U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934

For the fiscal year ended August 31, 2012

Commission file number: 000-53901

TITAN OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

Nevada	26-2780766
(State or Other Jurisdiction of incorporation or Organization)	(I.R.S. Employer Identification No.)

7251 West Lake Mead Boulevard, Suite 300

Las Vegas, Nevada 89128

(Address of principal executive offices)

(702) 562-4315

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

Common Stock, $0.001 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨     No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes ¨     No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   x

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

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)	Smaller Reporting Company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ¨ No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the average bid and asked price of such common equity as of February 29, 2012 was approximately $2,187,000.

The number of shares of the issuer’s common stock issued and outstanding as of November 29, 2012 was 54,227,000 shares.

Documents Incorporated By Reference:  None

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TABLE OF CONTENTS

			Page
Oil and Gas Glossary			3
PART I
	Item 1	Business	5
	Item 1A	Risk Factors	9
	Item 1B	Unresolved Staff Comments	20
	Item 2	Properties	20
	Item 3	Legal Proceedings	31
	Item 4	Mine Safety Disclosures	31
	PART II
	Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
	Item 6	Selected Financial Data	33
	Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
	Item 7A	Quantitative and Qualitative Disclosures About Market Risk.	40
	Item 8	Financial Statements and Supplementary Data.	41
	Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	65
	Item 9A	Controls and Procedures	65
	Item 9B	Other Information	66
	PART III
	Item 10	Directors, Executive Officers and Corporate Governance	67
	Item 11	Executive Compensation	69
	Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	72
	Item 13	Certain Relationships and Related Transactions, and Director Independence	73
	Item 14	Principal Accountant Fees and Services	73
	PART IV
	Item 15	Exhibits and Financial Statement Schedules	74
	SIGNATURES

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Oil and Gas Glossary

Adsorption: The accumulation of gases, liquids, or solutes on the surface of a solid or liquid.

Basin: A depressed area where sediments have accumulated during geologic time and considered to be prospective for oil and gas deposits.

Banff Formation: It is a stratigraphical unit of Lower Mississippian  age in the Western Canadian Sedimentary Basin.

Coal: A carbon-rich rock derived from plant material (peat).

Development: The phase in which a proven oil or gas field is brought into production by drilling production (development) wells.

Drilling: The using of a rig and crew for the drilling, suspension, production testing, capping, plugging and abandoning, deepening, plugging back, sidetracking, re-drilling or reconditioning of a well.

Drilling Logs: The recording of information about subsurface geologic formations, including records kept by the driller and records of mud and cutting analyses, core analysis, drill stem tests, and electric, acoustic, and radioactivity procedures.)

Exploration: The phase of operations which covers the search for oil or gas by carrying out detailed geological and geophysical surveys followed up where appropriate by exploratory drilling. Compare to "Development" phase.

Fracturing: The application of hydraulic pressure to the reservoir formation to create fractures through which oil or gas may move to the wellbore.

Mannville Formation: It is a stratigraphical unit of Cretaceous age in the Western Canadian Sedimentary Basin.

Methane: The simplest of the various hydrocarbons and is the major hydrocarbon component of natural gas, and in fact is commonly known as natural gas. It is colorless, odorless, and burns efficiently without many byproducts.

Milk River Formation: A near- shore to terrestrial sedimentary unit deposited during the Late Cretaceous period in southern Alberta.

Mineral Lease: A legal instrument executed by a mineral owner granting exclusive right to another to explore, drill, and produce oil and gas from a piece of land.

Mississippian Period: The period beginning about 359 million years ago and ending about 318 million years ago.

Nordegg:  A formation consisting of black limestone and calcareous black shales located in the subsurface.

P&NG: Petroleum and Natural Gas.

Pekisko: A stratigraphical unit of Mississippian age in the Western Canadian Sedimentary Basin.

Permeability: A measure of the ability of a rock to transmit fluid through pore spaces.

Reserves: Generally the amount of oil or gas in a particular reservoir that is available for production.

Reservoir: The underground rock formation where oil and gas has accumulated. It consists of a porous rock to hold the oil or gas, and a cap rock that prevents its escape.

Stratigraphy: A branch of geology that studies rock layers and layering (stratification). It is primarily used in the study of sedimentary and layered volcanic rocks.

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Forward-Looking Statements

This Annual Report on Form 10-K contains forward-looking information. Forward-looking information includes statements relating to future actions, prospective products, future performance or results of current or anticipated products, sales and marketing efforts, costs and expenses, interest rates, outcome of contingencies, financial condition, results of operations, liquidity, business strategies, cost savings, objectives of management of Titan Oil & Gas, Inc. (the “Company”, “Titan”, or “we”) and other matters. Forward-looking information may be included in this Annual Report on Form 10-K or may be incorporated by reference from other documents filed with the Securities and Exchange Commission (the “SEC”) by the Company. One can find many of these statements by looking for words including, for example, “believes,” “expects,” “anticipates,” “estimates” or similar expressions in this Annual Report on Form 10-K or in documents incorporated by reference in this Annual Report on Form 10-K. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information or future events.

The Company has based the forward-looking statements relating to the Company’s operations on management’s current expectations, estimates and projections about the Company and the industry in which it operates. These statements are not guarantees of future performance and involve risks, uncertainties and assumptions that we cannot predict. In particular, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, the Company’s actual results may differ materially from those contemplated by these forward-looking statements. Any differences could result from a variety of factors, including, but not limited to general economic and business conditions, competition, and other factors.

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PART I

Item 1.                      Description of Business

Corporate Developments

Titan Oil & Gas, Inc. (the “Company”) is an exploration stage company engaged in the acquisition and exploration of oil and gas properties.  In Alberta, Canada the Company has acquired the petroleum and natural gas rights to a total of approximately 2,816 hectares of land, a 2.51255% working interest in a non-producing oil well, and a 6% working interest in five producing oil wells.  The Company acquired its first producing assets in April 2011.  Previously, the Company had not realized any revenue from its oil and gas operations.

The Company was incorporated on June 5, 2008 under the name Xtrasafe, Inc. under the laws of the State of Florida to market and sell an electronic safe system, through wholesale distribution channels and directly to institutional buyers such as hospitals, colleges, universities, and assisted living facilities throughout the United States.

On February 25, 2010 the Company’s principal shareholder entered into a Stock Purchase Agreement which provided for the sale of 72,000,000 shares of common stock of the Company to Depinder Grewal.  Effective as of February 25, 2010 in connection with the share acquisition, Mr. Grewal was appointed President, Chief Executive Officer, Chief Financial Officer, Treasurer, Director, and Chairman of the Company.

On March 24, 2010, Mr. Grewal returned 36,000,000 common shares to the Company for cancellation.  Mr. Grewal returned the shares for cancellation in order to reduce the number of shares issued and outstanding. Subsequent to the cancellation, the Company had 51,600,000 shares issued and outstanding, a number that Mr. Grewal, who was at the time also a director of the Company, considered more in line with the Company’s business plans at that time.  Following the share cancellation, Mr. Grewal owned 36,000,000 common shares, or at the time 70%, of the remaining 51,600,000 issued and outstanding common shares of the Company.

Effective as of March 26, 2010 the Board of Directors of the Company elected Vivek Warrier as a director of the Company.

On April 19, 2010, Mr. Grewal, as the holder of 36,000,000 (at the time representing 67%) of the issued and outstanding shares of the Company’s common stock, provided the Company with written consent in lieu of a meeting of stockholders authorizing the Company to amend the Company’s Articles of Incorporation for the purpose of changing the name of the Company from “Xtrasafe, Inc.” to “Titan Oil & Gas, Inc.” and to change its domicile from Florida to Nevada.   In order to undertake the name and domicile change, the Company incorporated a wholly-owned subsidiary in Nevada named Titan Oil & Gas, Inc. and merged Xtrasafe, Inc. with the new subsidiary.  Subsequent to the merger, the Company continued as a Nevada company named Titan Oil & Gas, Inc.

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In connection with the change of the Company’s name to Titan Oil & Gas, Inc. the Company’s business was changed to oil and gas exploration.  The change in name, business, and domicile received its final approval by the regulatory authorities on June 30, 2010.

On July 6, 2010 the Company adopted a resolution to split the Company’s common stock.  The Board of Directors approved a 1:8 forward stock split.   The record and payment dates of the forward split were July 22 and July 23, 2010, respectively.   All of the common shares issued and outstanding on July 22, 2010 were split.   All references to share and per share amounts have been restated in this Form 10-K to reflect the split.

Effective as of August 1, 2010 the Board of Directors of the Company elected Jack Adams as a director of the Company.

On August 5, 2010 the Company completed an extra-provincial registration in Alberta and then on June 20, 2011 the Company withdrew such extra-provincial registration and incorporated a wholly-owned subsidiary, TNGS Oil & Gas, Inc. (“TNGS”) in the province of Alberta.

On January 20, 2012 the Board of Directors of the Company elected Mr. Jack Adams President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, and Treasurer of the Company and also on January 20, 2012 Mr. Jarnail Dhaddey resigned as President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director of the Registrant.

On October 2, 2012 the Board of Directors of the Company elected Mr. Michal Gnitecki President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director of the Company and on October 1, 2012, Jack Adams resigned from his positions as President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director of the Company.

Business Operations

The Company is engaged in the acquisition and exploration of oil and gas properties.  The Company acquired its first producing assets in April 2011.  Previously, the Company had not realized any revenue from its oil and gas operations.

On April 12, 2010 the Company executed a Sale and Conveyance Agreement (the “Agreement”) with 966749 Alberta Corp. (the “Vendor”) for the acquisition of a 2.51255% working interest in a non-producing oil well located in Alberta, Canada.  Under the Agreement the Company paid the Vendor $6,043 including taxes and closing costs.  The underlying property lease is with the Alberta provincial government.

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In addition, on April 12, 2010 the Company acquired an interest in two petroleum and natural gas (“P&NG”) leases (the “Saskatchewan Leases”) in the province of Saskatchewan, Canada.  Including fees and closing costs, the rights to the Saskatchewan Leases were acquired for an aggregate $9,873 and the purchase price included the first year’s aggregate annual lease payments of $372.  The total area covered by the Company’s portion of the Saskatchewan Leases is 326 acres.  The interests in the Saskatchewan Leases were acquired through a public land sale process held on a regular basis by the Saskatchewan provincial government.

On August 19, 2010 the Company acquired an interest in one P&NG lease (the “August 2010 Lease”) in the province of Alberta, Canada.  Including fees and closing costs, the rights to the August 2010 Lease were acquired for an aggregate $13,099 and the purchase price included the first year’s aggregate annual lease payments of $842.  The total area covered by the August 2010 Lease is 256 hectares.

Between September 2, 2010 and September 30, 2010 the Company entered into six additional P&NG leases (the “September 2010 Leases”) in the province of Alberta, Canada.  Including fees and closing costs, the rights to the September 2010 Leases were acquired for an aggregate $76,850 and the purchase price included the first year’s aggregate annual lease payments of $5,360.  The total area covered by the September 2010 Leases is 1,536 hectares.

On December 15, 2010 the Company acquired an interest in a P&NG lease (the “December 2010 Lease”) in the province of Alberta, Canada.  The rights to the December 2010 Lease were acquired for $9,484 and the purchase price included the first year’s annual lease payments of approximately $899.  The total area covered by the December 2010 Lease is 256 hectares.

On January 12, 2011, the Company acquired an interest in two P&NG leases (the “January 2011 Leases”) in the province of Alberta, Canada.  The rights to the January 2011 Leases were acquired for an aggregate $49,613 and the purchase price included the first year’s aggregate annual lease payments of approximately $2,724.  The total area covered by the Company’s January 2011 Leases is 768 hectares.

On April 14, 2011, the  Company began doing business in Alberta, Canada as TNGS Oil & Gas, Inc., entered into a general conveyance agreement (the “General Conveyance Agreement”) with Huron Energy Corporation (“Huron”), pursuant to which Huron conveyed to TNGS a 6% working interest in the petroleum and natural gas rights, as well as the intangible and miscellaneous interests (collectively, the “Assets”) in 800 acres of land located in the Leaman area of Alberta, Canada (the “Leaman Property”).  In consideration for the Assets, TNGS paid Huron an aggregate CDN $140,000.  Including closing costs and taxes the Leaman Property was acquired for a total of USD $148,367.  The Leaman Property consists of six oil wells, five of which are currently in production. Of the five currently in production, the Company receives revenue from four of the wells as a fifth well is currently in penalty.  The well in penalty is a result of Huron not paying its share of capital costs to the well’s operator.  Huron did not pay its share of costs as the well has had minimal production to date.  The Company does not expect to receive any future revenue from the well in penalty.

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On February 16, 2011 the Company disposed of its interest in the Saskatchewan Leases in the province of Saskatchewan, Canada.  The rights to the Saskatchewan Leases were sold to Westpoint Energy, Inc. (“Westpoint”) for total proceeds of $15,000 resulting in a gain of $4,572.  The Company sold its interests in the Saskatchewan Leases as they are located in Saskatchewan while the majority of the Company’s other assets are located in Alberta where the Company is focusing its activities.

Competition

The oil and gas exploration industry is intensely competitive, highly fragmented and subject to rapid change.  We may be unable to compete successfully with our existing competitors or with any new competitors.  We compete with many exploration companies that have significantly greater personnel, financial, managerial, and technical resources than we do.  This competition from other companies with greater resources and reputations may result in our failure to maintain or expand our business.

Government Regulation

Development, production and sale of oil and natural gas in Canada are subject to extensive laws and regulations, including environmental laws and regulations.  The oil and gas properties currently leased by the Company are owned by the Province of Alberta and are managed by the provincial Department of Energy.  Currently the Company has not been required to make large expenditures to comply with environmental and other governmental regulations as the Company is not the operator of its Leaman Property which is the Company’s only producing property.  However, in order to drill on the Company’s other properties the Company would need to obtain operator’s license, acquire appropriate insurance, and post a bond with the province of Alberta.  The costs to comply with these requirements may be substantial.  Matters subject to regulation include:

• location and density of wells;

• the handling of drilling fluids and obtaining discharge permits for drilling operations;

• accounting for and payment of royalties on production from state, federal and Indian lands;

• bonds for ownership, development and production of natural gas and oil properties;

• transportation of natural gas and oil by pipelines;

• operation of wells and reports concerning operations; and

• taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages.  Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties.  Moreover, these laws and regulations could change in ways that substantially increase our costs.  Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

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Employees

We have commenced only limited operations. Therefore, we have no full time employees. Our sole officer and three directors provide planning and organizational services for us on a part-time basis.

Subsidiaries

On August 5, 2010 the Company completed an extra-provincial registration in Alberta and then on June 20, 2011 the Company withdrew its extra-provincial registration and incorporated TNGS Oil & Gas, Inc. as a wholly-owned subsidiary in the province of Alberta.

Item 1A.                      Risk Factors

Factors that May Affect Future Results

This investment has a high degree of risk.  Before you invest you should carefully consider the risks and uncertainties described below and the other information included in this Annual Report on Form 10-K.  If any of the following risks actually occur, our business, operating results and financial condition could be harmed and the value of our stock could go down.  This means you could lose all or a part of your investment.

RISKS RELATING TO OUR COMPANY

1. Our auditors’ opinion in our August 31, 2012 financial statements includes an explanatory paragraph indicating the possibility that we may not be able to continue to operate.

We have incurred net losses of $461,886 from June 5, 2008 (inception) to August 31, 2012.  Our financial statements do not include any adjustments relating to the recoverability and classification of recorded assets, or the amounts of and classification of liabilities that might be necessary in the event the Company cannot continue in existence.  Our ability to continue as a going concern is dependent upon our generating cash flow sufficient to fund operations or we will need to raise additional capital in order to fund our future exploration and development.  Our plans to deal with this cash requirement include loans from existing shareholders, raising additional capital from the public or private sale of equity or entering into a strategic arrangement with a third party.  Any such plans may not be successful. If we cannot continue as a viable entity our shareholders will lose their entire investment in our company.

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2. We are an exploration stage company with limited operating history in oil and gas exploration focused primarily on acquiring early-stage properties and establishing our operations, which makes it difficult to evaluate our business and operations and our ability to successfully develop profitable business operations and makes an investment in our company very risky.

On June 30, 2010, we changed our name from “Xtrasafe, Inc.” to “Titan Oil & Gas, Inc.” and our domicile from Florida to Nevada.   In order to undertake the name and domicile change, the Company incorporated a wholly-owned subsidiary in Nevada named Titan Oil & Gas, Inc. and merged Xtrasafe, Inc. with and into the new subsidiary.

In connection with the name and domicile change, the Company’s business was changed to oil and gas exploration.  The Company acquired its first oil-producing assets in April 2011.  Previously, the Company had not realized any revenue from its oil and gas operations.  As a result we have only recently commenced oil and gas production and exploration activities.  To date, revenues from production have not been sufficient to fund all of our operational needs.

Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the oil and natural gas industries. We have only recently begun to generate revenues from operations.

Our future operating results will depend on many factors, including:

• our ability to raise adequate working capital;

• success of our exploration and development;

• demand for natural gas and oil;

• the level of our competition;

• our ability to attract and maintain key management and employees; and

• our ability to efficiently explore, develop and produce sufficient quantities of marketable natural gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

To achieve profitable operations, we must, alone or with others, successfully execute on the factors stated above.  If we are not successful in executing any of the above stated factors, our business will not be profitable, which make our common stock a less attractive investment.

3. The field of oil and gas exploration is difficult to predict because of technological advancements and market factors, which factors our management may not correctly assess and it may make it difficult for investors to sell their shares in our company.

Because the nature of our business is expected to change as a result of shifts in the market price of oil and natural gas, competition, and the development of new and improved technology, management forecasts are not necessarily indicative of future operations and should not be relied upon as an indication of future performance.

Management may incorrectly estimate projected occurrences and events within the timetable of our business plan, which would have an adverse effect on our results of operations and, consequently adversely affect the value of our stock.

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4. Because our current revenues are not sufficient to fund our future exploration programs we will need to raise a substantial amount of additional capital to fund our operations, develop our properties and acquire and develop new properties.  If we are unable to raise the necessary additional capital we will not be able to pursue our business activities, which would likely cause our common stock to become worthless.

The Company expects that it will need approximately $77,000 to fund its operations during the next twelve months which will include minimum annual property lease payments as well as the costs associated with maintaining an office. Current cash available is not sufficient to fund all of the Company’s planned operations for the next twelve months.  Even with our production which began in April 2011 we will require substantial additional capital to fund our operations which will include exploring the rest of our leased properties which have not had any production of oil or natural gas, as well as for the future acquisition and/or development of other properties.  Management may in the future seek to raise additional capital, from public and private equity offerings.  Our ability to access capital will depend on our success in participating in properties that are successful in exploring for and producing oil and gas at profitable prices.  It will also be dependent upon the status of the capital markets at the time such capital is sought.  Should sufficient capital not be available, or be available on favorable terms, the implementation of our business strategy would be adversely affected. In such event it would not be likely that investors would obtain a profitable return on their investments or a return of their investments at all.

5. Even if we discover unconventional tight gas on our properties, extraction can be costly. Accordingly, we will require substantial additional capital to fund our operations and should we fail to do so, we will not be able to pursue our business plan, which would likely cause our common shares to become worthless.

Currently, we are focused primarily on exploring our Southeastern Alberta properties to determine the potential for hosting natural gas in the form of unconventional tight gas.  Unconventional tight gas is stuck in very tight formations underground, trapped in unusually impermeable, hard rock, or in a sandstone or limestone formations that are unusually impermeable and non-porous (tight sand).  Even if we discover unconventional tight gas, a great deal more effort has to be put into extracting gas from a tight formation than a conventional natural gas deposit, where once drilled, the gas can usually be more readily and easily extracted..  Several techniques exist that allow natural gas to be extracted, including fracturing and acidizing, however, these techniques are very costly.  Accordingly, we will require substantial additional capital to fund our operations.  Because cash flow from our current operations is not sufficient to fund all of our operating needs, we will need to raise additional capital to fund such extraction if and when we make such gas discoveries.  Should sufficient capital not be available, we will not be able to extract such gas and the implementation of our business strategy would be adversely affected.  In such event it would not be likely that investors would obtain a profitable return on their investments or a return of their investments at all.

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6. We are heavily dependent on contracted third parties.  The inability to identify and obtain the services of third party contractors would harm our ability to execute our business plan and continue our operations until we found a suitable replacement.

We are dependent on the continued services of third party contractors whose knowledge and technical expertise is critical for future of the Company.  Our success is also heavily dependent on our ability to retain and attract experienced engineers, geoscientists and other technical and professional staff.  We do not currently have any long-term consulting agreements in place with third parties under which we can ensure that we will have sufficient expertise to undertake our planned exploration program.  If we were unable to obtain and maintain the services of third party contractors our ability to execute our business plan would be harmed and we may be forced to cease operations until such time as we could hire suitable contractors.

7. Volatility of oil and gas prices and markets, over which we have no control, could make it difficult for us to achieve profitability and investors are likely to lose their investment in our company.

Our ability to achieve profitability is dependent on prevailing prices for natural gas and oil.  The amounts of, and price obtainable for, any oil and gas production that we achieve will be affected by market factors beyond our control.  If these factors are not favorable over time to our financial interests, it is likely that owners of our common stock will lose their investments. Such factors include:

• worldwide or regional demand for energy, which is affected by economic conditions;

• the domestic and foreign supply of natural gas and oil;

• weather conditions;

• domestic and foreign governmental regulations;

• political conditions in natural gas and oil producing regions;

• the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; and

• the price and availability of other fuels.

8. The natural gas and oil business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our exploration, development, and exploitation activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas and oil well does not ensure a profit on investment.   A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical.

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The natural gas and oil business involves a variety of operating risks, including:

• fires;

• explosions;

• blow-outs and surface cratering;

• uncontrollable flows of oil, natural gas, and formation water;

• natural disasters, such as hurricanes and other adverse weather conditions;

• pipe, cement, or pipeline failures;

• casing collapses;

• embedded oil field drilling and service tools;

• abnormally pressured formations; and

• environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:

• injury or loss of life;

• severe damage to and destruction of property, natural resources and equipment;

• pollution and other environmental damage;

• clean-up responsibilities;

• regulatory investigation and penalties;

• suspension of our operations; and

• repairs to resume operations.

9. If we commence drilling, and we do not currently have any contracts with equipment providers, we may face the unavailability or high cost of drilling rigs, equipment, supplies, personnel and other services which could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans within our budget and, as a result, negatively impact our financial condition and results of operations.

If we commence drilling, shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could negatively impact our financial condition and results of operations.  Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry.  Increased drilling activity in these areas may also decrease the availability of rigs.  We do not currently have any contracts with providers of drilling rigs and, consequently we may not be able to obtain drilling rigs when we need them.  Therefore, our drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.

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10. We are subject to complex laws and regulations, including environmental regulations, which can significantly increase our costs and possibly force our operations to cease.

If we commence drilling and experience any leakage of crude oil and/or gas from the subsurface portions of a well, our gathering system could cause degradation of fresh groundwater resources, as well as surface damage, potentially resulting in suspension of operation of a well, fines and penalties from governmental agencies, expenditures for remediation of the affected resource, and liabilities to third parties for property damages and personal injuries.  In addition, any sale of residual crude oil collected as part of the drilling and recovery process could impose liability on us if the entity to which the oil was transferred fails to manage the material in accordance with applicable environmental health and safety laws.

Drilling operations generally involve a high degree of risk. Hazards such as unusual or unexpected geological formations, power outages, labor disruptions, blow-outs, sour gas leakage, fire, inability to obtain suitable or adequate machinery, equipment or labor, and other risks are involved. We may become subject to liability for pollution or hazards against which it cannot adequately insure or which it may elect not to insure. Incurring any such liability may have a material adverse effect on our financial position and operations.

Development, production and sale of natural gas and oil in Canada are subject to extensive laws and regulations, including environmental laws and regulations.  We may be required to make large expenditures to comply with environmental and other governmental regulations.  Matters subject to regulation include:

• location and density of wells;

• the handling of drilling fluids and obtaining discharge permits for drilling operations;

• accounting for and payment of royalties on production from state, federal and Indian lands;

• bonds for ownership, development and production of natural gas and oil properties;

• transportation of natural gas and oil by pipelines;

• operation of wells and reports concerning operations; and

• taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages.  Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties.  Moreover, these laws and regulations could change in ways that substantially increase our costs.  Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.

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11. The potential profitability of oil and gas ventures depends upon various factors beyond the control of our company, which may materially affect our financial performance.

The potential profitability of oil and gas properties is dependent upon many factors beyond our control.  For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project.  These changes and events may materially affect our financial performance.

12. If we do not maintain the property lease payments on our properties, we will lose our interests in the properties as well as losing all monies incurred in connection with the properties.

We have ten P&NG leases in Albert, Canada.  Our leases require annual lease payments to the Alberta provincial government as described above in the Description of Business section.  If we do not continue to make the annual lease payments, we will lose our ability to explore and develop the properties and we will not retain any kind of interest in the properties.

13. We may not be able to compete with current and potential exploration companies, some of whom have greater resources and experience than we do in locating and commercializing oil and natural gas reserves and, as a result, we may fail in our ability to maintain or expand our business.

The natural gas and oil market is intensely competitive, highly fragmented and subject to rapid change.   We compete with many exploration companies which have significantly greater personnel, financial, managerial, and technical resources than we do.  If we are unable to compete successfully with our existing competitors or with any new competitors we may not be able to develop or expand our business.

14. We expect losses to continue in the next 12 months because our oil or gas revenues are not sufficient to offset losses.

We acquired our first revenue-producing property in April 2011.  However, revenues from this property have not been sufficient to generate a profit.  We do not believe that revenues from our one producing property will generate profits in the future.  As a result, we expect to incur operating losses in next 12 months.  The operating losses will occur because there are expenses associated with the operation of oil wells.  In addition, the cost of acquiring and exploring natural gas and oil properties which do not have any income-producing reserves are significant.  Failure to generate additional revenues may cause us to go out of business.  We will require additional funds to achieve our current business strategy and our inability to obtain additional financing will interfere with our ability to expand our current business operations.

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15. Our officer and directors do not devote all of their time to our company and one of our directors works for other natural resource exploration companies, which may result in a conflict of interest,  and a slow down our operations.

Our sole officer and two directors are not required to work exclusively for us and do not devote all of their time to our operations.   Their other activities may prevent them from devoting full-time to our operations which could slow our operations and may reduce our financial results because of the slowdown in operations.  It is currently expected that each of our directors will devote only approximately one hour per week to our activities on an ongoing basis, and when required will devote more time when property visits are required or when extensive analysis of information is needed.  One of our directors works for other natural resource exploration companies.  Therefore, it is possible that a conflict of interest with regard to his time and business opportunities may arise because of his employment by such other companies which would negatively impact our operations.

16. Our principal shareholder owns a controlling interest in our voting stock and investors will not have any voice in our management, which could result in decisions adverse to our general shareholders.

Our principal shareholder beneficially owns approximately 66.4% of our outstanding common stock. As a result, this stockholder will have the ability to control substantially all matters submitted to our stockholders for approval including:

· election  of  our  board  of  directors;

· removal  of  any  of  our  directors;

· amendment  of  our  Articles of Incorporation  or  bylaws;

· significant corporate actions and the adoption of measures that could delay or prevent a change in control or impede a merger, takeover or other business combination involving us..

In addition, it is possible for our principal shareholder to sell or otherwise dispose of all or a part of his shareholdings which could affect the market price of our common stock if the marketplace does not orderly adjust to the increase in shares in the market and the value of your investment in the Company may decrease.  Furthermore, the controlling shareholder’s stock ownership may discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which in turn could reduce our stock price or prevent our stockholders from realizing a premium over our stock price.

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17. We have no employees and our only officer and two other directors each work one hour per week on our business.  Consequently, we may not be able to monitor our operations and respond to matters when they arise in a prompt or timely fashion.  Until we have additional capital or generate revenue, we will have to rely on consultants and service providers, which will increase our expenses and increase our losses.

We do not have any employees and our only officer and two other directors work on our business one hour per week.  With practically no personnel, we have a limited ability to monitor our operations, such as the progress of oil and gas exploration, and to respond to inquiries from third parties, such as regulatory authorities or potential business partners.  Though we may rely on third party service providers, such as accountants and lawyers, to address some of our matters, until we raise additional capital or generate revenue, we will have to rely on consultants and third party service providers to monitor our operations, which will increase our expenses and have a negative effect on our results of operations.

RISKS RELATING TO OUR COMMON STOCK

18. We may, in the future, issue additional common stock, which would reduce investors’ percent of ownership and may dilute our share value.

Our Articles of Incorporation authorize the issuance of 100,000,000 common shares, of which 54,227,000 shares are issued and outstanding.  The future issuance of our common stock for future services or acquisitions or other corporate actions may result in substantial dilution in the percentage of our common stock held by our then existing shareholders and may have an adverse effect on any trading market, if one is established for our common stock.

19. Our controlling shareholder may take actions that are contrary to your interests, including selling their stock.

Our controlling shareholder beneficially owns approximately 66.4% of our outstanding common stock.  If and when he is able to sell his shares in the market, such sales within a short period of time could adversely affect the market price of our common stock if the marketplace does not orderly adjust to the increase in the number of shares in the market. This will result in a decrease in the value of your investment in the Company.  This stock ownership may discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which in turn could reduce our stock price or prevent our stockholders from realizing a premium over our stock price.

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20. Our common stock is subject to the "penny stock" rules of the SEC which may make buy or selling our common stock difficult.  We have no established market for our common stock and there can be no assurance that one will ever develop or be sustained.

The SEC has adopted Rule 15g-9 which establishes the definition of a "penny stock," for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require: (i) that a broker or dealer approve a person's account for transactions in penny stocks; and (ii) the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased. In order to approve a person's account for transactions in penny stocks, the broker or dealer must: (i) obtain financial information and investment experience objectives of the person; and (ii) make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form: (i) sets forth the basis on which the broker or dealer made the suitability determination; and (ii) that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the "penny stock" rules. This may make it more difficult for investors to dispose of our common stock and cause a decline in the market value of our stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

Because we do not intend to pay any cash dividends on our shares of common stock, our stockholders will not be able to receive a return on their shares unless they sell them.

We intend to retain any future earnings to finance the development and expansion of our business. We do not anticipate paying any cash dividends on our common stock in the foreseeable future. Unless we pay dividends, our stockholders will not be able to receive a return on their shares unless they sell them at a price higher than that which they initially paid for such shares.

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21. We may be exposed to potential risks resulting from requirements under Section 404 of the Sarbanes-Oxley Act of 2002.

We are required, pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, to include in our annual report our assessment of the effectiveness of our internal control over financial reporting.  We do not have a sufficient number of employees to segregate responsibilities and may be unable to afford increasing our staff or engaging outside consultants or professionals to overcome our lack of employees.

We expect to incur significant continuing costs, including accounting fees and staffing costs, in order to maintain compliance with the internal control requirements of the Sarbanes-Oxley Act of 2002. Development of our business will necessitate ongoing changes to our internal control systems, processes and information systems. Currently, we have no employees, other than our sole officer and director. As we engage in the exploration of our mineral claim, hire employees and consultants, our current design for internal control over financial reporting will not be sufficient to enable management to determine that our internal controls are effective for any period, or on an ongoing basis. Accordingly, as we develop our business, such development and growth will necessitate changes to our internal control systems, processes and information systems, all of which will require additional costs and expenses.

In the future, if we fail to complete the annual Section 404 evaluation in a timely manner, we could be subject to regulatory scrutiny and a loss of public confidence in our internal controls. In addition, any failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations.

If we fail to establish and maintain an effective system of internal control, we may not be able to report our financial results accurately or to prevent fraud.  Any inability to report and file our financial results accurately and timely could harm our reputation and adversely impact the trading price of our common stock. As a result, our small size and any current internal control deficiencies may adversely affect our financial condition, results of operation and access to capital.

22. Because we are not subject to compliance with rules requiring the adoption of certain corporate governance measures, our stockholders have limited protections against interested director transactions, conflicts of interest and similar matters.

The Sarbanes-Oxley Act of 2002, as well as rule changes proposed and enacted by the SEC, the New York and American Stock Exchanges and the Nasdaq Stock Market, as a result of Sarbanes-Oxley, require the implementation of various measures relating to corporate governance. These measures are designed to enhance the integrity of corporate management and the securities markets and apply to securities which are listed on those exchanges or the Nasdaq Stock Market. Because we are not presently required to comply with many of the corporate governance provisions and because we chose to avoid incurring the substantial additional costs associated with such compliance any sooner than necessary, we have not yet adopted these measures.

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Because none of our directors are independent, we do not currently have independent audit or compensation committees. As a result, the directors have the ability, among other things, to determine their own level of compensation. Until we comply with such corporate governance measures, regardless of whether such compliance is required, the absence of such standards of corporate governance may leave our shareholders without protections against interested director transactions, conflicts of interest and similar matters and investors may be reluctant to provide us with funds necessary to expand our operations.

23. Because we do not intend to pay any cash dividends on our common shares, our stockholders will not be able to receive a return on their shares unless they sell them.

We intend to retain any future earnings to finance the development and expansion of our business. We do not anticipate paying any cash dividends on our common shares in the foreseeable future.  Unless we pay dividends, our stockholders will not be able to receive a return on their shares unless they sell them.

Item 1B.   Unresolved Staff Comments

There are no unresolved staff comments.

Item 2.   Description of Properties

Corporate Office

The Company does not currently have physical office space.  We currently maintain our corporate office on a shared basis at 7251 West Lake Mead Boulevard, Suite 300, Las Vegas, Nevada, 89128 pursuant to a one-year lease for monthly rent payments of $249. The lease expires March 1, 2013.  Management believes that our office space is suitable for our current needs.

Oil and Gas Property Interests

The following table lists total capitalized costs for the Company’s properties at August 31, 2012. All of the Company’s properties are located in Alberta, Canada.

	August 31, 2012 (Cumulative)
	Southeast Alberta		Alberta Well Interest		Leaman Property			Total
	(unproven)		(unproven)
Property acquisition and lease payments	$	162,292	$	6,043	$	150,964		$	319,299
Geological and geophysical (1)		93,198		1,086		4,175			98,459
Asset Retirement Obligation		-		-		27,881			27,881
Asset Write Down		-		-		(130,201	)		(130,201	)
Accumulated Depletion		-		-		(33,820	)		(33,820	)
Total expenditures	$	255,490	$	7,129		18,999			281,618

(1)   Balance includes total capitalized stock-based compensation expense of $36,443.

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Oil and Gas Property Lease Information

The Company’s Southeast Alberta Property is comprised of ten “P&NG leases with the government of the province of Alberta, Canada.  All of the interests in the leases were acquired through a public land sale process held on a regular basis by the provinces of Alberta.  Upon being notified that it has submitted the highest bid for a specific land parcel the Company immediately pays the government the bid price and enters into a formal lease with the government.  Each lease is for a 5 year term with a commencement date equal to the date of acquisition, requires minimum annual lease payments of CDN $3.50 (USD $3.55) per hectare, and grants the Company the right to explore for potential petroleum and natural gas opportunities on the respective lease.  The leases are renewable if certain conditions are met.  All leases require the payment of the first year’s minimum annual lease payments at the time of acquisition.  The P&NG leases are subject to royalties payable to the Alberta provincial government.  The royalty is calculated using a revenue-less-cost formula.  In years prior to the recovery of the project’s capital investment, the royalty is 1% of gross revenue.  Once the project costs have been recovered, the royalty is the greater of 1% of gross revenue or 25% of net revenue.

The province of Alberta can sell oil or gas rights separately and can sell the rights to different geological formations which can occur at different depths at different times.  As a result, there are producing gas wells on several sections of the Company’s Southeast Alberta Property but the Company does not have the rights to the gas from these wells as the Company has acquired different rights from the province.  The data from the gas well are available to the public so the Company may make use of this data when assessing its properties.  However, the existence of a producing gas well on any one of the Company’s properties does not mean that gas or oil exists within the land rights held by the Company.

Unconventional Tight Gas Sands Background

Canada has large deposits of natural gas in rock formations that are especially difficult and expensive to produce. The gas in these difficult-to-produce formations is often referred to as “unconventional”. Most commonly, the formations are low permeability, or “tight” sandstones and limestones, coal seams, organic shales, or interbedded combinations of these formations.

Unconventional gas is found in virtually all Canadian sedimentary basins with the gas resource estimated at over 60 trillion cubic metres, according to the Alberta Utilities Commission. Over the last several decades, new technologies have allowed it to be commercially developed.  According to the Alberta Utilities Commission, between 20% and 30% of Canada's current natural gas production is unconventional and unconventional gas accounts for over 40% of gas production in the United States.

Significant tight gas production occurs in shallow gas plays in Alberta, and the deep basin of Alberta.  Over the years there has been significant success in accessing natural gas locked in these tight gas reservoirs primarily through the application of horizontal drilling technology.  As conventional sandstones and limestones continue to decline in production, we believe that these tight formations will become increasingly important as industry currently shows a high level of interest in this play.

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Leaman Property

Acquisition of Interest

On April 14, 2011 the Company doing business in Alberta, Canada as TNGS Oil & Gas, Inc.  entered into the General Conveyance Agreement with Huron, pursuant to which Huron conveyed to the Company a 6% working interest in the Assets in 800 acres of land located in the Leaman Property.  Under the General and Conveyance Agreement, the Company began receiving its share of oil and gas revenue effective April 1, 2011. In consideration for the Assets, the Company paid Huron an aggregate CDN $140,000.  Including closing costs and taxes the Leaman Property was acquired for a total of USD $148,367.  The Leaman Property consists of six oil wells with five currently in production. Of the five currently in production, the Company receives revenue form four of the wells as a fifth well is currently in penalty.  The one well in penalty is a result of Huron not paying its share of capital costs to the well’s operator.  Huron did not pay its share of costs as the well has had minimal production to date.  The Company does not expect to receive any future revenue from the well in penalty.

Description and Location of the Leaman Property

The Leaman Property consists of a 6% non-operated working interest in 800 acres of land in the Leaman area of Alberta, Canada.  The Leaman Property is located 80 miles northwest of Edmonton.  The Company’s rights include P&NG rights from the base of Nordegg to the Base of the Pekisko.

The following is a list of the lands acquired as part of the Leaman Property acquisition:

Lands	Company Interest	Lease No.	Expiry	Encumbrances	Wells
T57 R9W5: 31 P&NG below base Nordegg to base Pekisko	6.00%	0599070341	Continued	Crown Royalty	6-31-57-9W5 02/6-31-57-9W5 (1) 7-31-57-9W5 10-31-57-9W5 11-31-57-9W5 (1) 02/12-31-57-9W5
T58 R10W5: SE 1 P&NG below base Nordegg to base Pekisko	6.00%	0599030221	Continued	Crown Royalty

(1)   Company’s interest in the 02/6-31-57-9W5 and 11-31-57-9W5 wells is:

0% BPPO and 6.00% APPO

Facilities

Water Disposal Pipeline, Metering Equipment and facilities from 8-36-57-10W5 to 16-35-57-10W5 disposal well

3% working interest

16-35-57-10W5 disposal well

6% working interest

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The wells on the Leaman Property are operated by Petrobakken Energy Ltd. (‘Petrobakken”).  The Company sells the oil it receives from the Leaman Property directly to a third party and pays Petrobakken on a monthly basis for the well operating costs.  Gas production has been minimal since the acquisition of Leaman by the Company

Reserves and Resources

GLJ Petroleum Consultants of Calgary, Alberta, Canada have prepared a reserve report on the Leaman Property as of August 31, 2012. The following is a summary of the reported results adjusted for the period ended August 31, 2012.  All of the Company’s reserves are from the Leaman Property which is located in Alberta, Canada.

	Summary of Reserves
	August 31, 2012
	Proved Producing		Proved Plus Probable Producing
MARKETABLE RESERVES
Heavy Oil (Mbbl)
Gross Lease		64.0		76.0
Total Company Interest		3.0		3.6
Net After Royalty		2.9		3.4
Gas (MMcf)
Gross Lease		8.4		9.8
Total Company Interest		0.3		0.4
Net After Royalty		0.3		0.4
Oil Equivalent (Mbbl)
Gross Lease		65.4		77.6
Total Company Interest		3.1		3.7
Net After Royalty		3.0		3.5

The Company does not have any proved or probable undeveloped properties nor does it have any possible developed or undeveloped properties.

A copy of the amended report has been attached to this Form 10-K as exhibit 99.1.

The following table shows the Company’s share of oil production in aggregate for the year ended August 31, 2012 and for the period from acquisition on April 1, 2011 to August 31, 2011.  Gas production received by the Company has been negligible to date.

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Year Ended August 31, 2012

Production (1)		Sales Price (2)		Operating Costs (3)
(bbls)		($/bbl)		($/bbl)
	1,050		69		62

1.   Production is the Company’s 6% working interest in Leaman Wells.

2.   Average selling price is calculated based on aggregate gross sales proceeds of $72,444 for the year ended August 31, 2012 divided by barrels of oil sold.

3.   Average operating cost is calculated based on aggregate operating costs of $65,597 for the year ended August 31, 2012 divided by barrels of oil produced.

Period from April 1, 2011 to August 31, 2011

Production (4)		Sales Price (5)		Operating Costs (6)
(bbls)		($/bbl)		($/bbl)
	401		86		63

4.   Production is the Company’s 6% working interest in Leaman Wells.

5.   Average selling price is calculated based on aggregate gross sales proceeds of $34,593 for the period from April 1, 2011 to August 31, 2011 divided by barrels of oil sold.

6.   Average operating cost is calculated based on aggregate operating costs of $25,414 for the period from April 1, 2011 to August 31, 2011 divided by barrels of oil produced.

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Southeast Alberta Properties

Map of the Southeast Alberta Properties.  Red circles indicate the location of the Company’s interests.

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Acquisition of Interests

On August 19, 2010 the Company acquired an interest in the August 2010 Lease.  Including fees and closing costs the rights to the August 2010 Lease were acquired for an aggregate $13,099 and the purchase price included the first year’s aggregate annual lease payments of $842.  The total area covered by the August 2010 Lease is 256 hectares.

Between September 2, 2010 and September 30, 2010 the Company entered into the September 2010 Leases.  Including fees and closing costs the rights to the September 2010 Leases were acquired for an aggregate $76,850 and the purchase price included the first year’s aggregate annual lease payments of $5,360.  The total area covered by the September 2010 Leases is 1,536 hectares.

On December 15, 2010 the Company acquired an interest in the December 2010 Lease).  The rights to the December 2010 Lease were acquired for $9,484 and the purchase price included the first year’s annual lease payments of approximately $899.  The total area covered by the December 2010 Lease is 256 hectares.

On January 12, 2011, the Company acquired an interest in the January 2011 Leases.  The rights to the January 2011 Leases were acquired for an aggregate of $49,613 and the purchase price included the first year’s aggregate annual lease payments of approximately $2,724.  The total area covered by the Company’s January 2011 Leases is 768 hectares.

Description and Location of the Southeast Alberta Properties

The Company has acquired the following leases:

Date	Location	Number of Leases	Land Area (Hectares)	Annual Lease Payments
August 19, 2010	Retlaw	1	256	CDN $896 / USD $909
September 2, 2010	Bow Island	1	256	CDN $896 / USD $909
September 2, 2010	Eyremore	1	256	CDN $896 / USD $909
September 2, 2010	Eyremore	1	256	CDN $896 / USD $909
September 16, 2010	Atlee Buffalo	1	256	CDN $896 / USD $909
September 30, 2010	Taber	1	256	CDN $896 / USD $909
September  30,2010	Bow Island	1	256	CDN $896 / USD $909
December 15, 2010	Cessford	1	256	CDN $896 / USD $909
January 12, 2011	Suffield	1	256	CDN $896 / USD $909
January 12, 2011	Suffield	1	512	CDN $1,792 / USD $1,818
		10	2,816	CDN $9,856 / USD $9,999

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Regional Geology

Alberta contains vast amounts of coal distributed throughout the southern plains, foothills, and mountains.  Originally deposited in relatively flat-lying peat swamps, organic matter (peat) was buried by sediments derived from uplift (mountain building), in the west and gradually changed into coal with increasing heat and pressure of burial.  Over time, the coals were uplifted and partially eroded away, resulting in the present distribution of coal across the plains.  Coal-bearing strata dip gently westward toward the mountains where coals are folded and abruptly turn toward the surface to be exposed in the foothills.

Coal typically occurs within a coal zone as discrete seams and/or packages with several thin and thick seams interbedded with non-coaly rock layers or beds.  A coal zone may be traceable over a large geographic area.  Coal zones are found in strata ranging in age from Late Jurassic (approximately 145 million years old) to Tertiary (approximately 65 million years old).

The oldest and deepest coals of the Alberta plains belong to the Lower Cretaceous Mannville Group coals.  The Mannville coals are widely distributed across the Alberta plains, are thick, continuous and contain some of the highest gas contents of any coals in the Alberta plains.  Typically six or more seams with cumulative coal thickness ranging from 2 to 14 meters occur over a stratigraphic interval of 40 to 100 meters.  The thickest coals extend from southeast Grande Prairie in a widening wedge between Edmonton and Calgary to the Coronation area with coals occurring at depths ranging from about 800 meters to 2800 meters.

Upper Cretaceous through Tertiary-aged coal also occurs across the plains with older coals being overlain by progressively younger rocks and coals.  Three coal zones are recognized within the Upper Cretaceous Belly River Group located in Alberta:  the McKay Coal Zone, near the base of the Belly River Group; the Taber Coal Zone, located in the middle; and the Lethbridge Coal Zone, at the top of the Belly River Group.  Compared to the Mannville coals, the overall thin coals and restricted lateral continuity of the Belly River Group coal seams have resulted in limited exploration efforts in these coals.

The rank of coal in Alberta ranges from very low (lignite) to high (anthracite).  Coal near the surface in the plains is generally of sub-bituminous rank with lignite occurring in the north and northeast part of the plains, and high volatile bituminous C in the northwest and southwest areas of the plains.  Coal rank increases with burial depth.  In the plains, coal rank increases towards the west as seams dip and become progressively deeper toward the mountains.  With increasing depth also comes increasing overburden pressure, which may restrict permeability.

To date, coals with relatively low gas contents, but with favorable fracturing are being exploited for unconventional production in the south-central plains.  Mannville coals are showing potentially favorable amounts of fracturing and high gas contents in some locations and are undergoing evaluation in the north central to central plains.

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Exploration History and Geology of the Southeast Alberta Properties

Atlee- Buffalo

The Atlee-Buffalo land parcel is located in Section 6, Township 23, Range 8 West of the 4th Meridian and is approximately sixty miles north of Medicine Hat, Alberta, Canada. The land contains one abandoned well 6-6-23-8W4 which was drilled and the rig released on 1989-08-27 with total depth (TD) to the Banff formation of the Mississippian age. Shallow Milk River stringers run from 1090 to 1340 feet in depth. The Company owns all P&NG rights and there has been no production to date. The offset wells at 16-36-22-9W4 and 6-31-22-8W4 are producing from the Milk River formation at a current rate of 10 to15 and 25 to 30 mcf/d (thousand cubic feet per day) respectively. Regionally, production in the area has been from the Belly River, Colorado, Medicine Hat, and Second White Specks zones.  This land parcel does not contain any assigned reserves or resources and the Company has not had any production from this land parcel.

Bow Island

The two Bow Island land parcels are located in Sections 23 and 25 both in Township 10, Range 10 West of the 4th Meridian and are approximately twenty miles southwest of Medicine Hat, Alberta, Canada. Section 23 contains one abandoned well while no wells have been drilled on section 25. The Company owns all P&NG rights and there has been no production from the lands to date. The abandoned well 7-23-10-10W4 was drilled and rig released on 1990-01-25 with TD in the Madison horizon.

The Bow Island formation, at 2486 to 2493 feet and from 2630 to 2650 feet, was identified as having potential production. The formation has been damaged and will require fracturing.

Regionally, production in the area has been from the Milk River, Medicine Hat and Second White Specks in the vicinity of the Company lands and as these are generally blanket sands and may  be considered for future development. New drilling in the region has been to the Sawtooth formation. These land parcels do not contain any assigned reserves or resources and the Company has not had any production from these land parcels.

Eyremore

The two Eyremore land parcels are located in Sections 20 and 21 in Township 18 Range 17 West of the 4th Meridian and are approximately forty-eight miles north of Lethbridge, Alberta, Canada. The two land parcels contain a total of eight producing gas wells which are producing from above the base of the Mannville formation. These eight wells are not Company gas wells as the lands acquired by the Company contain P&NG rights below the base of the Mannville.  All new wells that have their productive formation identified are producing from zones that are above the base of the Mannville. These land parcels do not contain any assigned reserves or resources and the Company has not had any production from these land parcels.

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Retlaw

The Retlaw land parcel is located in Section 9 Township 14 Range 18 West of the 4th Meridian and is approximately thirty miles northeast of Lethbridge, Alberta, Canada. The Company acquired P&NG rights below the base of the Mannville. The section contains one abandoned and one producing gas well however neither well penetrates to the zones acquired. Regionally, production has been from the Mannville, Belly River, Arcs, Nisku, and Glaucautic zones. This land parcel does not contain any assigned reserves or resources and the Company has not had any production from this land parcel.

Taber

The Taber land parcel is located in Section 22 Township 9 Range 16 West of the 4th Meridian and is located approximately thirty miles east of Lethbridge, Alberta, Canada. The land has one abandoned well 5-22-9-16W4 which was drilled and rig released on 1942-11-22. The existing logs are too old to be useful. The Company owns all P&NG rights. Regionally, newly drilled wells are located in a major Mannville field to the west of the Company land and have had production from the Mannville and Sawtooth formations. This land parcel does not contain any assigned reserves or resources and the Company has not had any production from this land parcel.

Cessford

The Cessford land parcel is located in Section 30, Township 22, Range 11, West of the 4th Meridian and is approximately sixty-five miles north north-west of Medicine Hat. The land contains nine gas wells and one abandoned well.    These nine wells are not Company gas wells as the Company owns all P&NG rights below the base of the Medicine Hat sandstone excepting NG in the Basal Colorado and the Blairmore. Section 30 production is from the Medicine Hat and the Milk River which the Company has no P&NG rights. The surrounding gas producers have no Cardium, Bakken or Glauconite production.  This land parcel does not contain any assigned reserves or resources and the Company has not had any production from this land parcel.

Suffield

The two Suffield land parcels are located in Township 17 Range 8 and Township 18 Range 5 respectively, both West of the 4th Meridian. The Company holds P&NG rights below the base of the Second White Specs. The land parcels and the surrounding lands have production from the Medicine Hat, Milk River and Second White Specs. The Company has no P&NG rights in any of these formations. There appears to be no area evidence of Cardium, Bakken, Viking or Glauconite production.  The land contains fifteen gas wells and one abandoned well but these fifteen wells are not Company gas wells as the rights to the gas are held by third parties.  These land parcels do not contain any assigned reserves or resources and the Company has not had any production from these land parcels.

29

Current State of Exploration

The Company has not undertaken any drilling on its Southeast Alberta properties.  There are abandoned wells on such properties drilled by former property owners.  In addition, there are producing gas wells but all production from these wells is owned by other companies as the production is from zones whose rights have been leased by other enterprises.  Drill log information from wells drilled on adjacent properties is publicly available. The Company is currently reviewing these data.

Geological Exploration Program

The Province of Alberta maintains a significant publicly-available database of drilling information from all wells drilled under leases issued by the provincial government.  Companies who drill on government land in Alberta are required to submit their drill results to the province.  Therefore, previous drilling undertaken on land adjacent to the Company’s holding, or drilling on the Company’s land by companies exploring for other resources (oil sands for example) are required to submit their drill log data to the Alberta government.  As a result, there is a large database of drill results available to the public.  The Company has only recently begun its initial review of the publicly available data to determine the potential of its properties for exploration.  The Company intends to undertake a more comprehensive review of this drill log data from surrounding properties in order to gain a better understanding of the exploration potential of its properties.  The Company does not currently have agreements in place with qualified geologists who can undertake this review.

The review of the data will include preparing detailed geological maps using existing drill log data with the aim of identifying potential drill targets and to obtain a better understanding of potential strategies for acquiring new land holdings.  The Company will not undertake any drilling in 2012, as the on-going review of available information will take between twelve to eighteen months to complete once the work commences.  Therefore, the Company is not expecting to undertake any drilling until at least 2013.

Alberta Well Interest

Acquisition of Interest

On April 12, 2010 the Company executed the Sale and Conveyance Agreement with the Vendor for the acquisition of a 2.51255% working interest in an oil well located in Alberta, Canada.  Under the Agreement the Company paid the Vendor $6,043 including taxes and closing costs.  The underlying property lease is with the Alberta provincial government.

Description and Location of the Alberta Well Interest

The underlying lease with the Alberta government is Crown Lease 0587090167 and is located at Township 49, Range 15 W5M: 7 with the well known as Apex et al Peco 100/06-07-049-15W5/00 (the “Well”).  The Well is located approximately 30 miles from Edson, Alberta, Canada.

30

Exploration History of the Alberta Well Interest

The Well was initially drilled in 1998 and re-entered by Apex Energy (Canada) Inc. (”Apex”) in November 2003.  To date there has been only minimal production from the Well and currently the Well is not in production. Beatton Energy Inc. (“Beatton”) is the current operator of the Well.

Current State of Exploration

To date there has been only minimal production from the Well and currently the Well is not in production.

Geological Exploration Program

Beatton is currently assessing the potential for future development of the Well.

Item 3.   Legal Proceedings

There are no pending legal proceedings to which the Company is a party or in which any director, officer or affiliate of the Company, any owner of record or beneficially of more than 5% of any class of voting securities of the Company, or security holder is a party adverse to the Company or has a material interest adverse to the Company.  The Company’s properties are not the subject of any pending legal proceedings.

Item 4.   Mine Safety Disclosures

The Company currently has no mining operations.

31

PART II

Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Market Information

Our common stock has been quoted on the Over The Counter Bulletin Board (“OTCBB”) under the symbol “TNGS.OB.” since July 27, 2010. Prior to July 27, 2010 there was no active market for our common stock. The following table sets forth the high and low closing bid prices of our common stock as quoted on the OTCBB.

Financial Quarter		Bid Price Information*
Year	Quarter	High Bid Price	Low Bid Price
2012	Fourth Quarter	$0.08	$0.02
	Third Quarter	$0.14	$0.04
	Second Quarter	$0.15	$0.07
	First Quarter	$0.245	$0.10
2011	Fourth Quarter	$0.42	$0.11
	Third Quarter	$1.54	$0.35
	Second Quarter	$2.905	$0.70
	First Quarter	$1.00	$0.10

*The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.

Holders

On November 23, 2012, there were approximately thirty-three holders of record of the Company’s common stock.

Dividends

The Company has not declared or paid any cash dividends on its common stock nor does it anticipate paying any dividends in the foreseeable future. Rather, the Company expects to retain any future earnings to finance its operations and expansion.

32

Securities Authorized for Issuance under Equity Compensation Plans

As of August 31, 2012, securities issued and securities available for future issuance under our 2010 Stock Option Plan were as follows:

Equity Compensation Plan Information
Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance
Equity compensation plans approved by security holders
Equity compensation plans not approved by security holders	5,000,000		$0.59	4,200,000

On August 3, 2010, the Company adopted its 2010 Stock Option Plan (the “2010 Plan”).  The 2010 Plan provides for the grant of stock options to key employees, directors and consultants, of common shares of the Company.  5,000,000 shares of common stock are reserved for issuance under the 2010 Plan. Under the 2010 Plan, the grant of stock options, the exercise prices, and the option terms are to be determined by the Company's Board of Directors For incentive options, the exercise price shall not be less than the fair market value of the Company's common stock on the grant date. (In the case of options granted to an employee who owns stock possessing more than 10% of the voting power of all classes of the Company's stock on the date of grant, the option price must not be less than 110% of the fair market value of common stock on the grant date.).  The term of options granted under the 2010 Plan may not exceed five years.

Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

None

Purchases of Equity Securities by the Company and Affiliated Purchasers

None

Item 6.   Selected Financial Data

A smaller reporting company, as defined by Item 10 of Regulation S-K, is not required to provide the information required by this item.

33

Item 7.   Management’s Discussion and Analysis or Plan of Operation

Overview

The Company is engaged in the acquisition and exploration of oil and gas properties.  The Company acquired its first producing assets in April 2011.  Previously, the Company had not realized any revenue from its oil and gas operations.

Plan of Operation

The Company’s current objective for the next twelve months is to continue to explore the properties subject to its P&NG leases.

The Company's ability to continue as a going concern is dependent on its ability to develop its oil and gas properties and ultimately achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations as they become payable.  Even with production form its Leaman Property the Company expects that losses will continue in the future until additional producing assets can either be developed or acquired.  The Company expects that it will need approximately $77,000 to fund its operations during the next twelve months which will include minimum annual property lease payments as well as the costs associated with maintaining an office. Current cash available is not sufficient to fund all of the Company’s operations for the next twelve months. Management may in the future seek additional capital through equity or debt offerings.  There are no assurances that management’s plans will be realized or that additional financing will be available or available on terms favorable to us.

We continue to run our operations with the use of contract operators, and as such do not currently anticipate a change to our company’s staffing levels. We remain focused on keeping management, which currently consists of our three directors and one officer, at a minimum to conserve capital. We believe that outsourcing of necessary operations continues to be the most cost effective and efficient manner for us to presently conduct business.

We do not currently anticipate any equipment purchases in the twelve months ending August 31, 2013.

Results of Operations

The Year Ended August 31, 2012 compared to the Year Ended August 31, 2011

Revenues

The Company recognized $72,444 in revenue for the year ended August 31, 2012 compared to $34,593 for the year ended August 31, 2011.  The Company acquired its first oil-producing assets in April 2011 when it acquired the Leaman Property.  The Company’s share of production for the year ended August 31, 2012 was approximately 1,047 barrels of oil compared to approximately 401 barrels of oil for the year ended August 31, 2011.

Prior to April 2011the Company had not realized any revenue from its oil and gas properties.

34

Expenses

For the year ended August 31, 2012 our net loss was $246,690 compared to $139,644 for the year ended August 31, 2011.  The Company acquired its first oil-producing assets in April 2011 when it acquired the Leaman Property.  Many of the Company’s expenses have increased in the current year as a result of the Company having a full year of production in 2012 compared to a partial year of production in 2011.  Due to 2012 being a full year of production compared to a partial period in 2011, operating expenses increased to $65,597 in 2012 from $25,414 in 2011.  In addition, depletion and accretion increased to $31,334 for the year ended August 31, 2012 from $8,429 for the year ended August 31, 2011.  During the year ended August 31, 2012 the Company wrote-down its Leaman Property by $130,201 as a result of a reduction in the Company’s reserves pursuant to the Company’s updated reserve report.  The reduction in reserves was the result of less favourable price and economic estimates in 2012 compared to 2011.

For the year ended August 31, 2012 the Company recognized a reversal of non-capitalized stock-based compensation expense of $8,040 compared to the recognition of an additional stock-based compensation of $61,375 for the year ended August 31, 2011.  The lower stock-based compensation expense in 2012 was due to stock options granted in previous periods being revalued during the current period when the Company’s share price was lower.  Professional fees have increased to $36,303 for the year ended August 31, 2012 compared $27,905 for the year ended August 31, 2011.  The increase was largely due to extra costs associated with tax planning related to the Company’s TNGS subsidiary and due to additional regulatory filing requirements.  General and administrative expenses were $35,239 and $28,686 in 2012 and 2011 respectively.  The increase in the current year was due to higher office and regulatory and filing fees. Total compensation paid to management and directors was $28,500 in 2012 compared to $27,000 in 2011.

Other Income (Expense)

During the fiscal year ended August 31, 2011 the Company disposed of its interest in two Petroleum and Natural Gas Leases in the province of Saskatchewan.  The rights to the Saskatchewan Leases were sold to Westpoint for total proceeds of $15,000 resulting in a gain of $4,572.  The Company sold its interests in the Saskatchewan Leases as they are located in Saskatchewan while the majority of the Company’s other assets are located in Alberta where the Company is focusing its activities.  No such activities occurred in 2012.

Liquidity and capital resources

We had a cash balance of $61,289 and working capital of $63,900 as of August 31, 2012. We anticipate that we will incur the following expenses over the next twelve months:

·   $62,000 for operating expenses, including working capital and general, legal, accounting and administrative expenses associated with reporting requirements under the Securities Exchange Act of 1934.

·   $15,000 for annual minimum lease payments and on-going assessment of our Alberta properties.

35

Net cash used in operating activities during the year ended August 31, 2012 was $93,282 compared to $113,612 during the year ended August 31, 2011.  The Company used less cash in operations in 2012 compared to 2011 despite an increase in the net loss to $246,690 in the year ended August 31, 2012 from $139,644 for the year ended August 31, 2011.  The primary reason for this effect was that $130,201 of the loss in the current year was a non-cash write-down of the Leaman property.  Additionally, two other non-cash items impacted the amount of cash used in operations.  Depletion and accretion for the year ended August 31, 2012 was $31,334 in 2012 compared to $8,429 in 2011.  Also, stock-based compensation for the year ended August 31, 2012 was a reversal of expense of $8,040 compared to an additional expense of $61,375 in the prior year.   Working capital changes for the year ended August 31, 2012 consisted of an inflow of $20,113 from the collection of accounts receivable, an outflow of $3,880 from an increase in prepaid expenses, and an outflow of $16,320 from the payment of accounts payable.  For the year ended August 31, 2011 working capital changes were the result of an outflow of $31,235 from an increase in accounts receivable, an outflow of $6,735 from an increase in prepaid expenses, and an outflow of $1,230 from a decrease in accounts payable and accrued liabilities.

Cash flows from investing activities for the year ended August 31, 2012 consisted of the acquisition of oil and gas property interests of $41,048 while there were no financing activities in 2012.  Cash flows from financing activities in 2011 consisted of $550,500 received from the sale of common stock while investing activities consisted primarily of $341,970 related to the acquisition of oil and gas property interests and $15,000 received from the disposal of the Saskatchewan Leases.

Going Concern Consideration

The Company’s financial statements have been prepared in US dollars and in accordance with accounting principles generally accepted in the United States on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business.   During the fiscal year ended August 31, 2012, the Company incurred a net loss of $246,690.   Since inception on June 5, 2008 the Company has an accumulated deficit of $461,886 to August 31, 2012.   These conditions raise substantial doubt about the Company's ability to continue as a going concern.

The Company's ability to continue as a going concern is dependent on its ability to develop its oil and gas properties and ultimately achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations as they become payable.  Even with production from its Leaman Property it is expected that losses will continue in the future until additional producing assets can either be developed or acquired by the Company.   Accordingly, no adjustment relating to the recoverability and classification of recorded asset amounts and the classification of liabilities has been made to the accompanying financial statements in anticipation of the Company not being able to continue as a going concern.

36

Critical Accounting Policies

The preparation of financial statements, in conformity with generally accepted accounting principles in the United States of America, requires companies to establish accounting policies and to make estimates that affect both the amount and timing of the recording of assets, liabilities, revenues and expenses. Some of these estimates require judgments about matters that are inherently uncertain and therefore actual results may differ from those estimates.

A detailed summary of all of the Company’s significant accountings policies and the estimates derived therefrom is included in Note 3 to the Company’s Consolidated Financial Statements for the year ended August 31, 2012. While all of the significant accounting policies are important to the Company’s consolidated financial statements, the following accounting policies and the estimates derived therefrom have been identified as being critical:

Oil and Gas Property Payments and Exploration Costs;

Revenue Recognition;

Impairment of Long-lived Assets;

Income taxes;

Stock-based compensation;

Foreign currency translation; and

Asset retirement obligations.

Oil and Gas Property Payments and Exploration Costs

The Company follows the full cost method of accounting for natural gas and oil operations.  Under the full cost method all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis. The Company’s current cost center is located in Canada. Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.  The Company has adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The percentage of total reserve volumes produced during the year is multiplied by the net capitalized investment plus future estimated development costs in those reserves.  Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

37

Under full cost accounting rules, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the ceiling) equal to the sum of:  (i) the after tax present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on currents costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; (ii) the cost of properties not being amortized; and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized.  If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs.  Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling.

Revenue recognition

Revenue from the production of crude oil and natural gas is recognized when title passes to the customer and when collection of the revenue is reasonably assured.  The Company currently earns revenue from its 6% working interest it has in four producing wells in Alberta, Canada.  The Company does not operate the wells but does currently market and sell its proportion of oil and gas produced from the wells.  The customers take title when the crude oil is transferred to their pipeline.

Impairment of Long-lived Assets

In accordance with ASC 360, Property, Plant and Equipment, long lived assets such as equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.  Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount of fair value less costs to sell, and are no longer depreciated.  The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes whereby deferred tax assets and liabilities are recognized for the future tax consequences of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  If it is determined that the realization of the future tax benefit is not more likely than not, the enterprise establishes a valuation allowance.

38

Stock-Based Compensation

Under ASC 718, Compensation-Stock Compensation, the Company is required to record compensation expense, based on the fair value of the awards, for all awards granted after the date of adoption and for the unvested portion of previously granted awards that remain outstanding as at the date of adoption.

The Company grants stock options to non-employees for services that include researching land availability, lease acquisitions, geological consulting and geophysical services including interpretation of seismic data.  These options are accounted for under ASC 505 (EITF 96-18) and were measured at the fair value of the options as determined by an option pricing model on the measurement date and recognized as the related services are provided and the options earned.

Compensation expense for unvested options to non-employees is revalued at each period end and is being amortized over the vesting period of the options.

Foreign Currency Translation

The Company has oil and gas property interests in Canada and as a result incurs some transactions in Canadian dollars.  The Company translates its Canadian dollar balances to US dollars in the following manner:  assets and liabilities have been translated using the rate of exchange at the balance sheet date.  The Company’s results of operations have been translated using average rates.

All amounts included in the accompanying financial statements and footnotes are stated in U.S. dollars.

Asset Retirement Obligations

In accordance with ASC 410, Asset Retirement and Environmental Obligations the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company has not yet undertaken any field exploration on its properties and as such has not yet incurred an asset retirement obligation.  At least annually, the Company will reassess the need to record an obligation or determine whether a change in any estimated obligation is necessary. The Company will evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation has materially changed the Company will accordingly update its assessment. The asset retirement obligation is measured at fair value on a non-recurring basis using level 3 inputs based on discounted cash flows involving estimates, assumptions, and judgments regarding the cost, timing of settlement, credit-adjusted risk-free rate and inflation rates.

Off-balance sheet arrangements

We have no off-balance sheet arrangements.

39

Recent Accounting Pronouncements

Goodwill Impairment

In September 2011, ASC guidance was issued related to goodwill impairment. Under the updated guidance, an entity will have the option to first assess qualitatively whether it is necessary to perform the current two-step goodwill impairment test. If the Company believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. The update is effective for the Company’s fiscal year beginning June 1, 2012 with early adoption permitted. The Company does not expect the updated guidance to have an impact its financial position, results of operations or cash flows.

Comprehensive Income

In June 2011, ASC guidance was issued related to comprehensive income. Under the updated guidance, an entity will have the option to present the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In addition, the update required certain disclosure requirements when reporting other comprehensive income. The update does not change the items reported in other comprehensive income or when an item of other comprehensive income must be reclassified to income. Subsequently, in December 2011, the FASB issued its final standard to defer the new requirement to present components of reclassifications of other comprehensive income on the face of the income statement. Companies will still be required to adopt the other requirements contained in the new standard on comprehensive income. The adoption of this guidance is not expected to have an impact on the Company’s financial position, results of operations or cash flows.

Fair Value Accounting

In May 2011, ASC guidance was issued related to disclosures around fair value accounting. The updated guidance clarifies different components of fair value accounting including the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity’s shareholders’ equity and disclosing quantitative information about the unobservable inputs used in fair value measurements that are categorized in Level 3 of the fair value hierarchy. The update is effective for the Company’s fiscal year beginning June 1, 2012. The Company does not expect the updated guidance to have a significant impact on its financial position, results of operations or cash flows.

Item 7A   Quantitative and Qualitative Disclosure About Market Risk

A smaller reporting company, as defined by Item 10 of Regulation S-K, is not required to provide the information required by this item.

40

Item 8.                         Financial Statements

TITAN OIL & GAS, INC.

(An Exploration Stage Company)

-:-

August 31, 2012 and 2011

41

Contents		Page
Report of Independent Registered Public Accountants		F - 1
Balance Sheets
	August 31, 2012 and 2011	F - 2
Statements of Operations for the
	Years Ended August 31, 2012 and 2011 and the Cumulative Period
	from June 5, 2008 (inception) to August 31, 2012	F - 3
Statement of Stockholders’ Equity
	Since June 5, 2008 (inception) to August 31, 2012	F - 4
Statements of Cash Flows for the
	Years Ended August 31, 2012 and 2011 and the Cumulative Period
	from June 5, 2008 (inception) to August 31, 2012	F – 6
Notes to Financial Statements		F - 8

42

ROBISON, HILL & CO.	Certified Public Accountants
A PROFESSIONAL CORPORATION
	DAVID O. SEAL, CPA
	W. DALE WESTENSKOW, CPA
	BARRY D. LOVELESS, CPA
	STEPHEN M. HALLEY, CPA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTANTS

Titan Oil & Gas, Inc.

(An Exploration Stage Company)

We have audited the accompanying balance sheets of Titan Oil & Gas, Inc. (an exploration stage company) as of August 31, 2012 and 2011, and the related statements of operations, and cash flows for the years ended August 31, 2012 and 2011, and the cumulative since June 5, 2008 (inception) to August 31, 2012, and the statement of stockholder’s equity since June 5, 2008 (inception) to August 31, 2012.  These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting.  Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting.  Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Titan Oil & Gas, Inc. (an exploration stage company) as of August 31, 2012 and 2011, and the results of its operations and its cash flows for the years ended August 31, 2012 and 2011, and the cumulative since June 5, 2008 (inception) to August 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has incurred net losses of approximately $461,886, which raise substantial doubt about its ability to continue as a going concern.  Management’s plans in regard to these matters are also described in Note 2.  The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

_/s/ Robison, Hill & Co.____

Certified Public Accountants

Salt Lake City, Utah

November 29, 2012

F - 1

TITAN OIL & GAS, INC.

(An Exploration Stage Company)

CONSOLIDATED BALANCE SHEETS

	August 31,			August 31,
	2012			2011
ASSETS
Current Assets
Cash	$	61,289		$	195,619
Accounts Receivable		11,122			31,235
Prepaid expenses		11,934			8,054
Total Current Assets		84,345			234,908
Oil and Gas Property Interests, Net (Note 4)		281,618			417,280
Total Assets	$	365,963		$	652,188
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts Payable and Accrued Liabilities	$	20,445		$	38,369
Total Current Liabilities		20,445			38,369
Long Term Liabilities
Asset Retirement Obligations (Note 5)		8,626			2,796
Total Long Term Liabilities		8,626			2,796
Total Liabilities		29,071			41,165
STOCKHOLDERS’ EQUITY
Common Stock, Par Value $.001
Authorized 100,000,000 shares,
Issued 54,227,000 shares at
August 31, 2012 (August 31, 2011 – 54,227,000)		54,227			54,227
Paid-In Capital		744,551			771,992
Deficit Accumulated Since Inception of Exploration Stage		(461,886	)		(215,196	)
Total Stockholders’ Equity		336,892			611,023
Total Liabilities and Stockholders’ Equity	$	365,963		$	652,188

The accompanying notes are an integral part of these financial statements.

F - 2

TITAN OIL & GAS, INC.

(An Exploration Stage Company)

CONSOLIDATED STATEMENTS OF OPERATIONS

							Cumulative
							Since
							June 5, 2008
	For the Year Ended						(Inception) to
	August 31,						August 31,
	2012			2011			2012
Revenues
Oil and Gas Revenue	$	72,444		$	34,593		$	107,037
Expenses
Operating Expenses		65,597			25,414			91,011
Depletion and Accretion		31,334			8,429			39,763
Write-down of oil and gas property interests (Note 4)		130,201			-			130,201
Professional Expenses		36,303			27,905			107,858
General and Administrative		35,239			28,686			92,827
Management Fees		19,500			15,000			34,500
Stock-based Compensation		(8,040	)		61,375			53,335
Directors’ Fees		9,000			12,000			24,000
Total Expenses		319,134			178,809			573,495
Net Loss from Operations		(246,690	)		(144,216	)		(466,458	)
Other Income (Expenses)
Gain on Sales of Assets (Note 4)		-			4,572			4,572
Net Other Income (Expense)		-			4,572			4,572
Net Loss	$	(246,690	)	$	(139,644	)	$	(461,886	)
Basic and Diluted loss per
Share	$	(0.00	)	$	(0.00	)
Weighted Average Shares
Outstanding		54,227,000			54,126,247

The accompanying notes are an integral part of these financial statements.

F - 3

TITAN OIL & GAS, INC.

(An Exploration Stage Company)

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)

										Deficit
										Accumulated
										During
	Common Stock						Paid-In			Exploration
	Shares(1)			Par Value			Capital			Stage			Total
Balance at June 5, 2008
(inception)		—		$	—		$	—		$	—		$	—
Common Stock Issued to Founder
at $0.000125 per share, August     13, 2008		72,000,000			72,000			(63,000	)		—			9,000
Net Loss		—			—			—			(120	)		(120	)
Balance at August 31, 2008		72,000,000			72,000			(63,000	)		(120	)		8,880
Common Stock Issued for Cash
at $0.00125 per share, February 27, 2009		15,600,000			15,600			3,900			—			19,500
Net Loss		—			—			—			(18,144	)		(18,144	)
Balance at August 31, 2009		87,600,000			87,600			(59,100	)		(18,264	)		10,236
Share Cancellation on March 24, 2010		(36,000,000	)		(36,000	)		36,000			—			—
Common Stock Issued  at $0.025
per share,  April 12, 2010		2,000,000			2,000			48,000			—			50,000
Common Stock Issued  at $0.50 per
share, August 18, 2010		160,000			160			79,840			—			80,000
August 2010, Compensation
from the Issuance of Stock
Options at Fair Market Value		—			—			14,756			—			14,756
Net Loss		—			—			—			(57,288	)		(57,288	)
Balance August 31, 2010		53,760,000		$	53,760		$	119,496		$	(75,552	)	$	97,704
(Balance Carried Forward)

F - 4

TITAN OIL & GAS, INC. (An Exploration Stage Company) CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT) (Continued)
								Deficit
								Accumulated
								During
	Common Stock				Paid-In			Exploration
	Shares(1)		Par Value		Capital			Stage			Total
Balance August 31, 2010		53,760,000	$	53,760	$	119,496		$	(75,552	)	$	97,704
(Balance Carried Forward)
Common Stock Issued  at $0.025
per share,  September 10, 2010		200,000		200		49,800			—			50,000
Common Stock Issued  at $1.50 per
share, January 31, 2011		67,000		67		100,433			—			100,500
Common stock issued at $2.00 per
Share, January 10, 2011		200,000		200		399,800			—			400,000
August 2011, Compensation
from the Issuance of Stock
Options at Fair Market Value		—		—		102,463			—			102,463
Net Loss		—		—		—			(139,644	)		(139,644	)
Balance August 31, 2011		54,227,000	$	54,227	$	771,992		$	(215,196	)	$	611,023
August 2012, Compensation
from the Issuance of Stock
Options at Fair Market Value		—		—		(27,441	)		—			(27,441	)
Net Loss		—		—		—			(246,690	)		(246,690	)
Balance August 31, 2012		54,227,000	$	54,227	$	744,551			(461,886	)	$	336,892

(1)   Reflects the 8:1 forward stock split completed on July 23, 2010.  See Note 7.

The accompanying notes are an integral part of these financial statements.

F - 5

TITAN OIL & GAS, INC.

(An Exploration Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS

							Cumulative
							Since
							June 5, 2008
	For the Year Ended						(Inception) to
	August 31,			August 31,			August 31,
	2012			2011			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net Loss	$	(246,690	)	$	(139,644	)	$	(461,886	)
Adjustments to Reconcile Net Loss to Net
Cash Used in Operating Activities
Depletion and Accretion Expense		31,334			8,429			39,763
Write-down of Oil and Gas Property Interests		130,201			-			130,201
Compensation Expense of Stock Options		(8,040	)		61,375			53,335
Gain on Sale of Assets		-			(4,572)			(4,572	)
Change in Operating Assets and Liabilities
(Increase) Decrease in Accounts Receivable		20,113			(31,235)			(11,122	)
(Increase) Decrease in Prepaid Expenses		(3,880)			(6,735	)		(11,934	)
Increase (Decrease) in Accounts Payable and Accrued Liabilities		(16,320	)		(1,230)			20,445
Net Cash Used in Operating Activities		(93,282	)		(113,612)			(245,770	)
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of Oil and Gas Property Interests		(41,048	)		(341,970	)		(416,941	)
Proceeds from Disposal of Oil and Gas Interest		-			15,000			15,000
Net Cash Used in Investing Activities		(41,048	)		(326,970	)		(401,941	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Sale of Common Stock		-			550,500			709,000
Net Cash Provided by Financing Activities		-			550,500			709,000
Net (Decrease) Increase in
Cash and Cash Equivalents		(134,330	)		109,918			61,289
Cash and Cash Equivalents
at Beginning of Period		195,619			85,701			—
Cash and Cash Equivalents
at End of Period	$	61,289		$	195,619		$	61,289

The accompanying notes are an integral part of these financial statements.

F - 6

TITAN OIL & GAS, INC.

(An Exploration Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Continued)

					Cumulative
					Since
					June 5, 2008
	For the Year Ended				(Inception) to
	August 31,		August 31,		August 31,
	2012		2011		2012
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for:
Interest	$	—	$	—	$	—
Income taxes	$	—	$	—	$	—
SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Accounts payable related to oil and gas property interests	$	—	$	22,428	$	22,428
Long Term Liabilities-Asset Retirement
Obligation	$	—	$	2,684	$	2,684

In previous years, the Company has granted stock options under its stock option plan.  A portion of the stock options granted relates to geological consulting and as a result a portion of the expense has been capitalized to oil and gas property interests.  The vesting period for some of these options is up to three years.  As a result, the unvested portion of the options has been revalued at August 31, 2012 resulting in a reversal of stock-based compensation expense of $(19,401) (2011- $41,088 in additional expense being capitalized) being capitalized to oil and gas property interests and a reversal of $(8,040) (2011- $61,375 in additional expense) being expensed.

The accompanying notes are an integral part of these financial statements.

F - 7

NOTE 1 – NATURE OF BUSINESS AND OPERATIONS AND BASIS OF PRESENTATION

Titan Oil & Gas, Inc. (an exploration stage company) was incorporated in the state of Florida on June 5, 2008 under the laws of the State of Florida to market and sell an electronic safe system, through wholesale distribution channels and directly to institutional buyers such as hospitals, colleges, universities, and assisted living facilities throughout the United States.

On February 25, 2010 the Company’s principal shareholder entered into a stock purchase agreement which provided for the sale of 72,000,000 shares of common stock of the Company to David Grewal. Effective as of February 25, 2010 in connection with the share acquisition, Mr. Grewal was appointed President, Chief Executive Officer, Chief Financial Officer, Treasurer, Director, and Chairman of the Company.

On March 24, 2010, Mr. Grewal, the owner of 72,000,000 shares of common stock of the Company returned 36,000,000 common shares to the Company for cancellation.  Mr. Grewal returned the shares for cancellation in order to reduce the number of shares issued and outstanding.  Subsequent to the cancellation, the Company had 51,600,000 shares issued and outstanding, a number that Mr. Grewal, who was also a director of the Company, considered more in line with the Company’s business plans at that time.

On April 19, 2010, Mr. Grewal, as the holder of 36,000,000 (at the time representing 67%) of the issued and outstanding shares of the Company’s common stock, provided the Company with written consent in lieu of a meeting of stockholders authorizing the Company to amend the Company’s Articles of Incorporation for the purpose of changing the name of the Company from “Xtrasafe, Inc.” to “Titan Oil & Gas, Inc.” and to change its domicile from Florida to Nevada.   In order to undertake the name and domicile change, the Company incorporated a wholly-owned subsidiary in Nevada named Titan Oil & Gas, Inc. and merged Xtrasafe, Inc. with the new subsidiary.  Subsequent to the merger, the Company continued as a Nevada company named Titan Oil & Gas, Inc.

In connection with the change of the Company’s name to Titan Oil & Gas, Inc. the Company’s business was changed to oil and gas exploration.  The change in name, business, and domicile received its final approval by the regulatory authorities on June 30, 2010.

On June 20, 2011 the Company incorporated a wholly-owned subsidiary in the province of Alberta Canada named TNGS Oil & Gas, Inc. (“TNGS”).  The accompanying consolidated financial statements include the balances of TNGS.

Nature of Operations

The Company currently has a 6% working interest in four producing oil wells located in Alberta, Canada.  The remaining of the Company’s oil and gas assets are not in production and do not contain any assigned resources or reserves.  In Alberta, Canada the Company has acquired the petroleum and natural gas rights to a total of approximately 2,816 hectares of land and has acquired a 2.51255% working interest in a non-producing oil well. In addition, the Company has acquired a 6% working interest in four producing oil wells as of August 31, 2012.

NOTE 2 – ABILITY TO CONTINUE AS A GOING CONCERN

The accompanying financial statements have been prepared in US dollars and in accordance with accounting principles generally accepted in the United States (GAAP) on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and commitments in the normal course of business.  The Company acquired its first producing assets in April 2011.  Previously, the Company had not realized any revenue from its oil and gas operations.  During the year ended August 31, 2012, the Company incurred a net loss of $246,690.   Since inception on June 5, 2008 the Company has an accumulated deficit of $461,886 to August 31, 2012.   These conditions raise substantial doubt about the Company's ability to continue as a going concern.

F - 8

The Company's ability to continue as a going concern is dependent on its ability to develop its oil and gas properties and ultimately achieve profitable operations and to generate sufficient cash flow from financing and operations to meet its obligations as they become payable.  Even with production from its Leaman assets it is expected that losses will continue in the future until additional producing assets can either be developed or acquired by the Company.  The Company expects that it will need approximately $77,000 to fund its operations during the next twelve months which will include minimum annual property lease payments as well as the costs associated with maintaining an office. Current cash available is not sufficient to fund all of the Company’s operations for the next twelve months.  Management may seek additional capital through a private placement or public offering of its common stock.  Although there are no assurances that management’s plans will be realized, management believes that the Company will be able to continue operations in the future.  Accordingly, no adjustment relating to the recoverability and classification of recorded asset amounts and the classification of liabilities has been made to the accompanying financial statements in anticipation of the Company not being able to continue as a going concern.

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management’s Estimates and Assumptions

The preparation of financial statements in conformity with generally accepted accounting principles requires the Company’s management to make estimates and assumptions that affect the amounts reported in these financial statements and notes. Significant areas requiring the use of estimates relate to accrued liabilities, stock-based compensation, asset retirement obligations, and the impairment of long-lived assets.  Management believes the estimates utilized in preparing these financial statements are reasonable and prudent and are based on management’s best knowledge of current events and actions the Company may undertake in the future. Actual results could differ from those estimates.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Company considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents to the extent the funds are not being held for investment purposes. At August 31, 2012, $0 (2011 - $3,751) of cash was held in trust with the Company’s land broker for the purpose of future oil and gas lease rental payments.  This cash can be returned to the Company upon request without penalty and as a result the full balance has been included in cash at August 31, 2012 and 2011.

Foreign Currency

The Company has oil and gas property interests in Canada and as a result incurs some transactions in Canadian dollars.  The Company translates its Canadian dollar balances to US dollars in the following manner:  assets and liabilities have been translated using the rate of exchange at the balance sheet date.  The Company’s results of operations have been translated using average rates.

All amounts included in the accompanying financial statements and footnotes are stated in U.S. dollars.

Concentration of Credit Risk

The Company has no off-balance-sheet concentrations of credit risk such as foreign exchange contracts, options contracts or other foreign hedging arrangements. The Company maintains all of its cash balances with two financial institutions in the form of demand deposits.

Loss per Share

Net income (loss) per share is computed by dividing the net income by the weighted average number of shares outstanding during the period. As of August 31, 2012, the company has outstanding common stock options of 800,000.  The effects of the Company’s common stock equivalents are anti-dilutive for August 31, 2012 and 2011 and are thus not presented.

F - 9

Comprehensive Income

The Company has adopted ASC 220 (formerly SFAS No. 130, “Reporting Comprehensive Income”), which establishes standards for reporting and display of comprehensive income, its components and accumulated balances. The Company has disclosed this information on its Statement of Operations. Comprehensive income is comprised of net income (loss) and all changes to capital deficit except those resulting from investments by owners and distribution to owners.

Stock Options

Under ASC 718, Compensation-Stock Compensation, the Company is required to record compensation expense, based on the fair value of the awards, for all awards granted after the date of adoption and for the unvested portion of previously granted awards that remain outstanding as at the date of adoption.

The Company grants stock options to non-employees for services that include researching land availability, lease acquisitions, geological consulting and geophysical services including interpretation of seismic data.  These options are accounted for under ASC 505 (EITF 96-18) and were measured at the fair value of the options as determined by an option pricing model on the measurement date and recognized as the related services are provided and the options earned.

Compensation expense for unvested options to non-employees is revalued at each period end and is being amortized over the vesting period of the options.

Oil and Gas Property Payments and Exploration Costs

The Company follows the full cost method of accounting for natural gas and oil operations.  Under the full cost method all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis. The Company’s current cost center is located in Canada. Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.  The Company has adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The accounting standards update revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The percentage of total reserve volumes produced during the year is multiplied by the net capitalized investment plus future estimated development costs in those reserves.  Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Under full cost accounting rules, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the ceiling) equal to the sum of:  (i) the after tax present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on currents costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; (ii) the cost of properties not being amortized; and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized.  If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the ceiling, the excess shall be charged to expense and separately disclosed during the period in which the excess occurs.  Amounts thus required to be written off shall not be reinstated for any subsequent increase in the cost center ceiling.

F - 10

Impairment of Long-lived Assets

In accordance with ASC 360, Property, Plant and Equipment, long lived assets such as equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset.  If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.  Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount of fair value less costs to sell, and are no longer depreciated.  The assets and liabilities of a disposed group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.

Asset Retirement Obligations

In accordance with ASC 410, Asset Retirement and Environmental Obligations the fair value of an asset retirement cost, and corresponding liability, should be recorded as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. The Company has not yet undertaken any field exploration on its properties and as such has not yet incurred an asset retirement obligation.  At least annually, the Company will reassess the need to record an obligation or determine whether a change in any estimated obligation is necessary. The Company will evaluate whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed. Should those indicators suggest the estimated obligation has materially changed the Company will accordingly update its assessment. The asset retirement obligation is measured at fair value on a non-recurring basis using level 3 inputs based on discounted cash flows involving estimates, assumptions, and judgments regarding the cost, timing of settlement, credit-adjusted risk-free rate and inflation rates.

Revenue recognition

Revenue from the production of crude oil and natural gas is recognized when title passes to the customer and when collection of the revenue is reasonably assured.  The Company currently earns revenue from its 6% working interest it has in four producing wells in Alberta, Canada.  The Company does not operate the wells but does currently market and sell its proportion of oil and gas produced from the wells.  The customers take title when the crude oil is transferred to their pipeline.

Income Taxes

The Company follows the asset and liability method of accounting for income taxes whereby deferred tax assets and liabilities are recognized for the future tax consequences of differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases.  If it is determined that the realization of the future tax benefit is not more likely than not, the enterprise establishes a valuation allowance.

Uncertain Tax Positions

The Company adopted the provisions of ASC 740-10-50, formerly FIN 48, Accounting for Uncertainty in Income Taxes. The Company had no material unrecognized income tax assets or liabilities for the years ended August 31, 2012 or August 31, 2011. The Company’s policy regarding income tax interest and penalties is to expense those items as general and administrative expense but to identify them for tax purposes. During the year ended April 30, 2012 and 2011, there were no income tax, or related interest and penalty items in the income statement, or liability on the balance sheet. The Company files income tax returns in the U.S. federal jurisdiction and Florida State.  Tax years 2008 to present remain open to income tax examination.  The Company is not currently involved in any income tax examinations.

F - 11

Fair Value of Financial Instruments

The book values of cash, prepaid expenses, and accounts payable approximate their respective fair values due to the short-term nature of these instruments. The fair value hierarchy under GAAP distinguishes between assumptions based on market data (observable inputs) and an entity’s own assumptions (unobservable inputs). The hierarchy consists of three levels:

• Level one — Quoted market prices in active markets for identical assets or liabilities;

• Level two — Inputs other than level one inputs that are either directly or indirectly observable; and

• Level three — Unobservable inputs developed using estimates and assumptions, which are developed by the reporting entity and reflect those assumptions that a market participant would use.

Determining which category an asset or liability falls within the hierarchy requires significant judgment. We evaluate our hierarchy disclosures each quarter.

New Accounting Pronouncements

Goodwill Impairment

In September 2011, ASC guidance was issued related to goodwill impairment. Under the updated guidance, an entity will have the option to first assess qualitatively whether it is necessary to perform the current two-step goodwill impairment test. If the Company believes, as a result of its qualitative assessment, that it is more-likely-than-not that the fair value of a reporting unit is less than its carrying amount, the quantitative impairment test is required. Otherwise, no further testing is required. The update is effective for the Company’s fiscal year beginning June 1, 2012 with early adoption permitted. The Company does not expect the updated guidance to have an impact its financial position, results of operations or cash flows.

Comprehensive Income

In June 2011, ASC guidance was issued related to comprehensive income. Under the updated guidance, an entity will have the option to present the total of comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In addition, the update required certain disclosure requirements when reporting other comprehensive income. The update does not change the items reported in other comprehensive income or when an item of other comprehensive income must be reclassified to income. Subsequently, in December 2011, the FASB issued its final standard to defer the new requirement to present components of reclassifications of other comprehensive income on the face of the income statement. Companies will still be required to adopt the other requirements contained in the new standard on comprehensive income. The adoption of this guidance is not expected to have an impact on the Company’s financial position, results of operations or cash flows.

Fair Value Accounting

In May 2011, ASC guidance was issued related to disclosures around fair value accounting. The updated guidance clarifies different components of fair value accounting including the application of the highest and best use and valuation premise concepts, measuring the fair value of an instrument classified in a reporting entity’s shareholders’ equity and disclosing quantitative information about the unobservable inputs used in fair value measurements that are categorized in Level 3 of the fair value hierarchy. The update is effective for the Company’s fiscal year beginning June 1, 2012. The Company does not expect the updated guidance to have a significant impact on its financial position, results of operations or cash flows.

F - 12

NOTE 4 – OIL AND GAS PROPERTY INTERESTS

	August 31, 2012 (Cumulative)
	Southeast Alberta		Alberta Well Interest		Leaman Property			Total
	(unproven)		(unproven)
Property acquisition and lease payments	$	162,292	$	6,043	$	150,964		$	319,299
Geological and geophysical (1)		93,198		1,086		4,175			98,459
Asset Retirement Obligation		-		-		27,881			27,881
Asset Write Down		-		-		(130,201	)		(130,201	)
Accumulated Depletion		-		-		(33,820	)		(33,820	)
Total expenditures	$	255,490	$	7,129		18,999			281,618

(1)   Balance includes total capitalized stock-based compensation expense of $36,443.

Leaman Property

On April 14, 2011, the company entered into a general conveyance agreement (the “General Conveyance Agreement”) with Huron Energy Corporation (“Huron”), pursuant to which Huron conveyed to the Company a 6% working interest in the petroleum and natural gas rights, as well as the intangible and miscellaneous interests, (collectively, the “Assets”) in 800 acres of land located in the Leaman area of Alberta, Canada (the “Leaman”).  In consideration for the Assets, the Company paid Huron an aggregate CDN $140,000.  Including closing costs and taxes the Leaman was acquired for a total of USD $148,367.  The Leaman consists of six oil wells with five currently in production. Of the five currently in production, the Company receives revenue form four of the wells as a fifth well is currently in penalty.  The one well in penalty is a result of Huron not paying its share of capital costs to the well’s operator.  Huron did not pay its share of costs as the well has had minimal production to date.  The Company does not expect to receive revenue from the well in penalty.  The Company has registered to do business in the province of Alberta under the name TNGS Oil & Gas, Inc. (“TNGS”).  The General Conveyance Agreement has been executed through the Company’s TNGS registration.

The Company received an updated reserve report as of August 31, 2012.  As a result of lower economic and price estimates used in the reserve report, the Company’s reserves have decreased in the current year compared to the prior year.  As a result of the decrease in reserves the Company has recognized a write-down of its Leaman property in the amount of $130,201 in the Consolidated Statement of Operations for the year ended August 31, 2012.

Southeast Alberta Property

On August 19, 2010 the Company acquired an interest in one Petroleum and Natural Gas (“P&NG) Lease (the “August 2010 Lease”) in the province of Alberta, Canada.  Including fees and closing costs the rights to the August 2010 Lease were acquired for an aggregate $13,099 and the purchase price includes the first year’s aggregate annual lease payments of $842.  The total area covered by the August 2010 Lease is 256 hectares.

Between September 2 and September 30, 2010 the Company entered into six additional P&NG Leases (the “September 2010 Leases”) in the province of Alberta, Canada.  Including fees and closing costs the rights to the September 2010 Leases were acquired for an aggregate $76,850 and the purchase price includes the first year’s aggregate annual lease payments of $5,360.  The total area covered by the September 2010 Leases is 1,536 hectares.

On December 15, 2010 the Company acquired an interest in a P&NG Lease (the “December 2010 Lease”) in the province of Alberta, Canada.  The rights to the December 2010 Lease were acquired for $9,484 and the purchase price includes the first year’s annual lease payments of approximately $899.  The total area covered by the December 2010 Lease is 256 hectares.

F - 13

On January 12, 2011, the Company acquired an interest in two PN&G Leases (the “January 2011 Leases”) in the province of Alberta, Canada.  The rights to the January 2011 Leases were acquired for an aggregate $49,613 and the purchase price includes the first year’s aggregate annual lease payments of approximately $2,724.  The total area covered by the Company’s January 2011 Leases is 768 hectares.

All of the leases comprising the Southeast Alberta Property were acquired through public land sales held on a regular basis by the Alberta provincial government.  Upon being notified that it has submitted the highest bid for a specific land parcel the Company immediately pays the government the bid price and enters into a formal lease with the government.  Each of the leases are for an initial five year term, requires minimum annual lease payments, and grants the Company the right to explore for potential petroleum and natural gas opportunities on the respective lease.

All of the Company’s leases are subject to royalties payable to the government of Alberta.  The royalty is calculated using a revenue-less-cost formula.  In years prior to the recovery of the project’s capital investment, the royalty is 1% of gross revenue.  Once the project costs have been recovered, the royalty is the greater of 1% of gross revenue or 25% of net revenue.

Alberta Well Interest

On April 12, 2010 the Company executed a Sale and Conveyance Agreement (the “Agreement”) with 966749 Alberta Corp. (the “Vendor”) for the acquisition of a 2.51255% working interest in an oil well located in Alberta, Canada.  Under the Agreement the Company paid the Vendor $6,043 including taxes and closing costs.  The underlying property lease is with the Alberta provincial government.

Depletion Expense

The Company has received a reserve report on its Leaman property as of August 31, 2012.  Based on the report prepared by GLJ Petroleum Consultants of Calgary, Alberta, Canada, the Company’s portion of estimated proved plus probable producing resources and reserves, on an after royalty basis, is 3,500 recoverable barrels equivalent of oil. As a result $25,503 (2011 - $8,317) has been recorded as depletion expense at August 31, 2012. The actual recoverable number of barrels may differ materially from this estimate.

NOTE 5 – ASSET RETIREMENT OBLIGATION

As at August 31, 2012 the Company’s asset retirement obligation was comprised of its 6% working interest in the Leaman property.  The Company has estimated its obligation at August 31, 2012 as $8,626 which includes an aggregate $5,942 in accretion expense.

NOTE 6 - RELATED PARTY TRANSACTIONS

On October 2, 2012 Michal Gnitecki was appointed President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director of the Company.  He did not receive any compensation for the fiscal years ended August 31, 2012 or 2011.  Effective with his appointment he will be paid $750 per month to serve as an officer and director of the Company.

For the period from March 1, 2012 to August 31, 2012 the Company’s paid its most recent former principal executive officer $750 a month to serve as an officer of the Company.  Prior to March 31, 2012 our most recent former principal executive officer served as a director only and received $500 per month.  Our most recent former principal executive officer was paid a total of $7,500 (2011- $6,000) for the year ended August 31, 2012.  In addition, the Company pays its other director $500 per month to serve on its Board of Directors. The payments are made quarterly in advance.  The total amount paid to the Company’s other director for the year ended August 31, 2012 was $6,000 (2011 - $6,000).

Prior to his resignation, the Company’s other former principal executive officer received $15,000 (2011 - $15,000) in management fees for the year ended August 31, 2012.

F - 14

NOTE 7 – SHARE CAPITAL

Common Share Transactions

On August 13, 2008, the Company issued 72,000,000 common shares at $0.000125 per share to its founder for total proceeds of $9,000.

On February 27, 2009 the Company issued 15,600,000 common shares at$0.00125 per share for total proceeds of $19,500.

On March 24, 2010, the Company’s controlling shareholder, Mr. Grewal returned 36,000,000 common shares to the Company for cancellation.  Mr. Grewal returned the shares for cancellation in order to reduce the number of shares issued and outstanding. Subsequent to the cancellation, the Company had 51,600,000 shares issued and outstanding; a number that Mr. Grewal, who is also a director of the Company, considered more in line with the Company’s business plans at that time.

On April 12, 2010 the Company closed a private placement of 2,000,000 common shares at $0.025 per share for a total offering price of $50,000.

On August 18, 2010 the Company closed a private placement of 160,000 common shares at $0.50 per share for a total offering price of $80,000.

On September 10, 2010 the Company closed a private placement of 200,000 common shares at $0.25 per share for a total offering price of $50,000.

On January 3, 2011 the Company closed a private placement of 67,000 common shares at $1.50 per share for a total offering price of $100,500.

On January 10, 2011 the Company closed a private placement of 200,000 common shares at $2.00 per share for a total offering price of $400,000.

Stock Splits

On April 19, 2010 the Company received a written consent in lieu of a meeting of stockholders (the “Written Consent”) from the holder of 36,000,000 (at the time representing 67%) of the issued and outstanding shares of our common stock.  The Written Consent adoptedthe resolution to change the Company’s name to Titan Oil & Gas, Inc.  In connection with the name change the Written Consent also adopted a resolution to split the Company’s common stock.  The Board of Directors subsequently approved an 8:1 forward stock split.  The record and payment dates of the forward split were July 22 and July 23, 2010 respectively.   All of the common shares issued and outstanding on July 22, 2010 were split.   All references to share and per share amounts have been restated in these financial statements to reflect the split.

Stock Options

On August 3, 2010 the Company adopted its 2010 Stock Option Plan (“the 2010 Plan”).  The 2010 Plan provides for the granting of up to 5,000,000 stock options to key employees, directors and consultants, of common shares of the Company.  Under the 2010 Plan, the granting of stock options, the exercise prices, and the option terms are determined by the Company's Option Committee, a committee designated to administer the 2010 Plan by the Board of Directors.  For incentive options, the exercise price shall not be less than the fair market value of the Company's common stock on the grant date. (In the case of options granted to an employee who owns stock possessing more than 10% of the voting power of all classes of the Company's stock on the date of grant, the option price must not be less than 110% of the fair market value of common stock on the grant date.).  Options granted are not to exceed terms beyond five years.

In order to exercise an option granted under the Plan, the optionee must pay the full exercise price of the shares being purchased. Payment may be made either: (i) in cash; or (ii) at the discretion of the Committee, by delivering shares of common stock already owned by the optionee that have a fair market value equal to the applicable exercise price; or (iii) with the approval of the Committee, with monies borrowed from us.

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Subject to the foregoing, the Committee has broad discretion to describe the terms and conditions applicable to options granted under the Plan. The Committee may at any time discontinue granting options under the Plan or otherwise suspend, amend or terminate the Plan and may, with the consent of an optionee, make such modification of the terms and conditions of such optionee’s option as the Committee shall deem advisable.

For the year ended August 31, 2012 no stock options were granted while 250,000 were granted in the year ended August 31, 2011.  For stock options granted in prior years, the Black-Scholes option pricing model was used to calculate to estimate the fair value of the options at the grant date. The following assumptions were made:

	2011	2010
Risk Free Rate	0.17%	0.19%
Expected Life of Option	5 years	5 years
Expected Volatility of Stock (Based on Historical Volatility)	115.6%	92.6%
Expected Dividend yield of Stock	0.00	0.00

Expected volatilities are based on industry comparables using available data and other factors due to the fact the Company’s business changed substantially from the previous electronic safe business to oil and gas exploration in 2010. When applicable, the Company will use historical data to estimate option exercise, forfeiture and employees termination within the valuation model. For non-employees, the expected term of the options approximates the full term of the options

Total stock-based compensation expense of a reversal of expense of $(27,441) (2011 - $102,463 in additional expense) was recognized for the year ended August 31, 2012 with $(19,401) (2011 - $41,088) being capitalized to oil and gas property interests and $(8,040) (2011 - $61,375) being expensed. The stock-based compensation expense for the year ended August 31, 2012 relates to revaluing the unvested stock options granted in prior years as the prior year grants have vesting periods of up to four years.

The following table sets forth the options outstanding under the 2010 Plan as of August 31, 2012:

	Available for Grant	Options Outstanding	Weighted Average Exercise Price
Balance, August 31, 2010	4,450,000	550,000	$   0.26
Options granted	(250,000)	250,000	$   1.30
Balance, August 31, 2012 and 2011	4,200,000	800,000	$   0.59

The following table summarizes information concerning outstanding and exercisable common stock options under the 2010 Plan at August 31, 2012:

Exercise Prices	Options Outstanding	Remaining Contractual Life (in years)	Weighted Average Exercise Price	Number of Options Currently Exercisable	Weighted Average Exercise Price
$ 0.26	550,000	2.92	$ 0.26	300,000	$ 0.26
$ 1.30	250,000	3.29	$1.30	150,000	$1.30
	800,000			450,000

The aggregate intrinsic value of stock options outstanding at August 31, 2012 was $0 (2011 - $0) and the aggregate intrinsic value of stock options exercisable at August 31, 2012 was also $0 (2011 - $0).  No stock options were exercised in 2012 or 2011.  As of August 31, 2012 there was $322 in unrecognized compensation expense that will be recognized over two years.

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A summary of status of the Company’s unvested stock options as of August 31, 2012 under all plans is presented below:

	Number of Options	Weighted Average Exercise Price	Weighted Average Grant Date Fair Value
Unvested at August 31, 2010	475,000	$      0.26	$     0.18
Granted	250,000	$      1.30	$     0.97
Vested	(175,000)	$      0.56	$     0.47
Unvested at August 31, 2011	550,000	$      0.64	$     0.47
Vested	(200,000)	$      0.78	$     0.58
Unvested at August 31, 2012	350,000	$      0.56	$    0.41

NOTE 8 - INCOME TAXES

Deferred tax assets of the Company are as follows:

	2012			2011
Non-capital losses carried forward		94,700			52,300
Less: valuation allowance		(94,700	)		(52,300	)
Deferred tax asset recognized		-			-

A valuation allowance has been recorded to reduce the net benefit recorded in the financial statements related to these deferred tax assets. The valuation allowance is deemed necessary as a result of the uncertainty associated with the ultimate realization of these deferred tax assets.

The provision for income tax differs from the amount computed by applying statutory federal income tax rate of 34% (2011 – 34%) to the net loss for the year.  The sources and effects of the tax differences are as follows:

	2012			2011
Computed expected tax benefit		84,000			47,500
Temporary differences		(44,300	)		-
Permanent differences		2,700			(20,900	)
Change in valuation allowance		(42,400	)		(26,600	)
Income tax provision		-			-

As of August 31, 2012, the Company had a net operating loss carryforward for income tax reporting purposes of approximately $278,400 (2011 - $153,900) which expire between 2028 and 2032.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

As at August 31, 2012 the Company has entered into a total of ten P&NG leases with the Alberta provincial government (Note 4).  Each lease is for a period of five years and has an annual minimum lease payment of CDN $3.50 (USD $3.55) per hectare.  The first year’s minimum annual lease payment is included in the initial purchase price.  Therefore, the commitments at August 31, 2012 are for the balance of the respective lease term.

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Total annual minimum lease payments are as follows:

Contractual Obligations	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years
Annual P&NG Lease Payments:
Southeast Alberta Property Lease	$	29,088	$	9,999	$	19,089		-
Office Lease Obligation	$	1,494	$	1,494		-		-
Total	$	30,582	$	11,493	$	19,089		-

Commencing March 1, 2012 the Company renewed its one-year lease for its office space at $249 per month.  It is expected that the Company will renew the lease for another year when the current lease expires.

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

In December 2008, the United States Securities and Exchange Commission (SEC) released a final rule, "Modernization of Oil and Gas Reporting," which amended the oil and gas reporting requirements effective January 1, 2010. The key revisions include:

· using a 12-month average price to determine reserves;

· including non-traditional resources in reserves if they are intended to be upgraded to synthetic oil and gas;

· the ability to use reliable technologies to determine and estimate reserves;

· permitting the optional disclosure of probable and possible reserves;

· reporting the independence and qualifications of the reserve preparer or auditor and filing a report as an exhibit when a third party is relied upon to prepare reserve estimates or conduct reserve audits; and

· disclosing the development of any proved undeveloped reserves, including the total quantity of proved undeveloped reserves at year-end, material changes to proved undeveloped reserves during the year, investments and progress toward the development of proved undeveloped reserves and an explanation of the reasons why material concentrations of proved undeveloped reserves have remained undeveloped for five years or more after disclosure as proved undeveloped reserves

In January 2010, the Financial Accounting Standards Board (FASB) issued FASB Accounting Standards Update (ASU) No. 2010-03, "Oil and Gas Reserve Estimations and Disclosures" (ASU 2010-03). ASU 2010-03 aligns the current oil and gas reserve estimation and disclosure requirements of the Extractive Industries - Oil and Gas topic of the FASB Accounting Standards Codification (ASC Topic 932) with the changes required by the SEC final rule, "Modernization of Oil and Gas Reporting." ASU No. 2010-03 must be applied prospectively as a change in accounting principle that is inseparable from a change in accounting estimate and is effective for entities with annual reporting periods ending on or after December 31, 2009.

Oil and Gas Reserves

Users of this information should be aware that the process of estimating quantities of "proved," "proved developed" and "proved undeveloped" crude oil, natural gas liquids and natural gas reserves is complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Although reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

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Proved reserves represent estimated quantities of crude oil, natural gas liquids and natural gas that geoscience and engineering data can estimate, with reasonable certainty, to be economically producible from a given day forward from known reservoirs under economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

On April 14, 2011, the company entered into a general conveyance agreement (the “General Conveyance Agreement”) with Huron Energy Corporation (“Huron”), pursuant to which Huron conveyed to the Company a 6% working interest in the petroleum and natural gas rights, as well as the intangible and miscellaneous interests, (collectively, the “Assets”) in 800 acres of land located in the Leaman area of Alberta, Canada (the “Leaman”).  Under the General and Conveyance Agreement, the Company began receiving its share of oil and gas revenue effective April 1, 2011.

The following tables set forth the Company’s portion of net proved and probable reserves at August 31, 2012 and 2011 and the changes in the net proved and probable reserves for the years ended August 31, 2012 and 2011 on an after-royalty basis,

Net Proved Reserves

All of the Company’s reserves are located in Alberta, Canada.  The Company does not have any proved or probable undeveloped properties nor does it have any possible developed or undeveloped properties.

Crude Oil (Mbbl)

Net proved reserves at August 31, 2010	-
Purchases in place	7.3
Production	(0.4	)
Net proved reserves at  August 31, 2011	6.9
Production	(1.1	)
Revisions of previous estimates	(2.4	)
Net proved reserves at  August 31, 2012	3.4

Gas (MMcf)

Net proved reserves at August 31, 2010	-
Purchases in place	0.8
Production	(0.0	)
Net proved reserves at  August 31, 2011	0.8
Production	(0.2	)
Revisions of previous estimates	(0.2	)
Net proved reserves at  August 31, 2012	0.4

Oil Equivalent (Mboe)

Net proved reserves at August 31, 2010	-
Purchases in place	7.4
Production	(0.4	)
Net proved reserves at  August 31, 2011	7.0
Production	(1.1	)
Revisions of previous estimates	(2.4	)
Net proved reserves at  August 31, 2012	3.5

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Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth the capitalized costs relating to Titan’s crude oil and natural gas producing activities at August 31, 2012 and 2011

	2012			2011
Proved		183,020			153,602
Unproved		262,619			271,995
Total		445,639			425,597
Accumulated depletion		(33,820	)		(8,317	)
Write-down of oil and gas property interests		(130,201	)		-
Net capitalized costs		281,618			417,280

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The acquisition, exploration and development costs disclosed in the following tables are in accordance with definitions in the Extractive Industries - Oil and Gas Topic of the ASC.

·   Acquisition costs include costs incurred to purchase, lease or otherwise acquire property.

·   Exploration costs include additions to exploratory wells, including those in progress, and exploration expenses.

·   Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

	2012		2011
Acquisition Costs of Properties
Proved		31,672		149,325
Unproved		9,376		144,885
Subtotal		41,048		294,210
Exploration costs		-		47,760
Total		41,048		341,970

Results of Operations

The following tables set forth results of operations for oil producing activities for the years ended August 31, 2012 and 2011.  Gas production received by the Company has been negligible to date.

August 31, 2012

Crude oil sales	$	72,444
Production costs		65,597
Depletion and accretion		31,334
Income before income taxes		(24,487	)
Income tax provision		-
Results of operations		(24,487	)

August 31, 2011

Crude oil sales	$	34,593
Production costs		25,414
Depletion and accretion		8,429
Income before income taxes		750
Income tax provision		-
Results of operations		750

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Revenue and Operating Costs Per Barrel

The following table shows the Company’s sales and production costs per barrel for the year ended August 31, 2012 and for the period from acquisition on April 1, 2011 to August 31, 2011.  Gas production received by the Company has been negligible to date.

Year ended August 31, 2012	Production (1)		Sales Price (2)		Operating Costs (3)
	(bbls)		($/bbl)		($/bbl)
		1,050		69		62

1.   Production is the Company’s 6% working interest in Leaman Wells.

2.   Average selling price is calculated based on aggregate gross sales proceeds of $72,444 for the year ended August 31, 2012 divided by barrels of oil sold.

3.   Average operating cost is calculated based on aggregate operating costs of $65,597 for the year ended August 31, 2012 divided by barrels of oil produced.

Period from April 1, 2011 to August 31, 2011	Production (4)		Sales Price (5)		Operating Costs (6)
	(bbls)		($/bbl)		($/bbl)
		401		86		63

4.   Production is the Company’s 6% working interest in Leaman Wells.

5.   Average selling price is calculated based on aggregate gross sales proceeds of $34,593 for the period from April 1, 2011 to August 31, 2011 divided by barrels of oil sold.

6.   Average operating cost is calculated based on aggregate operating costs of $25,414 for the period from April 1, 2011 to August 31, 2011 divided by barrels of oil produced.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by ASC Topic 932 and based on crude oil and natural gas reserves and production volumes estimated by GLJ. The estimates were based on a 12-month average for commodity prices for the years 2012 and 2011. The following information may be useful for certain comparison purposes, but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of crude oil and natural gas reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

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August 31, 2012

Future cash inflows (1)	$	271,000
Future production costs		249,000
Future income taxes		700
Future net cash flows		21,300
Discount to present value at 10% annual rate		(2,300	)
Standardize measure of discounted future net cash flows relating to proved oil and gas reserves		19,000

(1)   Estimated crude oil prices used to calculate 2011 future cash inflows for Canada was $78.45.

August 31, 2011

Future cash inflows (2)	$	648,000
Future production costs		358,000
Future income taxes		99,000
Future net cash flows		191,000
Discount to present value at 10% annual rate		(61,000	)
Standardize measure of discounted future net cash flows relating to proved oil and gas reserves		130,000

(2)   Estimated crude oil prices used to calculate 2011 future cash inflows for Canada was $87.76.

Following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown.

August 31, 2012

Net changes in price, production costs, and development costs	$	(74,000	)
Revisions of previous quantity estimates		(42,000	)
Accretion of discount		5,000
Net decrease		(111,000	)
Standardized measure at September 1, 2011		130,000
Standardize measure at August 31, 2012		19,000

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Item 9.                         Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None

Item 9A.   Controls and Procedures

DISCLOSURE CONTROLS AND PROCEDURES

The Company’s management, including its chief executive officer and chief financial officer, carried out an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of August 31, 2012, being the date of the Company’s most recently completed fiscal year end. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Exchange Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon our evaluation, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective, as of August 31, 2012, in ensuring that material information that we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. As defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, internal control over financial reporting is a process designed by, or under the supervision of, a company’s principal executive and principal financial officers, and effected by a company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles..

The Company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records, that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of the Company’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of August 31, 2012. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission( “COSO”) in Internal Control - Integrated Framework. Based on the Company’s assessment, our management has concluded that, as of August 31, 2012, the Company’s internal control over financial reporting was effective based upon the COSO criteria.

Lack of Segregation Of Duties

Management is aware that there is a lack of segregation of duties at the Company due to the small number of employees dealing with general administrative and financial matters. However, at this time management has decided that considering the abilities of the employees now involved and the control procedures in place, the risks associated with such lack of segregation are low and the potential benefits of adding employees to clearly segregate duties do not justify the substantial expenses associated with such increases. Management will periodically reevaluate this situation.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the SEC that permit the Company to provide only management’s report in this annual report.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in our internal controls over financial reporting during our fourth fiscal quarter for the fiscal year ended August 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.   Other Information

None

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PART III

Item 10.   Directors, Executive Officers and Corporate Governance

Directors and Executive Officers

All directors of our Company hold office for one-year terms until the next annual meeting of stockholders and until their successors are elected and qualified. The officers of our Company are appointed by, and serve at the discretion of, our board of directors and hold office until their earlier death, retirement, resignation or removal.

The following table sets forth the names, ages, and positions of our current directors and executive officers.

Name	Position Held with the Company	Age	Date First Appointed
Michal Gnitecki	Chairman, President, Chief  Executive Officer, Chief Operating Officer, Secretary, Treasurer, and Director	32	October 2, 2012
Vivek Warrier	Director	38	March 26, 2010

Business Experience

The following is a brief account of the education and business experience of each of our directors and executive officers during at least the past five years.

Michal Gnitecki is an experienced, Alberta-based, petroleum geologist.  Since November 2010 Mr. Gnitecki has been working as a Project Manager for PHH Arc Environmental in Calgary, Alberta.  From September 2008 to October 2010 he was a Project Manager at Adler Environmental Solutions, from January 2007 to August 2008 he was an Environmental Geologist at Cirrus Environmental Services, and from June 2004 to December 2006 he was a Geotechnical Technologist at AMEC Earth and Environmental.  Since April 2, 2012 Mr. Gnitecki has also served as Secretary and Director of Buckeye Oil & Gas, Inc. which is an exploration stage oil and gas exploration company listed on the OTC:BB.  Mr. Gnitecki graduated from Brandon University in Manitoba, Canada with a Bachelor of Science – Geology in 2004.  Mr. Gnitecki was appointed to his positions with the Company due to his industry experience.

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Vivek Warrier has been a partner with the law firm of Bennett Jones in Calgary, Alberta since 2009 and has been with the firm since 2000.  His practice focuses on the development, acquisition and divestiture of energy-related projects both in Canada and abroad. He regularly represents clients in the negotiation, conduct and completion of purchase and sale transactions in respect of upstream, midstream and transportation assets. In addition, he frequently advises clients in the structuring, construction, ownership and operation of energy infrastructure projects, including exploration, production, upgrading, processing, transportation, terminalling, storage and wind power facilities. He also advises clients on all types of contractual issues arising from construction, procurement, participation, joint operating and service-related agreements.  Mr. Warrier sits on the executive of the Natural Resources subsection of the Canadian Bar Association and is extensively involved in the Calgary community, including as a member of the board of directors of the Distress Centre Calgary.  He obtained a Bachelor of Arts degree from the University of Calgary in 1996 and his LLB from the University of Alberta in 2000. Mr. Warrier was appointed to the Board of Directors due to his experience in the oil and gas industry.

There are no family relationships among our directors or officers.  None of our directors or officers has been affiliated with any company that has filed for bankruptcy within the last ten years.  We are not aware of any proceedings to which any of our officers or directors, or any associate of any such officer or director is a party adverse to our company or has a material interest adverse to it.  Other than described  below, we have not compensated our directors for service on our Board of Directors, any committee thereof, or reimbursed for expenses incurred for attendance at meetings of our Board of Directors and/or any committee of our Board of Directors.

Audit Committee Financial Expert

The Board of Directors has not established an audit committee and does not have an audit committee financial expert. The Board is seeking additional Board members whom it hopes will qualify as such an expert.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires officers and Directors of the Company and persons who own more than ten percent of a registered class of the Company’s equity securities to file reports of ownership and changes in their ownership with the Securities and Exchange Commission, and forward copies of such filings to the Company.  We believe, based solely on our review of the copies of such forms, that during the fiscal year ended August 31, 2012, all reporting persons complied with all applicable Section 16(a) filing requirements.

Code of Ethics

The Company has not adopted a Code of Ethics, as defined by SEC rules that applies to the Company's Chief Executive Officer and Chief Financial Officer, and Secretary (its principal executive officer and principal accounting and financial officer). The Company has not adopted such a Code of Ethics because of the small size and limited resources of the Company, and because management's attention has been focused on matters pertaining to raising capital and the operation of the business.

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Potential Conflicts of Interest

Since we do not have an audit or compensation committee comprised of independent directors, the functions that would have been performed by such committees are performed by our directors. The Board of Directors has not established an audit committee and does not have an audit committee financial expert, nor has the Board established a nominating committee. The Board is of the opinion that such committees are not necessary since the Company has only three directors, and to date, such directors have been performing the functions of such committees. Thus, there is a potential conflict of interest in that our directors and officers have the authority to determine issues concerning management compensation, nominations, and audit issues that may affect management decisions. We are not aware of any other conflicts of interest with any of our executive officers or directors.

Involvement in Certain Legal Proceedings

There are no legal proceedings that have occurred within the past ten years concerning our directors, or control persons which involved a criminal conviction, a criminal proceeding, an administrative or civil proceeding limiting one's participation in the securities or banking industries, or a finding of securities or commodities law violations.

Changes to Procedures for Recommendations of Director Nominees

During the fiscal year ended August 31, 2012, there were no material changes to the procedures by which security holders may recommend nominees to our board of directors.

Item 11.   Executive Compensation

Summary Compensation Table

The table below sets forth information concerning compensation paid, earned or accrued by our chief executive officers (each a “Named Executive Officer”) for the last two fiscal years. No executive officer earned compensation in excess of $100,000 during our 2012 or 2011 fiscal year.

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SUMMARY COMPENSATION TABLE

										Non-Equity		Nonqualified		All
Name and						Stock		Option		Incentive Plan		Deferred		Other
Principal		Salary		Bonus		Awards		Awards		Compensation		Compensation		Compensation		Total
Position	Year	($)		($)		($)		($)		($)		Earnings ($)		($)		($)
Jack Adams	2012		7,500		0		0		0		0		0		0		7,500
President, Chief Executive Officer (1)	2011		6,000		0		0		0		0		0		0		6,000
											0
Jarnail Dhaddey President and Chief Executive Officer (2)	2012 2011		15,000 15,000		0 0		0 0		0 0		0 0		0 0		0 0		15,000 15,000

(1)   During the fiscal year ended August 31, 2012  Jack Adams was our President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director. He was appointed to his positions of President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary and Treasurer on January 20, 2012.   Prior to his appointment on January 20, 2012 Mr. Adams served as a director of the Company since August 1, 2010.  He resigned from all of his positions with the Company on October 1, 2012.  While serving as a director in 2011 he was paid $500 per month for total compensation of $6,000.  Commencing March 1, 2012 he began being paid $750 per month to serve as an officer of the Company.  His compensation for 2012 consisted of $4,500 for six months while he was the sole executive officer of the Company and $3,000 for the six months he served as a director only.  On October 2, 2012 Michal Gnitecki was appointed President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director of the Company.

(2)   During the fiscal year ended August 31, 2011, Jarnail Dhaddey was our President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director. On January 20, 2012 Mr. Dhaddey resigned from all of his positions with the Company. Mr. Dhaddey’s compensation for 2012 and 2011 represents management fees paid during each respective fiscal year.  Mr. Dhaddey did not have an employment agreement with the Company but was paid management fees from time-to-time.

Since inception, we have not paid compensation exceeding $100,000 per year to any of our executive officers.

Service Agreements

Effective as of October 2, 2012 the Company and Michal Gnitecki entered into service agreement to serve as the Company’s President, Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Secretary, Treasurer and Director of the Company.  Mr. Gnitecki will be paid $750 per month to serve as a director and officer of the Company.

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Outstanding Equity Awards

Outstanding Equity Awards at Fiscal Year-End

The following table summarizes the outstanding equity awards to our Named Executive Officers as of August 31, 2012:

	Option Awards
Name	Number of
	Securities	Securities
	Underlying	Underlying
	Unexercised	Unexercised	Option	Option
	Options	Options	Exercise	Expiration
	Exercisable	Unexercisable	Price	Date
Jarnail Dhaddey	150,000	100,000	$1.30	December 10, 2015

(1) Such options vest as to 50,000 shares subject to the option on December 10, 2010, the date of grant, and vest as to 100,000 shares subject to the option on each of December 10, 2011 and 2012.

Compensation of Directors

The following table summarizes the compensation awarded during the fiscal year ended August 31, 2012 to our directors:

Name (a)	Year	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)	Total ($)
Vivek Warrier	2012	6,000	0	0	0	0	0	6,000
	2011	6,000	0	0	0	0	0	6,000

The Company pays Vivek Warrier and Jack Adams $500 per month to serve on its Board of Directors.

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Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table lists, as of November 29, 2012, the number of shares of common stock of the Company beneficially owned by (i) each person or entity known to the Company to be the beneficial owner of more than 5% of the outstanding common stock; (ii) each officer and director of the Company; and (iii) all officers and directors as a group. Information relating to beneficial ownership of common stock by our principal stockholders and management is based upon information furnished by each person using “beneficial ownership” concepts under the rules of the Securities and Exchange Commission. Under these rules, a person is deemed to be a beneficial owner of a security if that person has or shares voting power, which includes the power to vote or direct the voting of the security, or investment power, which includes the power to dispose or direct the disposition of the security. The person is also deemed to be a beneficial owner of any security of which that person has a right to acquire beneficial ownership within 60 days. Under the Securities and Exchange Commission rules, more than one person may be deemed to be a beneficial owner of the same securities, and a person may be deemed to be a beneficial owner of securities as to which he or she may not have any pecuniary beneficial interest. Except as noted below, each person has sole voting and investment power.

The percentages below are calculated based on 54,227,000 shares of common stock which are issued and outstanding as of November 29, 2012.  Unless indicated otherwise, each person’s addresses below is c/o Titan Oil & Gas, Inc., 7251 West Lake Mead Boulevard, Suite 300, Las Vegas, Nevada, 89128.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership	Percentage of Class
Depinder Grewal(1)	36,000,000	66.4%
Jarnail Dhaddey  (2)	250,000(2)	0.5%
Vivek Warrier	-	-
Michal Gnitecki	-	-
Directors and executive officers as a group (2 individuals)	250,000	0.5%

(1)   Mr. Grewal resigned as an executive officer and director of our company on September 13, 2010.

(2)   Represents shares of common stock issuable upon the exercise of options that are currently exercisable or exercisable within 60 days. Mr. Dhaddey resigned as an officer and director of the Company on January 20, 2012.

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Item 13.   Certain Relationships and Related Transactions, and Director Independence

Related Party Transactions

On February 16, 2011 the Company sold its interest in the Saskatchewan Leases to Westpoint for total proceeds of $15,000. Jarnail Dhaddey, the former President and Chief Executive Officer of the Company is also the President and Chief Executive Officer of Westpoint.  In addition, Jack Adams was a member of the Board of Directors of the Company and of Westpoint at the time of the transaction.  Mr. Adams has since resigned all of his positions with the Company and Westpoint.

On December 10, 2010 the Company granted 250,000 stock options at an exercise price of $1.30 to Jarnail Dhaddey, the Company’s former principal executive officer.  The options vest as to 50,000 shares subject to the option on December 10, 2010, the date of grant, and vest as to 100,000 shares subject to the option on each of December 10, 2011 and 2012.  The stock options expire on December 10, 2015.

Director Independence

We are not subject to the listing requirements of any national securities exchange or national securities association and, as a result, we are not at this time required to have our board comprised of a majority of “independent directors.” We do not believe that any of our directors currently meet the definition of “independent” as promulgated by the rules and regulations of the American Stock Exchange.

Item 14.   Principal Accounting Fees and Services

On March 2, 2010, the Company named Robison, Hill & Co. as its principal independent accountants.  Fees billed to the Company for the fiscal years ending August 31, 2012 and 2011 are set forth below:

	Fiscal year ending August 31, 2012		Fiscal year ending August 31, 2011
Audit Fees (1)	$	15,000	$	15,000
Audit Related Fees		0		0
Tax Fees		0		0
All Other Fees		0		0

(1)Audit fees relate to professional services rendered in connection with the audit of the Company’s annual financial statements and internal control over financial reporting and quarterly review of financial statements included in the Company’s Quarterly Reports on Form 10-Q.

As of August 31, 2012, the Company did not have a formal, documented pre-approval policy for the fees of the principal accountant. It is in the process of adopting such a policy.

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PART IV

Item 15.   Exhibits and Financial Schedules

EXHIBIT NUMBER	DESCRIPTION
3.1	Certificate of Incorporation of Registrant. (1)
3.2	By-Laws of Registrant. (1)
4.1	Form of stock certificate. (1)
10.1	Form of Regulation S Subscription Agreement (1)
10.2	Sale and Conveyance Agreement dated April 12, 2010 by and between Titan Oil & Gas, Inc. and 966749 Alberta Corp. (2)
10.3	Form of Regulation S Subscription Agreement (2)
10.4	2010 Stock Option Plan (3)
10.5	Form of Regulation S Subscription Agreement (4)
10.6	Form of Regulation S Subscription Agreement (5)
10.7	Form of Regulation S Subscription Agreement (6
10.8	Sale and Conveyance Agreement dated February 16, 2011 by and between Westpoint Energy, Inc. and the Company (7)
10.9	General Conveyance Agreement dated April 14, 2011 by and between Huron Energy Corporation and the Company (8)
10.10	Service Agreement dated October 2, 2012 by and between Titan Oil & Gas, Inc. and Michal Gnitecki (9)
99.1	Reserve Report dated November 8, 2011 prepared by GLJ Petroleum Consultants (10)
99.2	Reserve Report dated November 23, 2012 prepared by GLJ Petroleum Consultants
21	List of Subsidiaries
31	Rule 13a-14(a)/15d14(a) Certifications (attached hereto)
32	Section 1350 Certifications (attached hereto)

(1) Previously filed as an Exhibit to a Registration Statement, filed with the Securities and Exchange Commission on October 1, 2008, file no. 333-153762

(2) Previously filed as Exhibits 10.1 and 10.2 to the Company’s Form 8-K submitted to the SEC on April 14, 2010.

(3) Previously filed as Exhibit 10.1 with the Company’s Form 8-K submitted to the SEC on August 6, 2010.

(4) Previously filed as Exhibit 10.1 with the Company’s Form 8-K submitted to the SEC on August 24, 2010.

(5) Previously filed as Exhibit 10.1 with the Company’s Form 8-K submitted to the SEC on September 13, 2010.

(6) Previously filed as Exhibit 10.1 with the Company’s Form 8-K submitted to the SEC on January 10, 2011.

(7) Previously filed as Exhibit 10.1 with the Company’s Form 8-K submitted to the SEC on February 23, 2011.

(8) Previously filed as Exhibit 10.1 with the Company’s Form 8-K submitted to the SEC on April 19, 2011.

(9) Previously filed as 10.1 with the Company’s Form 8-K submitted to the SEC on October 5, 2012.

(10) Previously filed as Exhibit 99.1 with the Company’s Form 10-K submitted to the SEC on November 29, 2011.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

TITAN OIL & GAS, INC.
Dated: November 29, 2012	By:                /s/ Michal Gnitecki
	Name:                Michal Gnitecki
	Title:                President, Chief Executive and Financial Officer, Secretary, Treasurer, and Director (Principal Executive, Financial and Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

SIGNATURE	TITLE	DATE
/s/Michal Gnitecki Michal Gnitecki	Director, President, Chief Executive and Financial Officer, Secretary, Treasurer, and Director (Principal Executive, Financial, and Accounting Officer)	November 29, 2012
/s/ Vivek Warrier Vivek Warrier	Director	November 29, 2012