ASXSF Elysee Development Corp (PK)

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.

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

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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:

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Not Applicable.

Not Applicable.

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

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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

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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

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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; and

• the 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

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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 Act and the Specified Gas Emitters Regulation . We may also be required comply with the regulatory scheme for greenhouse gas emissions ultimately adopted by the federal government, which is now expected to be modified to ensure consistency with the regulatory scheme for greenhouse gas emissions adopted by the United States. The direct or indirect costs of these regulations may have a material adverse effect on our business, financial condition, results of operations and prospects. The future implementation or modification of greenhouse gases regulations, whether to meet the limits required by the Kyoto Protocol, the Copenhagen Accord or as otherwise determined, could have a material impact on the nature of oil and natural gas operations, including ours. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on us, our operations and financial condition. See " Industry Conditions - Climate Change Regulation ".

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,

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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

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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; and

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

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

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

Significant competition exists for the limited number of property acquisition opportunities available. As a result of this competition, some of which is with large, established mining companies with substantial capabilities and greater financial and technical resources than us, we may be unable to acquire attractive mining properties on terms we consider acceptable. Competition in the precious metals mining industry is primarily for mineral rich properties which can be developed and exploited economically; the technical expertise to find, develop, and produce such properties; the labour to operate the properties; and the capital for the purpose of funding such properties. Many competitors not only explore for and mine precious metals and minerals but conduct refining and marketing operations on a worldwide basis. Such competition may result in our being unable to acquire desired properties, to recruit or retain qualified employees, to obtain necessary exploration, development or production equipment or to acquire the capital necessary to fund our operations and develop our properties. Our inability to compete with other mining companies for these resources may have a material adverse effect on

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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.

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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; and

• Capital available for exploration activity.

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

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

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

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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.

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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.

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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

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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.

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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; and

• the 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.

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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

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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.

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".

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

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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.

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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

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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

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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.

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

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

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

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

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

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

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

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

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

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

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

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

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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.

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

On April 26, 2007, the Government of Canada released "Turning the Corner: An Action Plan to Reduce Greenhouse Gases and Air Pollution" (the "Action Plan") which set forth a plan for regulations to address both greenhouse gases and air pollution. An update to the Action Plan, "Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions" was released on March 10, 2008 (the "Updated Action Plan"). The Updated Action Plan outlines emissions intensity-based targets which will be applied to regulated sectors on either a facility-specific, sector-wide or company-by-company basis. Facility-specific targets apply to the upstream oil and gas, oil sands, petroleum refining and natural gas pipelines sectors. Unless a minimum regulatory threshold applies, all facilities within a regulated sector will be subject to the emissions intensity targets. 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 Act which received royal assent on November 4, 2008. The CCEMA is based on an emissions intensity approach similar to the Updated Action Plan and aims for a 50% reduction from 1990 emissions relative to GDP by 2020.

Alberta facilities emitting more than 100,000 tonnes of greenhouse gases a year are subject to comply with the CCEMA. Similarly to the Updated Action Plan, the CCEMA and the associated Specified Gas Emitters Regulation make a distinction between "Established Facilities" and "New Facilities". Established Facilities are defined as facilities that completed their first year of commercial operation prior to January 1, 2000 or that have completed eight or more years of commercial operation. Established Facilities are required to reduce their emissions intensity to 88% of their baseline for 2008 and subsequent years, with their baseline being established by the average of the ratio of the total annual emissions to production for the years 2003 to 2005. New Facilities are defined as facilities that completed their first year of commercial operation on December 31, 2000, or a subsequent year, and have completed less than eight years of commercial operation, or are designated as New Facilities in accordance with the Specified Gas Emitters Regulation. New Facilities are required to

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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.

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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.

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

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

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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.

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41

Lloydminster Alberta

Maidstone

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Maidstone

Landrose

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Lloydminster Nordic, Alberta

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Hillmond

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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.

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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 4 ^th tier 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.

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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:

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

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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”.

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Notes:

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.

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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".

Notes:

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

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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.

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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.

Notes:

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:

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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:

Notes:

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:

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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

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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.

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.

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Figures 1&2
 
 

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Eldorado-Contact Lake Area Geological Setting

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

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

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

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

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

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

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

The Labine Group, which represents the main magmatic arc in the western part of the GBMZ, consists of a 7 km thick section of volcanic-derived rocks which is exposed in the Port Radium-Echo Bay area. The Labine Group consists of the

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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).

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Figure 3

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Figure 4

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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

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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:

• Drilling

• Trenching

• Sinking shafts

• Geochemical and geophysical investigation made on the ground or by aircraft

• Surveyor claims must be proved by the surveyor general

• Work done in constructing roads and airstrips

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

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

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

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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.

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A summary of our claims can be found below:

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Figure 6

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

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.

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A summary of our claims can be found below:

Figure 8

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

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Figure 9

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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.

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A summary of our claims can be found below:

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Figure 10

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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:

We did not incur any expenditures related to the Crossfault Lake Property over the past three fiscal years.

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Figure 11

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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:

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

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Figure 12

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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:

We did not incur any expenditures related to the North Contact Lake Mineral Claims over the past three fiscal years.

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Figure 13

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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:

Figure 14

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

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.

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:

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.

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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.

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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.

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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.

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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

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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

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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.

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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.