stock options with an exercise price of $0.21 per share were granted with an expiry date of January 9, 2015.vi.
      During the year ended 30 November, 2011, a total of 410,000 stock options with an exercise price of $1.75 per share expired.vii.
      During the year ended 30 November, 2011, a total of 100,000 stock options with an exercise price of $1.00 per share were cancelled.viii.
      During the year ended 30 November, 2011, a total of 910,000 stock options with an exercise price of $0.48 per share were granted with an expiry date of December 7, 2012.ix.
      During the year ended 30 November, 2011, a total of 466,667 share purchase warrants with an exercise price of $0.90 per share expired. 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, 2012, we were not party to any capital expenditure commitments other than the $602,889 present value 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 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 98


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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, including current political tensions between Israel, Iran and the United States and 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. During 2012, revenue from our oil production was negatively impacted by the glut of oil in mid-continental North America due to increased production in North Dakota, Alberta and Texas and insufficient pipeline capacity to transport this oil south to major markets. This has resulted in Canadian oil being sold at a discount to the West Texas Intermediate (“WTI”) benchmark crude oil price as rising production cannot find pipeline capacity. This discount to WTI has been even greater for heavy oil such as ours. This lack of pipeline capacity is expected to continue to depress the price paid for Canadian oil, and heavy oil in particular, during at least the next two years until new oil pipeline capacity comes on stream. We have decided to curtail our oil and gas development activities in the coming year to concentrate on advanced stage opportunities that my become available in the precious metals mineral exploration sector during 2013. 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, 2012, we were not party to any agreements or arrangements which gave rise to any contractually obligated payments. ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
  A.
        Directors and Senior Management.
 Directors Date of First Election orName of Director
        Age
        AppointmentGuido Cloetens
        46
        July 10, 2012Tom Ogryzlo
        73
        July 10, 2012Robert Hall
        36
        September 27, 2006Stuart Rogers
        56
        March 1, 2007Brian Morrison
        31
        September 5, 2008Edward Burylo
        69
        December 17, 2008
 Executive Officers and Management Name of Officer
        
        Age
        
        OfficeStuart Rogers
        
        56
        
        Chief Executive OfficerGordon Steblin
        
        53
        
        Chief Financial OfficerRobert Hall
        
        36
        
        Vice President Corporate Development
 The following describes the business experience of our directors and executive officers, including other directorships held in reporting companies: 99


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Stuart Rogers, Chief Executive Officer and 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 a director of MAX Resource Corp. and serves as a director and Chief Financial Officer of TerraX Minerals Inc. and Orefinders Resources Inc., all of which trade on the TSX Venture Exchange. Gordon Steblin, Chief Financial Officer Mr. Steblin obtained a Bachelor of Commerce degree in 1983 from the University of British Columbia, 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, Next Gen Metals Inc., Arctic Hunter Energy Inc. and CVC Cayman Ventures Corp. Robert Hall, Vice President Corporate Development and Director Mr. Hall brings over 10 years experience in management in both public and private companies to Alberta Star. He builds and maintains relationships with institutional and retail investors and assists in the day to day management of the Company. He is active as a director and officer of Arctic Hunter Energy Inc. and Windfire Capital Corp., both of which trade on the TSX Venture Exchange 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. Guido Cloetens, Director Guido Cloetens is a Certified Investment & Financial advisor located in Brussels, Belgium and has been active in the financial markets since 1988; he has participated in numerous financings and initial public offerings in Europe, the United States and in Canada in both private equity and public companies. Mr. Cloetens was a senior Investment advisor to international institutional Advisors from 1988 until 1995 at Daiwa Securities and KBC Bank. Tom Ogryzlo, Director Mr. Ogryzlo has over forty-five years of experience in mining, energy and mining projects worldwide. He has been responsible for the, financing, engineering, construction and operations of projects in many different countries. Mr. Ogryzlo has served as a director of many public companies, including Franco Nevada Mining Corp., Vista Gold Corp., Aura Minerals Inc., Birim Goldfields Inc., Baja Mining Corp. and Tiomin Resources Inc. During 2011, Mr. Ogryzlo served as Interim CEO of Aura Minerals Inc. until a permanent replacement could be located and is currently the Interim CEO of Baja Mining Corp. which is developing a $1.5 billion copper/cobalt/zinc project currently under construction in Baja California, Mexico. Mr. Ogryzlo holds a Bachelor of Mechanical Engineering from McGill University in Montreal, Quebec and, for many years, served as President of Kilborn Engineering Ltd. and Kilborn SNC-Lavalin, one of the worlds largest engineering contractors. He has been past President of several producing precious and base metal mining companies, including Triton Mining Corporation, Blackhawk Mining Inc. and Cerro Matoso S.A. His experience in exploration and development of numerous multi-million dollar mining projects spans the world. Over a six year period with Hanna Mining, he initially directed process development work as project manager and subsequently as President and General Manager, for the Cerro Matoso ferro-nickel project in Columbia where he was instrumental in 1979 in organizing a US$450 million financing involving World Bank, Exim, and a group of 52 private banks led by Chase Manhattan. Brian Morrison, Director Mr. Morrison has over 6 years of industry experience in the area of public company administration. Currently Mr. Morrison is a consultant for TSX-V listed junior mining companies and is a director of Saber Capital Corp., High North Resources Ltd., Decade Resources Ltd., Windfire Capital Corp., Touchdown Resources Inc. and Redhill Resources Corp. Prior to that, he was an Account Manager for public companies at Computershare Investor Services. 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. 100


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Edward Burylo Edward Burylo is a successful businessman with over 40 years of experience in the public markets. Mr. Burylo is currently a Director of Arctic Hunter Energy Inc., a TSX Venture 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, 2012. We pay $1,000 per month to our directors for their services in their capacity as directors from May 1, 2012 onwards. 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 as indicated below, no director received any compensation for his or her services as a director, including committee participation and/or special assignments. 2012 Summary Compensation Table LONG-TERMNAME AND PRINCIPAL POSITION
        ANNUAL COMPENSATION
        COMPENSATIONOtherAnnual
        
        
        LTIPSalary
        Compensation
        Awards
        payouts
        OtherRestricted
        Options/Stocks
        SARs(1)Tim Coupland : Former President, Chief Executive Officer and Director(2)
        $337,500
        -
        Nil
        $12,256
        Nil
        $12,000(6)Gord Steblin: CFO
        -
        $76,000(3)
        Nil
        $19,184
        Nil
        NilRobert Hall: Vice President Corporate Development and Director
        $80,000
        -
        Nil
        $19,184
        Nil
        NilStuart Rogers: Interim CEO
        
        $47,500(5)
        Nil
        $14,991
        Nil
        NilStuart Rogers: Director
        
        $2,000(5)
        Nil
        $9,191
        Nil
        NilBrian Morrison (appointed Sept. 5, 2008) Director
        -
        $7,000(4)
        Nil
        $19,184
        Nil
        NilEdward Burylo (appointed Dec. 17, 2008) Director
        -
        $7,000(4)
        Nil
        $19,184
        Nil
        NilGuido Cloetens (appointed July 10, 2012) Director
        -
        $5,000(4)
        Nil
        $16,607
        Nil
        NilTom Ogryzlo (appointed July 10, 2010) Director
        -
        $5,000(4)
        Nil
        $16,607
        Nil
        NilTamiko Coupland: Former Corporate Secretary
        $25,000(7)
        --
        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. Stock options were granted on January 9, 2012 with a calculated fair value of $0.12255 per share, July 10, 2012 with a calculated fair value of $0.08819 per share and October 12, 2012 with a calculated fair value of $0.09993 per share using the Black Scholes option pricing model.(2)
      Mr. Coupland resigned July 10, 2012 and this amount includes $204,167 paid as severance.(3)
      Fees paid to a company controlled by Mr. Steblin for accounting services. 101


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(4)
      These amounts are directors fees paid to entities controlled by the named director.(5)
      Fees paid to a company controlled by Mr. Rogers for CEO and director fees.(6)
      Vehicle allowance.(7)
      Resigned February 1, 2012. The table below sets forth the stock options granted to the Company’s director and officers during the fiscal year ended November 30, 2012: Number of Common
        Exercise PriceDirector or Officer
        Shares
        ($)
        Expiry DateGuido Cloetens
        75,000
        0.165
        July 10, 2015100,000
        0.20
        October 12, 2015Tom Ogryzlo
        75,000
        0.165
        July 10, 2015100,000
        0.20
        October 12, 2015Brian Morrison
        75,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Edward Burylo
        75,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Stuart Rogers
        75,000(1)
        0.21
        January 9, 2015150,000(1)
        0.20
        October 12, 2015Robert Hall
        75,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Gord Steblin
        75,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Tim Coupland
        100,000(2)
        0.21
        January 9, 2015
  (1)
      These options were issued to West Oak Capital Group, a private company owned by Stuart Rogers.(2)
      These options were cancelled during the year ended November 30, 2012 due to the resignation of Tim Coupland. 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. 102


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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’ terms 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 June 18, 2012. 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 Stuart Rogers, Brian Morrison and Guido Cloetens. 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; andEstablishes 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 MKT 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, and Cloetens are independent directors in accordance with Rule 10A-3 under the Exchange Act and Section 803 of the NYSE MKT Company Guide. In order to act in a forward-thinking manner, our board of directors intends to elect a compensation committee in 2013 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; 103


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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; andReviews and approves all special executive employment, compensation and retirement arrangements. D.
        Employees.
 At the end of the fiscal year ended November 30, 2012, we had one employee being the Vice President of Corporate Development. The employee was 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 oil and gas and mineral property interests. Our Chief Executive Officer and Chief Financial Officer are both engaged by the Company as consultants. E.
      Share Ownership. Our directors and officers beneficially own the following shares as of the date of this Annual Report: Common Shares Number of Common Shares
        Percentage of OutstandingDirector or Officer
        Owned
        (%)(1)Guido Cloetens
        2,215,000
        10.35Tom Ogryzlo
        -
        -Brian Morrison
        19,500
        0.02Edward Burylo
        3,800
        -Stuart Rogers
        114,000
        0.53Robert Hall
        72,700
        0.34Gord Steblin
        1,000
        -
 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: 104


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Shares that may be Purchased Upon Exercise of Stock Options Number of Common
        Exercise PriceDirector or Officer
        Shares
        ($)
        Expiry DateGuido Cloetens
        75,000
        0.165
        July 10, 2015100,000
        0.20
        October 12, 2015Tom Ogryzlo
        75,000
        0.165
        July 10, 2015100,000
        0.20
        October 12, 2015Brian Morrison
        30,000
        1.00
        July 2, 201475,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Edward Burylo
        50,000
        1.00
        July 2, 201475,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Stuart Rogers
        50,000
        1.00
        July 2, 201475,000(1)
        0.21
        January 9, 2015150,000(1)
        0.20
        October 12, 2015Robert Hall
        50,000
        1.00
        July 2, 201475,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015Gord Steblin
        50,000
        1.00
        July 2, 201475,000
        0.21
        January 9, 2015100,000
        0.20
        October 12, 2015
  (1)
      These options were issued to West Oak Capital Group, a private company owned by Stuart Rogers. At the annual general meeting of our shareholders held on June 18, 2012, 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 To the knowledge of the Company, the 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 are noted below. 105


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Identity of Person or Group(1)
        2012
        2011
        2010Guido Cloetens(3)
        10.81%
        -
        -Tim Coupland(4)(5)
        5.03%
        8.94%
        9.05%
 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) 2012: 21,403,979 shares of common stock issued and outstanding as of April 5, 2013; (2) 2011: 21,403,979 shares of common stock issued and outstanding as of March 27, 2013; and (3) 2010: 21,403,979 shares of common stock issued and outstanding as of March 29, 2011; unless otherwise noted. (3)
      Guido Cloetens beneficially owns 2,314,000 common shares including 2,139,000 common shares and 175,000 common shares acquirable upon exercise of outstanding stock options for a total of 10.81%. (4)
      In 2011, Tim Coupland beneficially owned 1,912,517 common shares including 1,077,517 common shares and 835,000 common shares acquirable upon exercise of outstanding stock options for a total of 8.94%. Tim Coupland holds 802,485 shares directly, T8X Capital Ltd., of which Tim Coupland is a 100% owner, holds 275,032 shares and 835,000 stock options. (5)
      As of July 10, 2012, Tim Coupland beneficially owned 1,077,517 common shares for a total of 5.03%. Tim Coupland held 802,485 shares directly, T8X Capital Ltd., of which Tim Coupland is a 100% owner, holds 275,032 shares. His current shareholdings cannot be confirmed as he is no longer an insider of the Company. 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, 2013: Number of registeredLocation
        shareholders
        Number of sharesCanada
        7
        21,387,059United States
        3
        4,200Other
        4
        12,720Total
        14
        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 April 5, 2013. 106


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B.
        Related Party Transactions.
  TRANSACTIONS WITH RELATED PARTIES Our board of directors consists of Guido Cloetens, Tom Ogryzlo, Robert Hall, Brian Morrison, Edward Burylo and Stuart Rogers. Stuart Rogers is our Chief Executive Officer, Robert Hall is our Vice President of Corporate Development and Gord Steblin is our Chief Financial Officer. We paid or accrued amounts to related parties as follows: For the Year Ended November 302012
        2011
        2010($)
        ($)
        ($)Secretarial fees paid to an individual related to Mr. Tim Coupland
        -
        -
        15,000Management fees paid to a company controlled by Mr. Stuart Rogers
        47,500
        -
        -Management fees paid to a company controlled by Mr. Tim Coupland
        -
        -
        50,000Director fees paid to a company controlled by Mr. Robert Hall
        -
        -
        15,000Director fees paid to a company controlled by Mr. Stuart Rogers
        2,000
        1,000
        27,000Director fees paid to Mr. Edward Burylo
        7,000
        1,000
        27,000Director fees paid to Mr. Brian Morrison
        7,000
        1,000
        27,000Director fees paid to Mr. Guido Cloetens
        5,000
        -
        -Director fees paid to Mr. Tom Ogryzlo
        5,000
        -
        -Accounting fees paid to a company controlled by Mr. Gord Steblin
        76,000
        70,500
        76,000Salaries and benefits paid to Mr. Tim Coupland*
        349,500
        362,000
        361,428Salaries and benefits paid to Mr. Rob Hall
        80,000
        80,000
        80,000Salaries and benefits paid to Ms. Tamiko Coupland**
        25,000
        60,000
        60,000$604,000
        $575,500
        $738,428
  *
      Resigned July 10, 2012 and this total includes a severance fee of $204,167.**
      Resigned February 1, 2012 During the year ended November 30, 2012, the Company sold plant, property and equipment to Arctic Hunter Energy Inc., a company with directors and officers in common, for proceeds of $8,000 (2011- $Nil), resulting in a gain of $8,000 (2011-$Nil). 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, 2012. C.
        Interests of Experts and Counsel.
 None. 107


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ITEM 8. FINANCIAL INFORMATION A.
        Financial Statements and Other Financial Information.
 Financial Statements As required, we have included the following as audited by an independent auditor and accompanied by an audit report, as of November 30, 2012, with the exception of the Supplementary Oil and Gas Reserve Estimation and Disclosures. Statements of financial position as at November 30, 2012 and 2011, and December 1, 2010;Statements of loss and comprehensive loss for the fiscal years ended November 30, 2012 and 2011;Statements of cash flows for the fiscal years ended November 30, 2012 and 2011;Statements of changes in shareholders’ equity for the fiscal years ended November 30, 2012 and 2011 ;Related notes and schedules; andSupplementary Oil and Gas Reserve Estimation and Disclosures – Unaudited. 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, 2012, 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: 108


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Period
        
        High
        
        LowDecember 1, 2007 to November 30, 2008
        $
        3.45
        $
        0.60December 1, 2008 to November 30, 2009
        $
        1.30
        $
        0.50December 1, 2009 to November 30, 2010
        $
        1.20
        $
        0.37December 1, 2010 to November 30, 2011
        $
        0.70
        $
        0.20December 1, 2011 to November 30, 2012
        $
        0.26
        $
        0.17Period
        
        High
        
        LowDecember 2010 to February 2011
        $
        0.70
        $
        0.44March 2011 to May 2011
        $
        0.59
        $
        0.39June 2011 to August 2011
        $
        0.44
        $
        0.26September 2011 to November 2011
        $
        0.27
        $
        0.20December 2011 to February 2012
        $
        0.26
        $
        0.20March 2012 to May 2012
        $
        0.26
        $
        0.17June 2012 to August 2012
        $
        0.20
        $
        0.17September 2012 to November 2012
        $
        0.23
        $
        0.17Period
        
        High
        
        LowSeptember 2012
        $
        0.23
        $
        0.19October 2012
        $
        0.23
        $
        0.19November 2012
        $
        0.19
        $
        0.17December 2012
        $
        0.18
        $
        0.16January 2013
        $
        0.17
        $
        0.16February 2013
        $
        0.19
        $
        0.16
 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
        
        LowDecember 1, 2007 to November 30, 2008
        US$
        3.50
        US$
        0.50December 1, 2008 to November 30, 2009
        US$
        1.10
        US$
        0.40December 1, 2009 to November 30, 2010
        US$
        1.20
        US$
        0.33December 1, 2010 to November 30, 2011
        US$
        0.71
        US$
        0.18December 1, 2011 to November 30, 2012
        US$
        0.27
        US$
        0.16Period
        
        High
        
        LowDecember 2010 to February 2011
        US$
        0.71
        US$
        0.43March 2011 to May 2011
        US$
        0.64
        US$
        0.40June 2011 to August 2011
        US$
        0.44
        US$
        0.26September 2011 to November 2011
        US$
        0.27
        US$
        0.18December 2011 to February 2012
        US$
        0.26
        US$
        0.18March 2012 to May 2012
        US$
        0.27
        US$
        0.16June 2012 to August 2012
        US$
        0.20
        US$
        0.16September 2012 to November 2012
        US$
        0.26
        US$
        0.16Period
        
        High
        
        LowSeptember 2012
        US$
        0.26
        US$
        0.19October 2012
        US$
        0.23
        US$
        0.18November 2012
        US$
        0.18
        US$
        0.16December 2012
        US$
        0.18
        US$
        0.15January 2013
        US$
        0.17
        US$
        0.16February 2013
        US$
        0.16
        US$
        0.16
  B.
        Plan of Distribution.
 Not applicable. 109


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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. 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 Robert Hall and the Company dated February 1, 2012 with respect to services in the capacity of Vice President Corporate Development at an annual salary of $80,000 filed as an exhibit to this Form 20-F;2.
      Consulting Agreement between Goring Development Corp. and the Company dated February 1, 2012 with respect to services rendered in the capacity of Chief Financial Officer at an annual amount of $78,000 filed as an exhibit to this Form 20-F.3.
      The Company entered into an employment contract dated March 30, 2007 and amended February 1, 2012 with Tom Coupland, for an indefinte term. Effective February 1, 2012, the base salary was reduced from $350,000 per annum to $180,000 per annum. On July 10, 2012, Mr. Coupland resigned and $204,167 was paid on the termination of his employment agreement. 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 the Investment 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 110


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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 United States 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. Except as specifically set forth below, this summary does not discuss applicable tax reporting requirements. 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. 111


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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; ora 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: (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 Income Tax Act (Canada) (“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 112


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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. In addition, in any year in which the Company is classified as a PFIC, such holder may be required to file an annual report with the IRS containing such information as Treasury Regulations and/or other IRS guidance may require. U.S. Holders should consult their own tax advisors regarding the requirements of filing such information returns under these rules, including the requirement to file a IRS Form 8621. 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 includes all revenues less the cost of goods sold, plus income from investments and from incidental or outside operations or sources, 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 (85% or more) of a foreign corporation’s commodities are stock in trade or inventory, depreciable property used in a trade or business or supplies regularly used or consumed in the ordinary course of its trade or business, and certain other requirements are satisfied. 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, and assuming certain other requirements are met, “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 for the tax year ended November 30, 2009 and during prior tax years. However, no determination has been made regarding our PFIC status for the tax years ended November 30, 2010, 2011 and 2012. 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). 113


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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. 114


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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 115


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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”. Subject to applicable limitations and provided that the Company is eligible for the benefits of the Canada-U.S. Tax Convention, dividends paid by the Company to non-corporate U.S. Holders, including individuals, generally will be eligible for the preferential tax rates applicable to long-term capital gains for dividends, provided certain holding period and other conditions are satisfied, including that the Company not be classified as a PFIC (as defined below) in the tax year of distribution or in the preceding tax year. The dividend rules are complex, and each U.S. Holder should consult its own tax advisor 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 116


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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. Additional Tax on Passive Income Individuals, estates and certain trusts whose income exceeds certain thresholds will be required to pay a 3.8% Medicare surtax on “net investment income” including, among other things, dividends and net gain from disposition of property (other than property held in certain trades or businesses). U.S. Holders should consult their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of common shares. 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. For example, U.S. return disclosure obligations (and related penalties) are imposed on individuals who are U.S. Holders that hold certain specified foreign financial assets in excess of certain threshold amounts. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity. U.S. Holders may be subject to these reporting requirements unless their common shares are held in an account at certain financial institutions. 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, including the requirement to file an IRS Form 8938. 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%, 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 117


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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 RESPECTTO 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. 118


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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, 2012. 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. 119


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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, 2012, 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, 2012. 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, 2012, 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 120


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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 Tom Ogryzlo, 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 MKT 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 2012 and 2011. The following is an aggregate of fees rendered during each of the years ended November 30, 2012 and 2011 for professional services rendered by our principal accountants: 2012
        
        
        2011Audit fees - auditing of our annual financial statements and preparation of auditors’ report.
        
        $39,000
        
        
        $50,752Tax fees - preparation
        
        4,000
        
        
        4,433All other fees – other services provided by our principal accountants.
        
        -
        
        
        -Total fees paid or accrued to our principal accountants
        
        $43,000
        
        
        $55,185
 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 2012. 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. 121


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ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES. Not applicable. 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, 2012. ITEM 16F. CHANGE IN CERTIFYING ACCOUNTANT. None. ITEM 16G. CORPORATE GOVERNANCE. Not applicable. ITEM 16H. MINE SAFETY DISCLOSURE. Not applicable. 122


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PART III ITEM 17 - FINANCIAL STATEMENTS Not applicable. ITEM 18 - FINANCIAL STATEMENTS The financial statements and schedules appear on Pages F-1 through F-53 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 statements of financial position as at November 30, 2012, and 2011, and 1 December 2010;the following statements for the fiscal years ended November 30, 2012 and 2011: statements of loss and comprehensive loss; andstatements of cash flows; our statements of changes in shareholders’ equity for the fiscal years ended November 30, 2012 and 2011;notes to the financial statements; andSupplementary Oil and Gas Reserve Estimation and Disclosures – Unaudited. All of these were audited by our auditor, James Stafford, Chartered Accountants, with the exception of the Supplementary Oil and Gas Reserve Estimation and Disclosures. The financial statements are prepared in accordance with IFRS as issued by the IASB. All figures are expressed in Canadian dollars. ITEM 19 - EXHIBITS Financial Statements PageDescriptionFinancial Statements and Notes
        
        F-1 - F-47Supplementary Oil and Gas Reserve Estimation and Disclosures - Unaudited
        
        F-48 - F-53
 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 Title1.1(1)
        Certificate of Incorporation and Certificate of Amendment and Registration of Restated Articles1.2(1)
        Bylaws1.3(1)
        Articles of Association4.1(2)
        Stock Option Plan as approved annually without change by Shareholders4.2*(2)
        Employment Agreement dated March 30, 2007 between Alberta Star Development Corp. and Mr. Tim Coupland, President and CEO4.3(2)
        Financial Public Relations Service Agreement dated December 15, 2007 between Alberta Star Development Corp. and MI3 Communications Financieres Inc.4.4(3)
        Shareholder Rights Plan Agreement dated October 10, 2008 between Alberta Star Development Corp. and MI3 Computershare Trust Company of Canada4.5(4)
        Financial Public Relations Service Agreement dated November 4, 2009 between Alberta Star Development Corp. and Progressive IR Consultants Corp.
 123


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4.6(5)
        Agreement of Purchase and Sale made as of August 5, 2010 between Western Plains Petroleum Ltd. and Alberta Star Development Corp.4.7(5)
        Asset Purchase Agreement made as of August 25, 2010 between Western Plains Petroleum Ltd. and Alberta Star Development Corp.4.8(5)
        Sub-participation Agreement made as of October 14, 2010 between Arctic Hunter Uranium Inc. and Alberta Star Development Corp.4.9(5)
        Joint Operating Agreement made as of August 5, 2010 between Western Plains Petroleum Ltd. and Alberta Star Development Corp.4.10(6)
        Employment Agreement dated February 1, 2012 between Alberta Star Development Corp. and Mr. Tim Coupland, President and CEO4.11(6)
        Employment Agreement dated February 1, 2012 between Alberta Star Development Corp. and Mr. Rob Hall, Vice President Corporate Development4.12(6)
        Consulting Agreement dated February 1, 2012 between Alberta Star Development Corp. and Goring Development Corp., acting as CFO11.1(2)
        Code of Ethics12.1
        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 200212.2
        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 200213.1
        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 200213.2
        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 200215.1
        Report and Consent of Petrotech15.2
        Consent of James Stafford, Chartered Accountants
 *
      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 20-F that was filed with the commission on April 8, 2008(3)
      incorporated by reference from our Form 20-F that was filed with the commission on March 24, 2009(4)
      Incorporated by reference from our Form 20-F that was filed with the commission on April 12, 2010(5)
      Incorporated by reference from our Form 20-F that was filed with the commission on May 17, 2011(6)
      Incorporated by reference from our Form 20-F that was filed with the commission on April 5, 2012 124


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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: April 5, 2013By: “Stuart Rogers”Stuart Rogers, CEO
 125


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Financial Statements 30 November 2012 (Expressed in Canadian dollars)  F-1


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JAMES STAFFORDINDEPENDENT AUDITOR’S REPORT

   James Stafford, Inc.Chartered AccountantsSuite 350 – 1111 Melville StreetVancouver, British ColumbiaCanada V6E 3V6Telephone +1 604 669 0711Facsimile +1 604 669 0754www.JamesStafford.ca
 To the Shareholders of Alberta Star Development Corp. We have audited the accompanying financial statements of Alberta Star Development Corp. which comprise the statements of financial position as at 30 November 2012, 30 November 2011 and 1 December 2010, and the statements of loss and comprehensive loss, cash flows and changes in equity for the years ended 30 November 2012 and 30 November 2011, and a summary of significant accounting policies and other explanatory information. Management’s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s Responsibility 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). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the financial statements present fairly, in all material respects, the financial position of Alberta Star Development Corp. as at 30 November 2012, 30 November 2011 and 1 December 2010, and the results of its operations and its cash flows for the years ended 30 November 2012 and 30 November 2011 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Emphasis of Matter Without qualifying our opinion, we draw attention to Note 1 in the financial statements, which describes matters and conditions that indicate the existence of a material uncertainty that raises substantial doubt about the ability of Alberta Star Development Corp. to continue as a going concern, including a net loss of $3,475,613 as at and for the year ended 30 November 2012 and accumulated deficit of $54,734,902 since inception.   Chartered Accountants Vancouver, Canada26 March 2013 F-2


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Alberta Star Development Corp.Statements of Financial Position(Expressed in Canadian dollars)
  Notes
   As at 30November2012$
   As at 30November2011$
   As at 1December2010$(Note 4)
   (Note 4)ASSETSCurrent assetsCash and cash equivalents
   5
   6,997,109
   7,780,441
   9,456,219Trade and other receivables
   6
   174,127
   235,489
   247,030Prepaid expenses
   7
   11,952
   14,161
   36,1397,183,188
   8,030,091
   9,739,388Exploration and evaluation properties
   8
   -
   729,515
   210,260Property, plant and equipment
   9
   1,455,645
   3,329,456
   3,656,257Total assets
   
   8,638,833
   12,089,062
   13,605,905EQUITY AND LIABILITIESCurrent liabilitiesTrade and other payables
   11
   1,469,037
   1,643,829
   1,713,640Decommissioning liabilities
   10
   602,889
   552,435
   489,180Total liabilities
   
   2,071,926
   2,196,264
   2,202,820EquityCommon shares
   12
   47,573,745
   47,573,745
   47,573,745Contributed surplus
   12
   13,728,064
   13,578,342
   13,231,208Warrant reserve
   12
   -
   -
   131,064Deficit
   
   (54,734,902)
   (51,259,289)
   (49,532,932)Total equity
   
   6,566,907
   9,892,798
   11,403,085Total equity and liabilities
   
   8,638,833
   12,089,062
   13,605,905
 APPROVED BY THE BOARD: “ Stuart Rogers”

   Director

   “ Robert Hall”

   DirectorStuart Rogers

   

   Robert Hall
  The accompanying notes are an integral part of these financial statements. F-3


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Alberta Star Development Corp.Statements of Loss and Comprehensive Loss(Expressed in Canadian dollars)
  Year ended 30 NovemberNotes
   2012$
   2011$(Note 4)RevenuePetroleum revenue
   
   2,422,266
   2,331,217Petroleum royalties
   
   (502,812)
   (425,260)Petroleum revenue, net of royalties
   
   1,919,454
   1,905,957Operating expensesPetroleum production and transportation
   
   1,120,317
   874,863Depletion and depreciation
   9
   1,658,495
   1,072,238Net petroleum loss
   
   (859,358)
   (41,144)General and administrative expenses
   19
   1,310,005
   1,764,471Loss before other items
   
   (2,169,363)
   (1,805,615)Other itemsInterest income
   
   70,621
   63,373Rent recovery
   18
   2,000
   -Finance costs
   10
   (22,096)
   (19,567)Unrealized foreign exchange loss
   
   (41,778)
   (6,263)Gain on sale of property, plant and equipment
   9
   18,518
   57,435Write-down of exploration and evaluation properties
   8
   (209,168)
   (15,720)Write-down of property, plant and equipment
   9
   (1,124,347)
   -Net loss and comprehensive loss
   
   (3,475,613)
   (1,726,357)Loss per shareBasic
   15
   (0.162)
   (0.081)Diluted
   15
   (0.162)
   (0.081)  The accompanying notes are an integral part of these financial statements. F-4


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Alberta Star Development Corp.Statements of Cash Flows(Expressed in Canadian dollars)
  Year ended 30 NovemberNotes
   2012$
   2011$(Note 4)OPERATING ACTIVITIESLoss for the year
   
   (3,475,613)
   (1,726,357)Adjustments for:Finance costs
   10
   22,096
   19,567Accrued interest income
   
   (216)
   -Depletion and depreciation
   9
   1,668,135
   1,088,275Gain on sale of property, plant and equipment
   9
   (18,518)
   (57,435)Share-based payments
   13
   149,722
   216,070Write-down of exploration and evaluation properties
   8
   209,168
   15,720Write-down of property, plant and equipment
   9
   1,124,347
   -Operating cash flows before movements in working capital(Increase) decrease in trade and other receivables
   
   24,227
   (32,833)Decrease in prepaid expenses
   
   2,209
   21,978Decrease in trade and other payables
   
   (174,792)
   (69,811)Cash used in operating activities
   
   (469,235)
   (524,826)INVESTING ACTIVITIESPurchase of property, plant and equipment
   9
   (385,254)
   (722,134)Purchase of exploration and evaluation expenditures
   8
   (22,361)
   (675,720)Recovery of exploration and evaluation expenditures
   8
   -
   168,750Recovery of plant, property and equipment
   9
   75,000
   -Proceeds on sale of property, plant and equipment
   9
   18,518
   78,152Cash used in investing activities
   
   (314,097)
   (1,150,952)Decrease in cash and cash equivalents
   
   (783,332)
   (1,675,778)Cash and cash equivalents, beginning of year
   
   7,780,441
   9,456,219Cash and cash equivalents, end of year
   
   6,997,109
   7,780,441
 Supplemental cash flow information(Note 20)  The accompanying notes are an integral part of these financial statements. F-5


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Alberta Star Development Corp.Statements of Changes in Equity(Expressed in Canadian dollars)
  Number ofshares
   Commonshares$
   Contributedsurplus$
   Warrantreserve$
   Deficit$
   Total$Balances, 1 December 2010 (Note 4)
   21,403,979
   47,573,745
   13,231,208
   131,064
   (49,532,932)
   11,403,085Share-based payments
   -
   -
   216,070
   -
   -
   216,070Warrants expired
   -
   -
   131,064
   (131,064)
   -
   -Net loss for the year
   -
   -
   -
   -
   (1,726,357)
   (1,726,357)Balances, 30 November 2011 (Note 4)
   21,403,979
   47,573,745
   13,578,342
   -
   (51,259,289)
   9,892,798Share-based payments
   -
   -
   149,722
   -
   -
   149,722Net loss for the year
   -
   -
   -
   -
   (3,475,613)
   (3,475,613)Balances, 30 November 2012
   21,403,979
   47,573,745
   13,728,064
   -
   (54,734,902)
   6,566,907
  The accompanying notes are an integral part of these financial statements. F-6


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  1.

   CORPORATE INFORMATION
 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 head office, principal address and registered and records office is located at Suite 506 - 675 West Hastings Street, Vancouver, British Columbia, V6B 1N2. The Company’s financial statements as at 30 November 2012 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 $3,475,613 for the year ended 30 November 2012 (2011 - $1,726,357) and has working capital of $5,714,151 at 30 November 2012 (30 November 2011 - $6,386,262, 1 December 2010 -$8,025,748). The Company had cash and cash equivalents of $6,997,109 at 30 November 2012 (30 November 2011 - $7,780,441, 1 December 2010 - $9,456,219), 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 2013. 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. 2.

   BASIS OF PREPARATION
 The financial statements of the Company for the years ended 30 November 2012, 30 November 2011 and as at 1 December 2010 were approved and authorized for issue by the Board of Directors on 26 March 2013. 2.1

   Basis of presentation
 The Company’s financial statements have been prepared on the historical cost basis except for certain financial instruments which are measured at fair value, as explained in Note 17, and are presented in Canadian dollars except where otherwise indicated. F- 7


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  2.2

   Statement of complianceThe financial statements of the Company have been prepared in accordance with and using accounting policies in full compliance with International Financial Reporting Standards (“IFRS”) and International Accounting Standards (“IAS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”), effective for the Company’s reporting for the years ended 30 November 2012, 30 November 2011 and as at 1 December 2010.2.3

   Adoption of new and revised standards and interpretationsAt the date of authorization of these financial statements, the IASB and IFRIC have issued the following new and revised standards, amendments and interpretations which are not yet effective during the year ended 30 November 2012. IFRS 9 ‘Financial Instruments: Classification and Measurement’is a new financial instruments standard effective for annual periods beginning on or after 1 January 2015 that replaces IAS 39 and IFRIC 9 for classification and measurement of financial assets and financial liabilities.IFRS 11 ‘Joint Arrangements’ is a new standard effective for annual periods beginning on or after 1 January 2013 that replaces IAS 31 and Standing Interpretations Committee Standards (“SIC”) 13.IFRS 13 ‘Fair Value Measurement’is a new standard effective for annual periods beginning on or after 1 January 2013 that replaces fair value measurement guidance in other IFRSs.IAS 1 (Amendment) ‘Presentation of Financial Statements’ is effective for annual periods beginning on or after 1 July 2012 and includes amendments regarding presentation of items of other comprehensive income.IAS 19 (Amendment) ‘Employee Benefits’ is effective for annual periods beginning on or after 1 January 2013 and revises recognition and measurement of post-employment benefits. The Company has not early adopted these standards, amendments and interpretations and anticipates that the application of these standards, amendments and interpretations will not have a material impact on the financial position and financial performance of the Company. F- 8


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  3.

   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES3.1

   Significant accounting judgments, estimates and assumptions The preparation of the Company’s financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities and contingent liabilities at the date of the financial statements and reported amounts of income and expenses during the reporting period. Estimates and assumptions are continuously evaluated and are based on management’s experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However, actual outcomes can differ from these estimates. Areas requiring a significant degree of estimation and judgment relate to the recoverability of the carrying value of petroleum and natural gas assets, fair value measurements for financial instruments and share-based payments, the recognition and valuation of provisions for decommissioning liabilities, the recoverability and measurement of deferred tax assets and liabilities and ability to continue as a going concern. Actual results may differ from those estimates and judgments. 3.2

   Cash and cash equivalentsCash and cash equivalents include highly liquid investments with original maturities of three months or less.3.3

   Property, plant and equipment Items of property, plant and equipment, which include petroleum and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses, net of reversals. Development and production assets are grouped into cash generating units for impairment testing. When significant parts of an item of property, plant and equipment, including petroleum and natural gas interests, have different useful lives, they are accounted for as separate items. Gains and losses on the disposal of an item of property, plant and equipment, including petroleum and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net in profit or loss. Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as petroleum and natural gas development and production assets only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized petroleum and natural gas assets generally represent costs incurred in developing proven and/or probable reserves and bringing on or enhancing production from such reserves. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of oil and gas properties are recognized in profit or loss as incurred. F- 9


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 The net carrying value of petroleum and natural gas development and production assets is depreciated using the unit of production method by reference to the ratio of production in the year to the related proven and probable reserves, including estimated future development costs. Future development costs are estimated taking into account the level of development required to bring reserves into production. These estimates are reviewed by independent reserve engineers at least annually. Changes in estimates such as quantities of proved and probable reserves that affect unit-of-production calculations are applied on a prospective basis. Other items of property, plant and equipment are depreciated over their estimated useful lives using the declining balance method at the following annual rates with half the rate applied in year of acquisition: Computer equipment

   30%Computer software

   100%Furniture and fixtures

   20%Equipment

   20%
  3.4

   Exploration and evaluation properties
 Exploration and evaluation expenditures include the costs of acquiring licenses, costs associated with exploration and evaluation activity, and the fair value (at acquisition date) of exploration and evaluation assets acquired in a business combination. Exploration and evaluation expenditures are capitalized. Costs incurred before the Company has obtained the legal rights to explore an area are recognized in profit or loss. Option payments received are treated as a reduction of the carrying value of the related property and deferred costs until the receipts are in excess of costs incurred, at which time they are credited to income. Option payments are at the discretion of the optionee, and accordingly, are recorded on a cash basis. Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. Once the technical feasibility and commercial viability of the extraction of mineral resources in an area of interest are demonstrable, exploration and evaluation assets attributable to that area of interest are first tested for impairment and then reclassified to mining property and development assets within property, plant and equipment. Recoverability of the carrying amount of any exploration and evaluation assets is dependent on successful development and commercial exploitation, or alternatively, sale of the respective areas of interest. F- 10


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  3.5

   Revenue recognitionPetroleum and natural gas revenues are recorded when title passes, the amount is determinable and collection is reasonably assured.3.6

   Decommissioning, restoration and similar liabilities The Company recognizes provisions for statutory, contractual, constructive or legal obligations associated with the reclamation of mineral properties and retirement of long-term assets, when those obligations result from the acquisition, construction, development or normal operation of the assets. The net present value of future cost estimates arising from the decommissioning of plant, site restoration work and other similar retirement activities is added to the carrying amount of the related asset, and depreciated on the same basis as the related asset, along with a corresponding increase in the provision in the period incurred. Discount rates using a pre-tax rate that reflect the current market assessments of the time value of money are used to calculate the net present value. The Company’s estimates of reclamation costs could change as a result of changes in regulatory requirements, discount rates and assumptions regarding the amount and timing of the future expenditures. These changes are recorded directly to the related asset with a corresponding entry to the provision. Changes in the net present value, excluding changes in the Company’s estimates of reclamation costs, are charged to profit or loss for the period. The net present value of reclamation costs arising from subsequent site damage that is incurred on an ongoing basis during production are charged to profit or loss in the period incurred. The costs of reclamation projects that were included in the provision are recorded against the provision as incurred. The costs to prevent and control environmental impacts at specific properties are capitalized in accordance with the Company’s accounting policy for exploration and evaluation properties. 3.7

   Share-based payments
 Share-based payments to employees are measured at the fair value of the instruments issued and recognized over the vesting periods. Share-based payments to non-employees are measured at the fair value of goods or services received or the fair value of the equity instruments issued, if it is determined the fair value of the goods or services cannot be reliably measured, and are recorded at the date the goods or services are received. The corresponding amount is recorded to contributed surplus. The fair value of options is determined using the Black-Scholes Option Pricing Model which incorporates all market vesting conditions. The number of shares and options expected to vest is reviewed and adjusted at the end of each reporting period such that the amount recognized for services received as consideration for the equity instruments granted shall be based on the number of equity instruments that will eventually vest. F- 11


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  3.8

   Flow-through shares
 Any premium received by the Company on the issuance of flow-through shares is initially recorded as a liability and included in trade and other payables. Upon renouncement by the Company of the tax benefits associated with the related expenditures, a deferred tax liability is recognized and the flow-through liability will be reversed. To the extent that suitable deferred tax assets are available, the Company will reduce the deferred tax liability and record a deferred tax recovery. 3.9

   Taxation
 Deferred tax is provided, using the liability method, on all temporary differences at the statement of financial position date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred tax liabilities are generally recognized for all taxable temporary differences. Deferred tax assets are generally recognized for all deductible temporary differences to the extent that it is probable that taxable profits will be available against which those deductible temporary differences can be utilized. Such deferred tax assets and liabilities are not recognized if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit. The carrying amount of deferred tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilized. Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the year when the asset is realized or the liability is settled, based on the tax rates that have been enacted or substantively enacted at the reporting date. 3.10

   Foreign currency translation
 The Company’s reporting currency and the functional currency of all of its operations is the Canadian dollar as this is the principal currency of the economic environment in which it operates. Foreign currency transactions are translated into functional currency using the exchange rates prevailing at the date of the transaction. Foreign currency monetary items are translated at the period-end exchange rate. Non-monetary items measured at historical cost continue to be carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at the exchange rate at the date when fair values were determined. Exchange differences arising on the translation of monetary items or on settlement of monetary items are recognized in profit or loss in the period in which they arise, except where deferred in equity as a qualifying cash flow or net investment hedge. F- 12


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Exchange differences arising on the translation of non-monetary items are recognized in other comprehensive income in the statement of comprehensive income to the extent that gains and losses arising on those non-monetary items are also recognized in other comprehensive income. Where the non-monetary gain or loss is recognized in profit or loss, the exchange component is also recognized in profit or loss. 3.11

   Loss per share
 Basic per share amounts are calculated by dividing the profit or loss attributable to shareholders of the Company by the weighted average number of shares outstanding during the period. Diluted per share amounts are determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of all dilutive potential common shares, which consist of share purchase warrants and stock options. 3.12

   Financial assets
 Financial assets are classified as financial assets at fair value through profit or loss (“FVTPL”), held-to-maturity, loans and receivables, available-for-sale financial assets, or as derivatives designated as hedging instruments in an effective hedge, as appropriate. The Company determines the classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value. The subsequent measurement of financial assets depends on their classification as follows: Financial assets at FVTPL Financial assets are classified as held for trading and are included in this category if acquired principally for the purpose of selling in the short term or if so designated by management. Derivatives, other than those designated as effective hedging instruments, are also categorized as held for trading. These assets are carried at fair value with gains or losses recognized in profit or loss. Transaction costs associated with financial assets at FVTPL are expensed as incurred. Cash and cash equivalents are included in this category of financial assets. Held-to-maturity and loans and receivables Held-to-maturity and loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in profit or loss when the financial assets classified in this category are derecognized or impaired, as well as through the amortization process. Transaction costs are included in the initial carrying amount of the asset. Trade and other receivables are classified as loans and receivables. F- 13


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Available-for-sale Available-for-sale financial assets are those non-derivative financial assets that are not classified as loans and receivables. After initial recognition, available-for-sale financial assets are measured at fair value, with gains or losses recognized within other comprehensive income. Accumulated changes in fair value are recorded as a separate component of equity until the investment is derecognized or impaired. Transaction costs are included in the initial carrying amount of the asset. The fair value is determined by reference to bid prices at the close of business on the reporting date. Where there is no active market, fair value is determined using valuation techniques. Where fair value cannot be reliably measured, assets are carried at cost. Derivatives designated as hedging instruments in an effective hedge The Company does not hold or have any exposure to derivative instruments. 3.13

   Financial liabilities
 Financial liabilities are classified as financial liabilities at FVTPL, derivatives designated as hedging instruments in an effective hedge, or as financial liabilities measured at amortized cost, as appropriate. The Company determines the classification of its financial liabilities at initial recognition. The measurement of financial liabilities depends on their classification, as follows: Financial liabilities at FVTPL Financial liabilities at FVTPL has two subcategories, including financial liabilities held for trading and those designated by management on initial recognition. Transaction costs on financial liabilities at FVTPL are expensed as incurred. These liabilities are carried at fair value with gains or losses recognized in profit or loss. Financial liabilities measured at amortized cost All other financial liabilities are initially recognized at fair value, net of transaction costs. After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognized respectively in interest, other revenues and finance costs. Trade payables are included in this category of financial liabilities. Derivatives designated as hedging instruments in an effective hedge The Company does not hold or have any exposure to derivative instruments. 3.14

   Impairment of financial assets
 Financial assets, other than financial assets at FVTPL, are assessed for indicators of impairment at each period end. F- 14


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Assets carried at amortized cost If there is objective evidence that an impairment loss on assets carried at amortized cost has been incurred, the amount of the loss is measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial asset’s original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in profit or loss. If, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized, the previously recognized impairment loss is reversed to the extent that the carrying value of the asset does not exceed what the amortized cost would have been had the impairment not been recognized. Any subsequent reversal of an impairment loss is recognized in profit or loss. Available-for-sale If an available-for-sale financial asset is impaired, the cumulative loss previously recognized in equity is transferred to profit or loss. Any subsequent recovery in the fair value of the asset is recognized within other comprehensive income. 3.15

   Derecognition of financial assets and liabilities
 Financial assets are derecognized when the rights to receive cash flows from the assets expire or, the financial assets are transferred and the Company has transferred substantially all the risks and rewards of ownership of the financial assets. On derecognition of a financial asset, the difference between the asset’s carrying amount and the sum of the consideration received and receivable and the cumulative gain or loss that had been recognized directly in equity is recognized in profit or loss. For financial liabilities, they are derecognized when the obligation specified in the relevant contract is discharged, cancelled or expires. The difference between the carrying amount of the financial liability derecognized and the consideration paid and payable is recognized in profit or loss. 3.16

   Impairment of non-financial assets
 The carrying amount of the Company’s assets is reviewed for an indication of impairment at the end of each reporting period. If an indication of impairment exists, the Company makes an estimate of the asset’s recoverable amount. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Recoverable amount of an asset group is the higher of its fair value less costs to sell and its value in use. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. F- 15


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and is written down to its recoverable amount. Impairment losses are recognized in profit or loss. An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist or may have decreased. If such indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if there has been a change in the estimates used to determine the asset’s recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation, if no impairment loss had been recognized. 3.17

   Related party transactions
 Parties are considered to be related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also considered to be related if they are subject to common control. Related parties may be individuals or corporate entities. A transaction is considered to be a related party transaction when there is a transfer of resources or obligations between related parties. 3.18

   Joint arrangements
 Substantially all of the Company’s petroleum and natural gas exploration and development activities involve jointly controlled assets; accordingly, the financial statements reflect only the Company’s share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. 3.19

   Comparative figures
 Certain comparative figures have been adjusted to conform to the current year’s presentation. 4.

   TRANSITION TO INTERNATIONAL FINANCIAL REPORTING STANDARDS4.1

   Initial adoption of IFRS IFRS 1 ‘First-time Adoption of International Financial Reporting Standards’ establishes guidance for the initial adoption of IFRS. The accounting policies in Note 3 have been applied consistently in preparing the financial statements for the year ended 30 November 2012. The financial statements for the year ended 30 November 2011 were prepared applying available standards under Canadian generally accepted accounting principles (“Canadian GAAP”). For the first-time adoption of IFRS, the comparative information for the year ended 30 November 2011 and the opening IFRS statement of financial position on 1 December 2010 (the “Transition Date”) have been revised where appropriate to conform with IFRS using various exemptions and options available under IFRS 1. F- 16


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  4.2

   Optional exemptions from full retrospective application
 Share-based payments IFRS 1 encourages, but does not require, first-time adopters to apply IFRS 2 “Share-based Payment”to equity instruments that were granted on or before 7 November 2002, or equity instruments that were granted subsequent to 7 November 2002 and vested before the Transition Date. The Company elected not to apply IFRS 2 to equity instruments that vested prior to the Transition Date. This resulted in no difference in share-based payments as at the Transition Date and for the year ended 30 November 2011. Full cost accounting IFRS 1 provides an exemption for entities that have used the full cost method of accounting under Canadian GAAP. The Company elected to measure oil and gas assets at the Transition Date on the following basis: Exploration and evaluation assets at the amount determined under Canadian GAAP; andAssets in the development or production phases at the amount determined for the cost center under Canadian GAAP, allocated to the cost center’s underlying assets pro rata using reserve values as at the Transition Date. An impairment test was completed for each cash-generating unit as at the Transition Date and no impairment loss was recorded. Decommissioning liabilities IFRS 1 requires entities that have taken advantage of the full cost accounting election to measure their decommissioning liabilities on transition under IAS 37, “Provision, Contingent Liabilities and Contingent Assets”and to treat any difference between this amount and the amount recognized under Canadian GAAP as an adjustment to retained earnings or deficit. 4.3

   Mandatory exception to full retrospective application
 Estimates In accordance with IFRS 1, the Company’s estimates under IFRS at the date of transition to IFRS must be consistent with estimates made for the same date under Canadian GAAP unless there is objective evidence that those estimates were in error. The estimates previously made by the Company under Canadian GAAP were not revised for application of IFRS. 4.4

   Reconciliation to previously reported financial statements
 IFRS 1 requires an entity to reconcile its equity, comprehensive loss and cash flows to prior periods. The reconciliations between the previously reported financial results under Canadian GAAP and the current reported financial results under IFRS are as follows: F- 17


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  Reconciliation of Statement of Financial Position as at 1 December 2010 Notes
   CanadianGAAP
   IFRSAdjustments
   IFRSASSETSCurrent assetsCash and cash equivalents
   
   9,456,219
   -
   9,456,219Trade and other receivables
   
   247,030
   -
   247,030Prepaid expenses
   
   36,139
   -
   36,1399,739,388
   -
   9,739,388Exploration and evaluation properties
   (a)
   -
   210,260
   210,260Property, plant and equipment
   (a)
   3,866,517
   (210,260)
   3,656,257Total assets
   
   13,605,905
   -
   13,605,905EQUITY AND LIABILITIESCurrent liabilitiesTrade and other payables
   
   1,713,640
   -
   1,713,640Decommissioning liability
   (c)
   352,780
   136,400
   489,180Total liabilities
   
   2,066,420
   136,400
   2,202,820EquityCommon shares
   (d)
   37,397,902
   10,175,843
   47,573,745Contributed surplus
   
   13,231,208
   -
   13,231,208Warrants reserve
   
   131,064
   -
   131,064Deficit
   (c)(d)
   (39,220,689)
   (10,312,243)
   (49,532,932)Total equity
   
   11,539,485
   (136,400)
   11,403,085Total equity and liabilities
   
   13,605,905
   -
   13,605,905
 F- 18


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Reconciliation of Statement of Financial Position as at 30 November 2011 Notes
   CanadianGAAP
   IFRSAdjustments
   IFRSASSETSCurrent assetsCash and cash equivalents
   
   7,780,441
   -
   7,780,441Trade and other receivables
   
   235,489
   -
   235,489Prepaid expenses
   
   14,161
   -
   14,1618,030,091
   -
   8,030,091Exploration and evaluation properties
   (a)
   -
   729,515
   729,515Property, plant and equipment
   (a)(b)(c)
   3,352,686
   (23,230)
   3,329,456Total assets
   
   11,382,777
   706,285
   12,089,062EQUITY AND LIABILITIESCurrent liabilitiesTrade and other payables
   
   1,643,829
   -
   1,643,829Decommissioning liability
   (c)
   459,354
   93,081
   552,435Total liabilities
   
   2,103,183
   93,081
   2,196,264EquityCommon shares
   (d)
   37,397,902
   10,175,843
   47,573,745Contributed surplus
   
   13,578,342
   -
   13,578,342Deficit
   (b)(c)(d)
   (41,696,650)
   (9,562,639)
   (51,259,289)Total equity
   
   9,279,594
   613,204
   9,892,798Total equity and liabilities
   
   11,382,777
   706,285
   12,089,062
 F- 19


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Reconciliation of Statement of Loss and Comprehensive Loss For the year ended 30 November 2011 Notes
   CanadianGAAP
   IFRSAdjustments
   IFRSRevenuePetroleum revenue
   
   2,331,217
   -
   2,331,217Petroleum royalties
   
   (425,260)
   -
   (425,260)Petroleum revenue, net of royalties
   
   1,905,957
   -
   1,905,957Operating expensesPetroleum production and transportation
   
   874,863
   -
   874,863Depletion and depreciation
   (b)
   1,816,497
   (744,259)
   1,072,238Accretion
   (c)
   24,912
   (24,912)
   -Net petroleum income (loss)
   
   (810,315)
   769,171
   (41,144)ExpensesMineral properties
   (e)
   15,720
   (15,720)
   -General and administrative
   
   1,764,471
   -
   1,764,471Income (loss) before other items
   
   (2,590,506)
   784,891
   (1,805,615)Other itemsInterest income
   
   63,373
   -
   63,373Finance costs
   (c)
   -
   (19,567)
   (19,567)Foreign exchange loss
   
   (6,263)
   -
   (6,263)Gain on sale of plant, property and equipment
   
   57,435
   -
   57,435Write-down of exploration and evaluation properties
   (e)
   -
   (15,720)
   (15,720)Net income (loss) and comprehensiveincome (loss)
   
   (2,475,961)
   749,604
   (1,726,357)
 F- 20


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Reconciliation of Statement of Cash Flows for the year ended 30 November 2011 The transition to IFRS did not have a significant impact on the Company’s statement of cash flows for the year ended 30 November 2011. The transition adjustments recognized in the statements of financial position and the statement of loss and comprehensive loss have resulted in reclassifications of various amounts on the statement of cash flows. However, there were no significant changes to the total operating, financial or investing cash flows. As a result, no reconciliation has been prepared. Differences between Canadian GAAP and IFRS (a)

   Full cost accounting
 The Company reclassified $210,260 which represents the deferred costs related to unproven petroleum and natural gas properties to exploration and evaluation properties from property, plant and equipment as at the Transition Date. As at 30 November 2011, the Company reclassified $729,515 to exploration and evaluation properties. (b)

   Depletion and depreciation
 Under Canadian GAAP, the full cost pool was depleted as one unit on a unit-of-production basis over proven reserves. Under IFRS, the Company depletes petroleum and natural gas interests on a unit-of-production basis over proven plus probable reserves. In addition, depletion is calculated at an individual component level. The change in accounting policy related to depletion and depreciation resulted in a decrease in depletion, depreciation and amortization and a corresponding increase in property, plant and equipment of $744,259 for the year ended 30 November 2011. (c)

   Decommissioning liabilities
 Under Canadian GAAP, decommissioning liabilities were discounted at a credit adjusted risk-free rate of 7%. Under IFRS, the estimated cash flow to abandon and remediate the wells and facilities has been discounted at a risk-free rate of 4% at the Transition Date. Upon transition to IFRS, this resulted in a $136,400 increase in the decommissioning liabilities with a corresponding increase in deficit. Under IFRS, the decommissioning liability is discounted at the end of each reporting period at the current risk-free discount rate. As at 30 November 2011, the Company re-measured the liabilities which resulted in a further difference of $37,974 recorded as a reduction in decommissioning liabilities with an offsetting entry to property, plant and equipment. The accretion expense related to the decommissioning liabilities decreased by $5,345 for the year ended 30 November 2011 under IFRS compared to Canadian GAAP. Accretion expense is included in finance costs under IFRS. F- 21


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  (d)

   Flow-through shares
 Flow-through shares are a unique Canadian tax incentive which is the subject of specific guidance under Canadian GAAP. Under Canadian GAAP, the Company accounted for the issue of flow-through shares in accordance with the provisions of the Canadian Institute of Chartered Accountants (the “CICA”) Emerging Issues Committee Abstract 146 ‘Flow-through Shares’. At the time of issue, the funds received are recorded as share capital. At the time of the filing of the renunciation of the qualifying flow-through expenditures to investors, the Company recorded a deferred tax liability with a charge directly to shareholders’ equity. Also under Canadian GAAP, a portion of the deferred tax assets that were not recognized in previous years, due to the recording of a valuation allowance, are recognized as a recovery of income taxes. IFRS does not contain explicit guidance pertaining to this tax incentive. Therefore, the Company has adopted a policy whereby the premium paid for flow-through shares in excess of the market value of the shares without the flow-through features at the time of issue is initially recorded as a flow-through liability. Upon renunciation by the Company of the tax benefits associated with the related expenditures, a deferred tax liability is recognized and the flow-through liability is reversed, with any difference recorded as deferred tax expense. A portion of the deferred tax assets that were not recognized in previous years, due to the recording of a valuation allowance, will reduce the deferred tax liability and be recorded as a deferred tax recovery. The change in accounting policy related to flow-through shares resulted in an increase in share capital and a corresponding increase in deficit of $9,436,156 as at the Transition Date. Further, the indemnification loss of $739,687 recorded as a reduction in share capital under Canadian GAAP has been reclassified as deferred tax expense under IFRS. (e)

   Exploration and evaluation properties
 Under Canadian GAAP, the Company expensed mineral acquisition and exploration and evaluation costs on an individual property basis until the viability of a property was determined. Under IFRS, the Company elected to capitalize mineral exploration and evaluation costs as incurred until it has been determined that a resource property can be economically developed as a result of establishing proven and probable reserves. The Company elected to test for impairment upon adoption of IFRS. The change in accounting policy related to exploration and evaluation costs resulted in an increase in exploration and evaluation properties of $15,720, which was subsequently written down during the year ended 30 November 2011. F- 22


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  5.

   CASH AND CASH EQUIVALENTS
 The Company’s cash and cash equivalents are denominated in the following currencies: As at 30November2012$
   As at 30November2011$
   As at 1December2010$Denominated in Canadian dollars
   5,474,920
   6,204,265
   9,415,265Denominated in U.S. dollars
   1,522,189
   1,576,176
   40,954Total cash and cash equivalents
   6,997,109
   7,780,441
   9,456,219
  6.

   TRADE AND OTHER RECEIVABLES
 The Company’s trade and other receivables arise from four main sources: petroleum and natural gas revenue receivable, Goods and Services Tax / Harmonized Sales Tax (“GST/HST”) receivable due from the government taxation authorities, interest receivable and other receivables from related parties. These are as follows: As at 30November2012$
   As at 30November2011$
   As at 1December2010$GST/HST receivable
   9,202
   25,951
   34,675Trade receivables
   164,709
   209,538
   212,355Interest receivable
   216
   -
   -Total trade and other receivables
   174,127
   235,489
   247,030
 Included in trade and other receivables are amounts due from a company related to the Company by way of management and directors in common of $1,273 (30 November 2011 - $Nil, 1 December 2010 - $Nil) which is disclosed in Note 18. The amounts are unsecured, non-interest bearing and has no fixed terms of repayment. F- 23


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  7.

   PREPAID EXPENSES
 The Company’s prepaid expenses are as follows: As at 30November2012$
   As at 30November2011$
   As at 1December2010$Insurance
   11,424
   11,053
   11,879Prepaid rent expense
   528
   528
   -Other
   -
   2,580
   24,260Total prepaid expenses
   11,952
   14,161
   36,139
  F- 24


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  8.   EXPLORATION AND EVALUATION PROPERTIES
 The Company’s exploration and evaluation properties expenditures for the year ended 30 November 2012 are as follows: Petroleum andNatural Gas   Contact Lake   Glacier Lake   OtherProperties   Property   Property   Properties   Total$   $   $   $   $ACQUISITION COSTSBalance, 1 December 2011   701,510   -   -   -   701,510Additions   8,006   -   -   -   8,006Transfer to property, plant and equipment   (526,509)   -   -   -   (526,509)Write-down   (183,007)   -   -   -   (183,007)Balance, 30 November 2012   -   -   -   -   -EXPLORATION AND EVALUATION COSTSBalance, 1 December 2011   28,005   -   -   -   28,005Camp costs and field supplies   -   1,575   -   -   1,575Claim maintenance and permitting   -   5,134   6,227   1,419   12,780Transfer to property, plant and equipment   (16,199)   -   -   -   (16,199)Write-down   (11,806)   (6,709)   (6,227)   (1,419)   (26,161)Balance, 30 November 2012   -   -   -   -   -Total costs   -   -   -   -   -
 F- 25


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 The Company’s exploration and evaluation properties expenditures for the year ended 30 November 2011 are as follows: Petroleum andNatural Gas   Contact Lake   Glacier Lake   OtherProperties   Property   Property   Properties   Total$   $   $   $   $ACQUISITION COSTSBalance, 1 December 2010   41,510   -   -   -   41,510Additions   660,000   -   -   -   660,000Balance, 30 November 2011   701,510   -   -   -   701,510EXPLORATION AND EVALUATION COSTSBalance, 1 December 2010   168,750   -   -   -   168,750Camp costs and field supplies   -   3,200   -   -   3,200Claim maintenance and permitting   -   4,874   6,227   1,419   12,520Decommissioning liabilities   28,005   -   -   -   28,005Cost recovery   (168,750)   -   -   -   (168,750)Write-down   -   (8,074)   (6,227)   (1,419)   (15,720)Balance, 30 November 2011   28,005   -   -   -   28,005Total costs   729,515   -   -   -   729,515
 F- 26


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Petroleum and natural gas properties During the year ended 30 November 2012, the Company recorded a provision for write-down of $194,813 (2011 - $Nil) related to petroleum and natural gas properties. 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 a 1% net smelter return royalty (“NSR”), in five 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. 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, totaling 10,563.78 ha (26,103.57 acres). Collectively the properties are known as the Contact Lake Mineral Claims. During the year ended 30 November 2012, the Company recorded a provision for write-down of $6,709 (2011 - $8,074) related to the Contact Lake Property. 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 a 2% 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. The Company may purchase one-half of the NSR for a one-time payment of $1,000,000. During the year ended 30 November 2012, the Company recorded a provision for write-down of $6,227 (2011 - $6,227) related to the Glacier Lake Property. 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, totaling 1,789.22 ha (4,421.24 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. The Company may purchase one-half of the NSR for a one-time payment of $1,000,000. 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, totaling 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). F- 27


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 During the year ended 30 November 2012, the Company recorded a provision for write-down of $526 (2011 - $526) related to the Eldorado property. 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 issuance of 50,000 common shares of the Company valued at $182,500. 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 6,305.51 ha (15,581.20 acres). 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 IOCG & Uranium Project now consists of fourteen mineral claims totaling 10,247.27 ha (25,321.47 acres). On 23 February 2013, the Company allowed three mineral claims related to the Eldorado South IOCG & Uranium Project to lapse (Note 23). Longtom Property – Longtom Lake, Northwest Territories The Company holds a 50% undivided interest subject to a 2% NSR, totaling 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 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 or 50% ($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. 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. F- 28


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 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. During the year ended 30 November 2012, the Company recorded a provision for write-down of $893 (2011 - $893) related to the Longtom Property. 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 $56,000. During the year ended 30 November 2012, the Company allowed this property to lapse. 9.   PROPERTY, PLANT AND EQUIPMENT
 The Company’s property, plant and equipment as at 30 November 2012 are as follows: Accumulated   Net bookCost   depreciation   value$   $   $Petroleum and natural gas properties   5,279,869   3,855,080   1,424,789Computer equipment   60,749   49,965   10,784Computer software   86,947   86,947   -Equipment   58,720   44,713   14,007Furniture and fixtures   25,706   19,641   6,065Total   5,511,991   4,056,346   1,455,645
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 The changes in the Company’s property, plant and equipment for the years ended 30 November 2012 and 2011 are as follows: Petroleum and            Furniturenatural gas   Computer   Computer      andproperties   equipment   software   Equipment   fixtures   Total$   $   $   $   $   $COSTBalance, as at 1 December 2010   3,579,007   60,749   86,947   58,720   67,205   3,852,628Additions   766,508   -   -   -   -   766,508Disposals   -   -   -   -   (41,499)   (41,499)Asset retirement costs   15,683   -   -   -   -   15,683Balance, as at 30 November 2011   4,361,198   60,749   86,947   58,720   25,706   4,593,320Additions   422,605   -   -   -   -   422,605Transfer from evaluation and   542,708   -   -   -   -   542,708exploration propertiesCost recovery   (75,000)   -   -   -   -   (75,000)Asset retirement costs   28,358   -   -   -   -   28,358As at 30 November 2012   5,279,869   60,749   86,947   58,720   25,706   5,511,991
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  Petroleum and            Furniturenatural gas   Computer   Computer      andproperties   equipment   software   Equipment   fixtures   Total$   $   $   $   $   $ACCUMULATED DEPRECIATION AND IMPAIRMENTBalance, as at 1 December 2010   -   38,740   86,947   36,859   33,825   196,371Depletion and depreciation   1,072,238   6,603   -   4,352   5,082   1,088,275Disposals   -   -   -   -   (20,782)   (20,782)Balance, as at 30 November 2011   1,072,238   45,343   86,947   41,211   18,125   1,263,864Depletion and depreciation   1,658,495   4,622   -   3,502   1,516   1,668,135Impairment loss   1,124,347   -   -   -   -   1,124,347As at 30 November 2012   3,855,080   49,965   86,947   44,713   19,641   4,056,346NET BOOK VALUESAt 1 December 2010   3,579,007   22,009   -   21,861   33,380   3,656,257At 30 November 2011   3,288,960   15,406   -   17,509   7,581   3,329,456At 30 November 2012   1,424,789   10,784   -   14,007   6,065   1,455,645
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 On 9 August 2010, the Company completed 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. 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. On 15 October 2010, the Company entered into a sub-participation agreement with Arctic Hunter Energy Inc. (“Arctic Hunter”), a company with officers and 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”), whereby the Company 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 28 December 2011, this participation agreement was terminated. On 19 November 2010, the Company entered into an agreement with Western Plains 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. On 10 May 2011, the Company entered into an asset exchange agreement with Canadian Natural Resources to acquire a 50% working interest in petroleum and natural gas rights, including one standing case well, on 240 acres located in the Landrose area of Saskatchewan in exchange for its 50% working interest in 320 acres of undeveloped land located in the Golden Lake area of Saskatchewan. The aggregate value of the assets exchanged is $50,000. F- 32


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 On 18 November 2011, the Company entered into a sub-participation agreement with Arctic Hunter. Under the agreement, Arctic Hunter has agreed to participate with the Company in the drilling of one test well. Arctic Hunter must pay 50% of the Company’s share of the cost to drill, complete and equip or abandon the test wells to earn a 25% working interest (being 50% of the Company’s pre-participation 50% working interest) in the well. 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. During the year ended 30 November 2012, the Company sold property, plant and equipment for proceeds of $18,518 (2011 - $78,152) resulting in a gain of $18,518 (2011 - $57,435), of which proceeds of $8,000 (2011 - $Nil) and a gain of $8,000 (2011 - $Nil) related to plant, property and equipment sold to Arctic Hunter (Note 18). Depletion and depreciation No general and administrative expenses were capitalized for the year ended 30 November 2012. Future development costs of $Nil (2011 - $274,500) were included in the depletion calculation. Impairment test The Company performed the impairment test at 30 November 2012 resulting in the net book value of petroleum and natural gas assets exceeding the estimated discounted future net cash flows associated with proved and probable reserves. Impairment of petroleum and natural gas assets in the amount of $1,124,347 (2011 - $Nil) was recognized during the year ended 30 November 2012. Prices used in the evaluation of the carrying value of the Company’s reserves for the purpose of the impairment test were: Year   Heavy Crude Oil($Cdn/BBL)2012   63.872013   60.922014   68.362015   71.102016   73.022017   73.022018   73.022019   73.812020   75.322021   76.872022   78.44Percentage increase each year thereafter   2.0%
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  10.   DECOMMISSIONING LIABILITIES
 The total decommissioning liabilities was estimated by management based on the Company’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods.  The total undiscounted abandonment and restoration cost obligation at 30 November 2012 is $675,870 (30 November 2011 - $640,427, 1 December 2010 - $624,273) and is expected to be incurred between 2013 to 2037. The present value of the decommissioning liabilities is estimated to be $602,889 (30 November 2011 - $552,435, 1 December 2010 - $489,180). The present value of the decommissioning liabilities was calculated using an inflation rate of 2% and discounted using a rate of 4%. An accretion expense component of $22,096 (2011 - $19,567) has been charged to operations, included in finance costs, to reflect an increase in the carrying amount of the decommissioning liabilities. The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of petroleum and natural gas properties: As at   As at   As at30 November   30 November   1 December2012   2011   2010$   $   $Balance, beginning of year   552,435   489,180   -Liabilities incurred or acquired   -   28,005   481,630Revisions to future reclamation andabandonment costs   28,358   15,683   -Accretion   22,096   19,567   7,550Decommissioning liabilities, ending   602,889   552,435   489,180
  11.   TRADE AND OTHER PAYABLES
 The Company’s trade and other payables are broken down as follows: As at   As at   As at30 November   30 November   1 December2012   2011   2010$   $   $Trade payables   905   172,697   226,675Accrued liabilities   1,468,132   1,471,132   1,486,965Total trade and other payables   1,469,037   1,643,829   1,713,640
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Included in the trade payables and accrued liabilities at 30 November 2012 is $639,445 (30 November 2011 - $639,445, 1 December 2010 - $639,445) related to Part XII.6 tax on funds raised by the Company on flow-through share offerings (Note 22). Included in the trade payables and accrued liabilities at 30 November 2012 is $739,687 (30 November 2011 - $739,687, 1 December 2010 – $739,687) related to the estimated costs to the Company for amending its flow-through filings (Note 22). Included in trade and other payables at 30 November 2012 is $25 (30 November 2011 - $Nil, 1 December 2010 - $Nil) payable to a company controlled by the interim Chief Executive Officer (“CEO”) and director of the Company (Note 18). The amounts are unsecured, non-interest bearing and has no fixed terms of repayment. Included in trade and other payables at 30 November 2012 is $Nil (30 November 2011 - $9,683, 1 December 2010 - $831) payable to a director of the Company (Note 18). The amounts are unsecured, non-interest bearing and has no fixed terms of repayment. Included in trade and other payables at 30 November 2012 is $Nil (30 November 2011 - $39,792, 1 December 2010 - $125,241) payable to Arctic Hunter (Note 18). The amounts are unsecured, non-interest bearing and have no fixed terms of repayment. 12.   SHARE CAPITAL
  12.1   Authorized share capital
 The Company has authorized an unlimited number of voting common shares with no par value. Authorized share capital also consists of an unlimited number of preferred shares with no par value, 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. At 30 November 2012, the Company had 21,403,979 common shares outstanding (30 November 2011 -21,403,979, 1 December 2010 - 21,403,979) and no preferred shares outstanding (30 November 2011 - Nil, 1 December 2010 - Nil). 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. 12.2   Shares issuances
 During the years ended 30 November 2012 and 2011, the Company did not issue any common shares. F- 35


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  12.3   Share purchase warrants
 The following is a summary of the changes in the Company’s share purchase warrants for the years ended 30 November 2012 and 2011: Year ended 30 November   2012   2011Weightedaverage      Weightedexercise      averageNumber of   price   Number of   exercise pricewarrants   $   warrants   $Outstanding, beginning of year   -   -   466,667   0.90Granted   -   -   -   -Exercised   -   -   -   -Expired   -   -   (466,667)   0.90Outstanding, end of year   -   -   -   -
  12.4   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 is a summary of the changes in the Company’s stock option plan for the years ended 30 November 2012 and 2011: Year ended 30 November   2012   2011Weighted      Weightedaverage      averageexercise      exerciseNumber of   price   Number of   Priceoptions   $   options   $Outstanding, beginning of year   1,580,000   0.70   1,180,000   1.26Granted   1,425,000   0.20   910,000   0.48Exercised   -   -   -   -Expired   -   -   (410,000)   1.60Cancelled   (980,000)   0.68   (100,000)   1.40Outstanding, end of year   2,025,000   0.36   1,580,000   0.70
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 The weighted average fair value of the options granted and vested during the year ended 30 November 2012 was estimated at $0.10 (2011: $0.24) per option at the grant date using the Black-Scholes Option Pricing Model. The weighted average assumptions used for the calculation were: Year ended 30 November   2012   2011Risk free interest rate   1.11%   1.64%Expected life   2.92 years   2.00 yearsExpected volatility   79.02%   96.57%Expected dividend per share   -%   -%
 The following table summarizes information regarding stock options outstanding and exercisable as at 30 November 2012: Number ofoptionsoutstanding   Exercise   Remainingand   price   contractualGrant date   Expiry date   exercisable   $   life (years)3 July 2009   2 July 2014   250,000   1.00   1.598 December 2010 (Note 23)   7 December 2012   450,000   0.48   0.029 January 2012   9 January 2015   375,000   0.21   2.1131 January 2012   31 January 2014   50,000   0.25   1.1710 July 2012   10 July 2015   150,000   0.165   2.6112 October 2012   12 October 2015   750,000   0.20   2.87Total options outstanding and exercisable   2,025,000
  12.5   Shareholder rights plan
 Effective 10 October 2008, the Board of Directors has approved and adopted a shareholder 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. F- 37


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  13.   SHARE-BASED PAYMENTS
 Share-based payments for the following options granted by the Company will be amortized over the vesting period, of which $149,722 was recognized in the year ended 30 November 2012 (2011 - $216,070): Amount   Amount vestedFair value   vested in 2012   in 2011Grant date   $   $   $4 November 2009   2,682   -   2,6828 December 2010   213,707   319   213,3889 January 2012   58,211   58,211   -31 January 2012   3,014   3,014   -10 July 2012   13,229   13,229   -12 October 2012   74,949   74,949   -Total   365,792   149,722   216,070
  14.   TAXES
  14.1   Provision for income taxes
  2012   2011Year ended 30 November   $   $Loss before tax   (3,475,613)   (1,726,357)Statutory tax rate   25.13%   26.67%Expected tax recovery   873,422   460,419Non-deductible items   (41,590)   (63,897)Change in future tax rates   175,310   (24,829)Change in valuation allowance   (1,007,142)   (371,693)Tax recovery for the year   -   -
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  14.2   Deferred tax balances
 The tax effects of temporary differences that give rise to future income tax assets and liabilities are as follows: As at 30   As at 30   As at 1November   November   December2012   2011   2010$   $   $Tax loss carry-forwards   1,935,768   1,784,018   1,677,782Property, plant and equipment   84,013   83,001   93,351Exploration and evaluation properties   2,492,295   1,655,525   1,394,457Decommissioning liabilities   156,751   138,109   122,295Share issue costs   1,118   2,150   3,2254,669,945   3,662,803   3,291,110Less: Valuation allowance   (4,669,945)   (3,662,803)   (3,291,110)Deferred tax assets   -   -   -
  14.3   Expiry dates
 The Company’s recognized and unrecognized deferred tax assets related to unused tax losses have the following expiry dates: 2012As at 30 November   $Non-capital losses2026   672,0832028   2,495,8932029   1,870,5222030   1,672,6302031   424,9452032   309,187Total non-capital losses   7,445,260Total resource-related deduction, no expiry   11,010,540
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  15.   LOSS PER SHARE
 The calculation of basic and diluted loss per share is based on the following data: Year ended 30 November      2012      2011Net loss for the year   $   (3,475,613)   $   (1,726,357)Weighted average number of shares – basic and diluted      21,403,979      21,403,979Loss per share, basic and diluted   $   (0.162)   $   (0.081)
 The basic loss per share is computed by dividing the net loss by the weighted average number of common shares outstanding during the year. The diluted loss per share reflects the potential dilution of common share equivalents, such as outstanding stock options and share purchase warrants, in the weighted average number of common shares outstanding during the year, if dilutive. All of the stock options and share purchase warrants were anti-dilutive for the years ended 30 November 2012 and 2011. 16.   CAPITAL RISK MANAGEMENT
 The capital structure of the Company consists of equity attributable to common shareholders, comprising of issued capital, contributed surplus 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 2012. The Company is not subject to externally imposed capital requirements. F- 40


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  17.   FINANCIAL INSTRUMENTS
  17.1   Categories of financial instruments
  As at 30   As at 30   As at 1November   November   December2012   2011   2010$   $   $FINANCIAL ASSETSFVTPL, at fair valueCash and cash equivalents   6,997,109   7,780,441   9,456,219Loans and receivables, at amortized costTrade and other receivables   164,925   209,538   212,355Total financial assets   7,162,034   7,989,979   9,668,574FINANCIAL LIABILITIESOther liabilities, at amortized costTrade payables   905   172,697   226,675Total financial liabilities   905   172,697   226,675
  17.2   Fair value
 The fair value of financial assets and financial liabilities at amortized cost is determined in accordance with generally accepted pricing models based on discounted cash flow analysis or using prices from observable current market transactions. The Company considers that the carrying amount of all its financial assets and financial liabilities recognized at amortized cost in the financial statements approximates their fair value due to the demand nature or short term maturity of these instruments. The following table provides an analysis of the Company’s financial instruments that are measured subsequent to initial recognition at fair value, grouped into Level 1 to 3 based on the degree to which the inputs used to determine the fair value are observable. Level 1 fair value measurements are those derived from quoted prices in active markets for identical assets or liabilities.Level 2 fair value measurements are those derived from inputs other than quoted prices included within Level 1, that are observable either directly or indirectly.Level 3 fair value measurements are those derived from valuation techniques that include inputs that are not based on observable market data. As at 30 November 2012, the Company does not have any Level 3 financial instruments. F- 41


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  As at   As at   As at30 November   30 November   1 December2012   2011   2010$   $   $LEVEL 1Financial assets at fair valueCash and cash equivalents   6,997,109   7,780,441   9,456,219Total financial assets at fair value   6,997,109   7,780,441   9,456,219
 There were no transfers between Level 1 and 2 in the year ended 30 November 2012. 17.3   Management of financial risks
 The financial risk arising from the Company’s operations are credit risk, liquidity risk, interest rate risk, currency risk and commodity price risk. These risks arise from the normal course of operations and all transactions undertaken are to support the Company’s ability to continue as a going concern. The risks associated with these financial instruments and the policies on how to mitigate these risks are set out below. Management manages and monitors these exposures to ensure appropriate measures are implemented on a timely and effective manner. 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 trade receivables. 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 2012, trade receivables were comprised of GST/HST receivable of $9,202 (30 November 2011 -$25,951, 1 December 2010 - $34,675), petroleum revenue receivable of $164,709 (30 November 2011 - $209,538, 1 December 2010 - $212,355), and interest receivable of $216 (30 November 2011 - $Nil, 1 December 2010 - $Nil). As a result, credit risk is considered insignificant. 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. F- 42


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
 Interest rate 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 $58,128 for the year ended 30 November 2012. 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’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 (Note 5). The Company monitors and forecasts the values of net foreign currency cash flow and financial position 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 Company has not, to the date of these financial statements, entered into derivative instruments to offset the impact of foreign currency fluctuations. Commodity price risk The Company is in the exploration stage and is not subject to commodity price risk. 18.   RELATED PARTY TRANSACTIONS
 For the year ended 30 November 2012, the Company had related party transactions with Arctic Hunter, a company related by way of officers and directors in common for rent recovery and sale of property, plant and equipment. F- 43


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  18.1   Related party expenses
 The Company’s related party expenses are broken down as follows: 2012   2011Year ended 30 November   $   $Rent recovery   (2,000)   -Total related party expenses (recovery)   (2,000)   -
  18.2   Due from/to related parties
 The assets and liabilities of the Company include the following amounts due from/to related parties: As at 30   As at 30   As at 1November   November   December2012   2011   2010$   $   $Arctic Hunter   1,273   -   -Total amount due from related party   1,273   -   -Arctic Hunter   -   39,792   125,241Company controlled by interim CEO and director   25   -   -Director   -   9,683   831Total amount due to related parties   25   49,475   126,072
 The amounts due to/from related parties are unsecured, non-interest bearing and have no fixed terms of repayment. F- 44


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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  18.3   Key management personnel compensation
 The remuneration of directors and other members of key management were as follows: 2012   2011Year ended 30 November   $   $Short-term benefits   604,000   597,515Share-based payments   146,388   196,784Total key management personnel compensation   750,388   794,299
  18.4   Other related party transactions
 During the year ended 30 November 2012, the Company sold plant, property and equipment to Arctic Hunter for proceeds of $8,000 (2011 - $Nil), resulting in a gain of $8,000 (2011 - $Nil) (Note 9). 19.   GENERAL AND ADMINISTRATIVE EXPENSES
  2012   2011Year ended 30 November   $   $Advertising and promotion   21,521   135,152Depreciation   9,640   16,037Automotive   3,388   5,082Bank charges and interest   1,012   951Consulting fees   73,284   182,825Directors fees   26,000   3,000Filing fees   62,014   53,090Legal and accounting   237,408   304,831Management fees   47,500   -Meals and entertainment   31,549   47,029Office and miscellaneous   36,892   48,693Rent and utilities   56,479   48,863Salaries and benefits   474,224   524,015Share-based payments   149,722   216,070Telephone and internet   14,315   16,034Transfer fees and shareholder information   47,300   118,674Travel   17,757   44,125Total   1,310,005   1,764,471
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  20.   SUPPLEMENTAL CASH FLOW INFORMATION
 Included in trade and other receivables is $37,351 (30 November 2011 - $44,374, 1 December 2010 - $Nil) related to the purchase of capital expenditures for the petroleum and natural gas properties as at 30 November 2012. Included in decommissioning liabilities is $28,358 (30 November 2011 - $15,683, 1 December 2010 - $Nil) related to the revision of future reclamation costs as at 30 November 2012 (Note 10). 20.1   Cash payments for interest and taxes
 The Company made the cash payments for interest of $Nil (2011 - $Nil) and income taxes of $Nil (2011 - $Nil) during the year ended 30 November 2012. 21.   SEGMENTED INFORMATION
 The Company’s business activity is acquiring and exploring mineral and petroleum and natural gas properties. At 30 November 2012, the Company operates in three geographical areas, being British Columbia, Alberta/Saskatchewan and the Northwest Territories. The following is an analysis of the revenues, net loss, current assets and non-current assets by geographical area: British   Alberta/   NorthwestColumbia   Saskatchewan   Territories   TotalPetroleum revenue, net of royaltiesFor the year ended 30 November 2012   -   1,919,454   -   1,919,454For the year ended 30 November 2011   -   1,905,957   -   1,905,957Net income (loss)For the year ended 30 November 2012   (1,243,162)   (2,236,614)   4,163   (3,475,613)For the year ended 30 November 2011   (1,689,926)   (60,711)   24,280   (1,726,357)Current assetsAs at 30 November 2012   7,018,479   164,709   -   7,183,188As at 30 November 2011   7,820,553   209,538   -   8,030,091As at 1 December 2010   9,527,033   212,355   -   9,739,388Exploration and evaluation propertiesAs at 30 November 2012   -   -   -   -As at 30 November 2011   -   729,515   -   729,515As at 1 December 2010   -   210,260   -   210,260Property, plant and equipmentAs at 30 November 2012   30,856   1,424,789   -   1,455,645As at 30 November 2011   40,496   3,288,960   -   3,329,456As at 1 December 2010   77,250   3,579,007   -   3,656,257
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Alberta Star Development Corp.Notes to the Financial Statements30 November 2012(Expressed in Canadian dollars)
  22.   COMMITMENTS AND OTHER OBLIGATIONS
 The Company has certain obligations related to the amendments of its flow-through filings (Note 11). 23.   EVENTS AFTER THE REPORTING PERIOD
 The following events occurred subsequent to 30 November 2012: On 7 December 2012, a total of 450,000 stock options with an exercise price of $0.48 per share expired (Note 12). On 23 February 2013, the Company allowed three mineral claims related to the Eldorado South IOCG & Uranium Project to lapse (Note 8). F- 47


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Alberta Star Development Corp. Supplementary Information – Oil and Gas Activities For the year ended November 30, 2012 (Canadian Dollars) (Unaudited) F-48


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DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES TOPIC 932 “EXTRACTIVE ACTIVITIES – OIL AND GAS” (unaudited) The following select disclosures of Alberta Star Development Corp.’s (“Alberta Star” or the “Company”) reserves and other oil and gas information have been prepared in accordance with United States (“U.S.”) Financial Accounting Standards Board (“FASB”) Topic 932 – “Extractive Activities – Oil & Gas” and the U.S. disclosure requirements of the Securities and Exchange Commission (“SEC”). All amounts pertaining to the Company’s audited financial statements are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Unless otherwise noted, all amounts are in thousands of Canadian dollars. RESERVES DATA The SEC Modernization of Oil and Gas Reporting final rules require that proved reserves be estimated using existing economic conditions (constant pricing). The Company’s results have been calculated using the average of the first-day-of-the-month prices for the prior 12 month period. This same 12 month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. Future fluctuations in prices, production rates, or changes in political or regulatory environments could cause the Company’s share of future production from Canadian reserves to be materially different from that presented. The reserves estimates included in this supplemental information are estimates only. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. In general, estimates of economically recoverable crude oil and natural gas reserves and the future net cash flows derived therefrom are based upon a number of variable factors and assumptions, including but not limited to: product prices; future operating and capital costs; historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments and taxes; initial production rates; production decline rates; and the availability, proximity and capacity of oil and gas gathering systems, pipelines and processing facilities, all of which may vary considerably from actual results. All such estimates are to some degree uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the economically recoverable crude 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 expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Our actual production, revenues, royalty payments, taxes and development and operating expenditures with respect to our reserves may vary from current estimates and such variances may be material. Estimates with respect to 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 upon actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves. Canadian provincial royalties are determined based on a graduated percentage scale which varies with prices and production volumes. Canadian reserves, as presented on a net basis, assume royalty rates in existence at the time the estimates were made. Subsequent to November 30, 2012 no major discovery or other favourable or unfavourable event is believed to have caused a material change in the proved or proved developed reserves as of that date. F-49


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OIL AND GAS RESERVE INFORMATION All of Alberta Star’s reserves are located in Canada, primarily within the provinces of Alberta and Saskatchewan. Net Proved Reserves (Alberta Star Share After Royalties)(1)(2)(3) Average Fiscal-Year Prices Crude Oil andNatural GasLiquids(thousands ofbarrels)2011Beginning of year   192Revisions and improved recovery   (78.6)Production   (35.4)End of year   78Developed   57.0Developed Non-Producing   20.0Total   772012Beginning of year   16.0Revisions and improved recovery   57.1Production   (37.6)End of year   35.5Developed   35.5Total   35.5
 Notes: (1)   Definitions: (a)   “Net” reserves are the remaining reserves attributable to the Company, after deduction of estimated royalties and including royalty interests.(b)   “Proved” oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations, i.e., prices and costs as of the date the estimate is made.(c)   “Developed” oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods in which the cost or the required equipment is relatively minor compared to the cost of a new well.(d)   “Undeveloped” reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (2)   Estimates of total net proved bitumen, crude oil, natural gas liquids, or natural gas reserves are not filed by the Company with any U.S. federal authority or agency other than the SEC.(3)   Natural gas liquids reserves are individually insignificant and have been included with crude oil reserves. F-50


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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein In calculating the standardized measure of discounted future net cash flows, the average of the first-day-of-the-month prices for the prior 12 month period and cost assumptions were applied to the Company’s annual future production from proved reserves to determine cash inflows. Future production and development costs do not include any cost inflation and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The discount was computed by application of a ten percent discount factor to the future net cash flows. The calculation of the standardized measure of discounted future net cash flows is based upon the discounted future net cash flows prepared by independent qualified reserves evaluators in relation to the reserves they respectively evaluated, and adjusted to the extent provided by contractual arrangements such as price risk management activities, in existence at year end and to account for asset retirement obligations and future income taxes. The Company cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of the Company’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of ten percent may not appropriately reflect future interest rates. The computation also excludes values attributable to the Company’s enhancing the netback price of the Company’s proprietary production. Computation of the standardized measure of discounted future net cash flows relating to proved oil and gas reserves were based on the following average of the first-day-of-the-month benchmark prices for the twelve month period before the end of the year: Crude OilHeavy Crude atCromer   Lloydminster   MaidstoneCDN$/bbl   CDN$/bbl   CDN$/bbl2012   62.27   68.26   64.942011   87.94   66.40   64.20
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves ($ thousands)      2012      2011Future cash inflows      2,048.1      4,270.6Less future:Production costs      1,081.3      1,954.4Development costs      -      484.5Asset retirement obligation payments      154.6      329.7Future net cash flows      812.2      1,502.0Less 10 percent annual discount for estimated timing of cash flows      113.8      431.0Discounted future net cash flows      698.4      1071.0
 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves ($ thousands)      2012      2011Balance, beginning of year      1,071.0      6,613.0Changes resulting from:Net change in sales, transfer prices and in production (lifting) costs related to future production      (1,054.7)      (6,047.5)Changes in future development costs      580.7      224.7Accretion of discount      101.4      280.8Balance, end of year      698.4      1,071.0
 Results of Operations ($ thousands)      2012      2011Oil and gas sales, net of royalties      1,919      1,9061,919      1,906Less:Operating costs, production and transportation, and accretion of decommissioning liabilities      1,142      894Depreciation, depletion and amortization      1,658      1,072Write-down      1,319      -Operating income      (2,200)      (60)
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Capitalized Costs ($ thousands)      2012      2011Proved oil and gas properties      5,280      4,361Unproved oil and gas properties      -      730Total capital cost      5,280      5,091Accumulated depreciation, depletion, amortization and impairment      3,855      1,072Net capitalized costs      1,425      4,019
 Costs Incurred ($ thousands)      2012      2011Acquisitions- Unproved      -      -- Proved      -      -Total acquisitions      -      -Exploration costs      8      491Development costs      422      767Total costs incurred      430      1,258
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